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Paramount Resources Ltd. Announces Third Quarter 2017 Results; 2018 Production and Capital Guidance; October 2017 Sales Volumes Exceed 98,000 Boe/d

CALGARY, Nov. 9, 2017 (Canada NewsWire via COMTEX) --

OIL AND GAS OPERATIONS

    --  Paramount completed two major transactions in the third quarter
        of 2017, acquiring Apache Canada Ltd. (?Apache Canada?) in
        August and completing a merger with Trilogy Energy Corp.
        (?Trilogy?) in September.

    --  During October 2017, the first full month of operations for the
        combined entities, Paramount's estimated sales volumes averaged
        over 98,000 Boe/d (38 percent Liquids).

    --  Average sales volumes for the fourth quarter are expected to
        exceed 95,000 Boe/d, with greater than 38 percent Liquids
        volumes.

    --  Paramount's third quarter 2017 sales volumes averaged 49,023
        Boe/d (40 percent Liquids).

    --  In the Grande Prairie Region, the 2016/17 Karr-Gold Creek
        capital program is wrapping up with the the final six wells of
        the 27-well Montney program scheduled to be completed and
        brought on production before year-end 2017. Paramount expects
        fourth quarter production from the Grande Prairie Region to
        exceed 35,000 Boe/d (approximately 50 percent Liquids).

    --  In the Kaybob Region, a total of seven wells were rig released
        and twelve wells were completed in the third quarter of 2017,
        including the completion and tie-in of a six (3.1 net) well pad
        at Kaybob South Duvernay in September. The Company expects
        fourth quarter production from the Kaybob Region to exceed
        40,000 Boe/d (approximately 33 percent Liquids).

    --  The Central Alberta and Other Region includes assets and
        production in the Northwest Territories, northeast British
        Columbia, northwest Alberta, and central Alberta. Drilling and
        completion activity in the Region during the third quarter took
        place at the Birch joint-venture in northeast British Columbia.
        Paramount expects fourth quarter production from the Central
        and Other Region to be approximately 20,000 Boe/d (30 percent
        Liquids).

    --  Capital expenditures in the third quarter of 2017 totaled
        $122.0 million. The majority of the capital spending was
        directed towards the Karr-Gold Creek Montney development
        program in the Grande Prairie Region.


CORPORATE

    --  Paramount's revolving bank credit facility (the ?Facility?) was
        increased from $300 million to $700 million in November 2017.
        At Paramount's request, the size of the Facility can be further
        increased by $300 million to $1.0 billion.

    --  Approximately $315 million was drawn on the Facility as of
        November 6, 2017.

    --  Trilogy's $285 million bank credit facility has been repaid and
        cancelled.

    --  Third quarter 2017 funds flow from operations totaled $45.3
        million compared to $3.8 million in the third quarter of 2016.

    --  Transition efforts are in full swing with a management team
        comprised of representation from all three companies. The
        Company has reorganized into three operating regions while also
        creating discipline-based leadership roles to facilitate
        project execution and best practices and to ensure integration
        across the organization.

    --  Since October 1, 2017, Paramount has entered into hedges for
        10,000 Bbl/d of Liquids for 2018 at an average WTI price of
        C$69.84/Bbl. For the remainder of 2017, the Company has 4,000
        Bbl/d of Liquids hedged at an average WTI price of C$70.80/Bbl
        and 2,000 Bbl/d hedged at a WTI price of US$54.48/Bbl.

    --  The Company has secured firm service transportation capacity
        for approximately 60,000 GJ/d of natural gas for delivery to
        the Dawn natural gas hub in Ontario for sale to eastern natural
        gas markets.


OIL AND GAS OPERATIONS

In the third quarter of 2017 sales volumes averaged 49,023 Boe/d, including 40 percent Liquids volumes. This includes 46 days of production from the Apache Canada assets and 19 days of production from the Trilogy assets. For the full month of October, the Company's estimated monthly sales averaged over 98,000 Boe/d, including approximately 38 percent Liquids volumes. Average sales volumes for the fourth quarter of 2017 are expected to exceed 95,000 Boe/d, with 38 percent Liquids volumes.

Capital expenditures for the Company in the third quarter of 2017 were $122.0 million. Paramount estimates approximately $130 million of capital will be spent in the fourth quarter, bringing total projected annual spending for 2017 to approximately $510 million, excluding land and property acquisitions.

Following the acquisition of Apache Canada (the ?Apache Canada Acquisition?) and the merger with Trilogy (the ?Trilogy Merger?), Paramount has divided its oil and gas operating areas into three operating regions: i) the Grande Prairie Region; ii) the Kaybob Region and iii) the Central Alberta and Other Region.

In the third quarter of 2017 the combined entities rig released 11 wells, completed 16 wells, and had 12 wells in the process of being completed.

Grande Prairie Region

The focus within the Grande Prairie Region is the over-pressure liquids-rich Deep Basin Montney trend. In the third quarter Paramount added approximately 45,000 net acres to its land position through the Apache Canada Acquisition and increased its total land holding to approximately 147,000 net acres. In addition, the Company has a material position of Deep Basin Cretaceous rights of approximately 150,000 net effective acres targeting the Dunvegan, Falher, Gething and Wilrich formations.

Production for the quarter averaged 24,000 Boe/d with approximately 50 percent Liquids, despite a 20-day planned outage at a third-party gas processing plant. Paramount expects fourth quarter production from the Grande Prairie Region to continue to exceed 35,000 Boe/d, comprised of approximately 50 percent Liquids.

During the third quarter, a total of four wells were rig released, four wells were completed and brought on production, and 12 wells were in the process of being completed and brought on production.

The 2016/17 Karr Montney capital program is wrapping up with six wells in-progress and scheduled to be on production before year-end 2017. This will complete the successful 27 (27.0 net) well program, which delivered average sales volumes of around 26,600 Boe/d in October 2017, including approximately 52 percent Liquids volumes. Peak wellhead throughput in the month of October reached 30,500 Boe/d, with approximately 55 percent Liquids volumes.

The table below summarizes the average peak 30-day initial wellhead production rates for 21 of the 27 wells in the 2016/17 Karr Montney capital program:


    Well                      Pad Peak 30 Day    Peak 30 Day  % Condensate      Days on

                                    Total (1) Condensate (1)                 Production

                                      (Boe/d)        (Bbl/d)
    ---                               -------        -------

    00/15-14-065-06W6/0 15-02           2,628           1,340             51           307

    00/04-07-065-05W6/0 04-19           2,550           1,815             71           266

    02/04-07-065-05W6/0 04-19           2,844           2,176             77           238

    02/01-12-065-06W6/0 04-19           2,633           1,795             68           229

    00/03-22-066-05W6/0 03-22           1,949             946             49           203

    00/01-12-065-06W6/0 04-19           2,218           1,532             69           196

    00/09-32-065-04W6/0 16-36           2,159           1,401             65           158

    00/16-32-065/04W6/0 16-36           2,122           1,263             60           143

    00/04-34-065-05W6/0 16-04           2,137             994             47           132

    00/01-33-065-05W6/0 16-04           1,912             805             42           127

    00/08-32-065-04W6/0 16-36           1,856           1,176             63           119

    02/16-24-066-05W6/0 13-07           1,341             694             52            94

    00/04-06-066-04W6/0 13-07           1,815             900             50            93

    02/04-06-066-04W6/0 13-07           2,050           1,414             69            91

    00/16-24-066-05W6/0 13-07           1,352             647             48            91

    00/03-06-066-04W6/0 13-07           1,839             942             51            89

    02/09-32-065-04W6/0 16-36           1,529             950             62            80

    00/13-14-065-06W6/0 15-02           1,723           1,072             62            56

    02/16-14-065-06W6/0 15-02           2,018           1,346             67            48

    02/14-14-065-06W6/0 15-02           1,702           1,003             59            30

    02/15-14-065-06W6/0 15-02           1,855           1,270             67            30
    ------------------- -----           -----           -----            ---           ---

    Average                             2,011           1,212             59           134
    =======                             =====           =====            ===           ===

             (1)    Peak 30 Day is the highest daily
                     average production rate over a
                     30-day consecutive period for an
                     individual well, measured at the
                     wellhead. Natural gas sales
                     volumes are approximately 10
                     percent lower and stabilized
                     condensate sales volumes are
                     approximately 15 percent lower
                     due to shrinkage. 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.

Drilling costs for the 21 wells averaged $3.7 million per well ($622 per meter of total depth or $1,281 per meter of lateral length) and completion costs averaged $7.1 million per well ($103,000 per stage or $1,032 per tonne of proppant placed). Paramount increased the number of average fracs pumped per day from about five on the 04-19 pad to an average of more than 10 per day on the most recent pad, with as many as 17 frac stages pumped in a single 24-hour period.

The Karr 06-18 compression and dehydration facility (the ?06-18 Facility?) produces to a nearby third party sour gas processing plant where Paramount has firm natural gas transportation on TCPL and downstream contracts for our condensate and NGLs volumes.

The 2016/17 delineation and land tenure program at the Wapiti Montney property is nearly complete, with two wells rig released and one well completed and tested in the third quarter of 2017. To date, the property has been delineated with nine wells that have tested three landing zones in the Middle and Lower Montney. A new third party sour gas processing plant, trunk lines, and compression nodes are at various stages of engineering, procurement and construction, with the first 150 MMcf/d of sour gas processing capacity scheduled to be commissioned in the spring of 2019.

In the Resthaven/Jayar area, the 2016/17 program of five (4.5 net) Cretaceous wells and one (1.0 net) Montney well is near completion. In the third quarter, one well was rig released, four wells were completed and put on production, and one well is in the process of being completed, tested and brought on production.

The Montney well at Resthaven was drilled, completed and tied-in during the third quarter with encouraging results. This Montney well was completed with a similar design to those of the Karr Montney program and had a completed length of approximately 2,700 meters with 70 x 100 tonne frac stages for proppant loading intensity of about 2.6 tonnes per meter. The well continues to flow on cleanup and has achieved an initial 30-day production rate of approximately 1,314 Boe/d at the wellhead, about 33 percent condensate. Wellhead production rates over the first 30 days have increased day-over-day with the 30th day delivering approximately 1,780 Boe/d with 34 percent condensate. The Company plans to closely monitor the well's longer-term performance and may accelerate the development of the Montney in this area.

All of the new Resthaven/Jayar production is being processed either in the 300 MMcf/d Pembina 08-11 deep cut gas plant where Paramount holds a 16 percent interest (54 MMcf/d net capacity), or the Resthaven 01-36 gas plant, where Paramount holds a 50 percent interest (10 MMcf/d net capacity). Paramount has firm service natural gas transportation on TCPL and downstream contracts for condensate and NGLs to handle egress for production from the Resthaven/Jayar area.

Kaybob Region

The focus in the Kaybob Region is Montney oil at Kaybob and Ante Creek, Montney gas at Presley, liquids-rich Duvernay at Kaybob South and Smoky River and Gething oil. Paramount has added about 900,000 net acres of land at Kaybob as a result of the Apache Canada Acquisition and the Trilogy Merger, including approximately 88,000 net acres of tier one Montney oil acreage, 122,000 net acres of liquids-rich Montney gas, and 136,000 net acres of Duvernay rights, more than half of which are in the liquids-rich trends. In addition to these Montney and Duvernay land positions, Paramount added additional acreage in stacked Cretaceous plays within the Deep Basin at Kaybob.

Through the Apache Canada Acquisition and the Trilogy Merger, Paramount also added strategically owned and operated facilities including six natural gas processing plants and three oil batteries. The natural gas processing capacity totals greater than 150 MMcf/d and the oil batteries can process more than 40,000 Bbl/d of liquids.

During the third quarter, a total of seven wells were rig released and 12 wells completed in the Kaybob Region, including a six-well pad at Kaybob South Duvernay which tested completion intensities up to 4.5 tonnes per meter. Production for the Kaybob Region in the third quarter averaged approximately 13,500 Boe/d, approximately 31 percent Liquids volumes. Paramount expects fourth quarter 2017 production from the Kaybob Region to exceed 40,000 Boe/d, with about 33 percent Liquids volumes.

The Company has implemented a new completion design in the Kaybob Montney oil pool which on average has 45 percent more stages and 290 percent higher proppant loading than the original wells. The table below summarizes the average peak 30-day initial wellhead rates for wells with the new completion design.


    Well                Peak 30 Day Peak 30 Day  % Oil      Days on

                          Total (1)     Oil (1)          Production

                            (Boe/d)     (Bbl/d)
    ---                     -------     -------

    02/05-06-064-18W5/0       2,301        1,928      84           299

    03/04-06-064-18W5/0       1,059          759      72           298

    02/04-06-064-18W5/0       1,202        1,082      90           270

    00/13-31-064-18W5/0       1,174          990      84           210

    02/13-31-064-18W5/0         811          605      75           208

    00/14-31-064-18W5/0         756          578      76           208

    00/14-12-064-19W5/2         539          475      88           198

    02/15-12-064-19W5/0         683          587      86           195

    03/15-12-064-19W5/0         754          620      82           157

    02/08-05-064-18W5/0       1,007          929      92           137

    03/09-05-064-18W5/0         815          758      93           136

    02/08-29-064-18W5/0       1,573          599      38           114
    -------------------       -----          ---     ---           ---

    Average                   1,056          826      80           203
    =======                   =====          ===     ===           ===

             (1)    Peak 30 Day is the highest daily
                     average production rate over a 30
                     day consecutive period for an
                     individual well, measured at the
                     wellhead. Natural gas sales
                     volumes are approximately 10
                     percent lower and stabilized oil
                     sales volumes are approximately
                     15 percent lower due to
                     shrinkage. 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.

Drilling costs for the 17 wells that were completed in the Kaybob Region averaged $1.7 million per well ($440 per meter of total depth or $926 per meter of lateral length), with completion costs averaging $0.9 million per well ($29,233 per stage or $1,500 per tonne of proppant placed). Paramount will continue to operate a drilling rig through the fourth quarter on this play.

The Kaybob Montney oil asset produces through owned and operated sour natural gas processing and oil handling facilities that are coupled with firm transportation for the solution gas and downstream contracts for oil and NGLs volumes. The facilities are dually connected to both the TCPL and Alliance systems for natural gas volumes and the Pembina gathering system for crude oil.

During the quarter, the Company brought on a new six-well pad on its Kaybob South Duvernay lands and is excited by the results. The wells on this pad had an average daily wellhead production rate of approximately 1,600 Boe/d per well with about 51 percent condensate volumes over their first 30 days of production. The production rates from this new pad are over a brief period of time and not necessarily indicative of the long-term performance. The average drill cost was $4.6 million per well ($842 per meter of total depth or $2,030 per meter of lateral length) and the average completion cost was $6.0 million per well ($147,000 per stage or $711 per tonne of proppant placed). The six-well pad tested two proppant loading intensities at approximately 55-meter stage spacing and the Company is currently evaluating the results to determine the optimal proppant loading intensity.

The Kaybob South Duvernay asset produces through third party facilities under firm agreements, again coupled with firm transportation for natural gas and downstream contracts for condensate and NGLs volumes.

Central Alberta and Other Region

The Central Alberta and Other Region includes assets and production in the Northwest Territories, northeast British Columbia, northwest Alberta, and central Alberta. There are a number of material land and resource positions in the region including Willesden Green and East Shale Basin Duvernay. The following table summarizes the noteworthy positions in the region:


    Description               Approximate Net Acres
    -----------               ---------------------

    Willesden Green Duvernay                         63,000

    East Shale Basin Duvernay                        30,000

    Fee Simple Lands                                176,000

    Cardium                                         187,000

    Glauconite                                       76,000

    Ellerslie                                        95,000
    ---------                                        ------

During the third quarter, drilling and completion activity in the Central Alberta and Other Region took place at the non-operated Birch joint-venture lands in northeast British Columbia.

Production for the region for the third quarter averaged about 11,000 Boe/d (28 percent Liquids). Paramount expects fourth quarter 2017 production from the Central Alberta and Other Region to be approximately 20,000 Boe/d with approximately 30 percent Liquids.

2018 GUIDANCE AND OUTLOOK

Paramount's 2018 capital budget is focused on liquids-rich growth opportunities while maintaining a strong balance sheet. Paramount expects sales volumes to average approximately 100,000 Boe/d in 2018, including 40 percent Liquids volumes. The Company's sales volumes are expected to remain at this level until production at Wapiti begins to ramp up in the spring of 2019 when 150 MMcf/d of new third-party gas processing capacity is scheduled to come on-stream.

Capital expenditures for 2018 are expected to be approximately $600 million including maintenance, optimization and exploration expenses, excluding acquisitions or divestitures. In addition, the Company intends to spend approximately $28 million on abandonment and suspension activities in 2018.

Approximately 50 percent of the $130 million of capital expenditures the Company expects to incur in the fourth quarter of 2017 are related to the planned 2018 development program and include lease construction, drilling operations and ordering of long-lead items.

The 2018 capital allocation is expected to be as follows: 68 percent liquids-rich Montney, 23 percent liquids-rich Duvernay, six percent for maintenance/optimization projects and three percent for other liquids-rich projects. Capital allocation by region is forecast to be about 54 percent Grande Prairie, 36 percent Kaybob and 10 percent Central/Other.

In 2018 the Company plans to drill between 70 and 75 net development wells and complete up to 55 of those net wells. The 55 net well completions will account for about 13 percent of Paramount's proved plus probable booked undeveloped locations (as at June 1, 2017). As the Company furthers the development of its plays, additional locations will be added to Paramount's reserves.

At an average drilling duration of 30 days and 270 operating days per year per drilling rig, Paramount's wholly-owned Fox Drilling fleet of seven rigs can accommodate approximately 1,900 of the up to 2,500 drilling days that may be required for these development wells. The remaining drilling days will be contracted out based on cost of service, availability, reliability and functionality of equipment.

In 2016/17 Paramount contracted pumping services for extended periods of up to 12 months, and plans to employ the same strategy in 2018 to ensure access to quality crews, equipment, and materials. Paramount has a water management team and greater than five million barrels of existing fresh water storage capacity in Wapiti, Karr and Kaybob.

During the period from late-2016 through to the present, Paramount has seen between 10 and 15 percent cost inflation in drilling and completion activities. These increases have been included in future development planning with any additional cost inflation anticipated to be offset by savings due to multi-well pad drilling, fresh water storage and economies of scale from the combined businesses.

For budgeting and planning purposes, Paramount uses constant prices and costs with US$50/Bbl WTI, US$3.00/MMbtu NYMEX, US$1.00/MMbtu AECO basis, and a foreign exchange rate of 1.25 Canadian dollars per US dollar. Operating costs through the 2018 period are estimated to be approximately $10.00 per Boe. Transportation costs are expected to average $3.10 per Boe with royalties of approximately $1.65 per Boe. Operating costs per Boe and general and administrative costs are expected to decline in the fourth quarter of 2018 as optimization and synergistic benefits start to be realized.

Paramount expects to fund the portion of its 2018 budgeted capital expenditures that are in excess of cash flow through non-core asset divestitures and by drawings on the Company's expanded bank credit facility.

Paramount has a portfolio of very profitable projects and intends to invest in these while maintaining financial strength and flexibility. This will provide the Company with the flexibility to accelerate capital investments should macro conditions continue to improve.

2018 Capital Program By Property

Wapiti Montney

In 2018 the Company will allocate about 25 percent of the capital program to the Wapiti Montney asset in the form of drilling, completions, water management, land tenure, and geological studies. A 24-well drilling campaign (100 percent working interest) will be kicked off with most of the well completions to follow in early 2019 to align with the commissioning and startup of the first phase of the third-party Wapiti gas plant.

The Wapiti gas plant, trunk line connecting the east and west blocks and compression nodes are in various stages of engineering, procurement and construction with an anticipated onstream date in the spring of 2019 as per the third party schedule. This third-party infrastructure is complimented by a Leduc water disposal scheme which Paramount will commence drilling the first of a series of water disposal wells in 2018.

Paramount has firm natural gas transportation on TCPL which ramps up from 50 MMcf/d in 2019 to 130 MMcf/d in early 2021 with the potential to accelerate these volumes should Paramount choose to do so.

Karr Montney

The Karr Montney asset is expected to be allocated approximately 27 percent of the 2018 capital program in the form of drilling, completions, optimizations and facility expansions. Paramount plans to expand the existing 06-18 Facility from its current 80 MMcf/d throughput capacity to about 100 MMcf/d of capacity in the latter half of 2018. The 2018 program will see about 15 wells drilled (five to be spud in the fourth quarter of 2017) and up to 10 wells completed. Paramount has a 100 percent working interest in the wells in the 2018 program.

In addition to expanding the existing 06-18 Facility from 80 to 100 MMcf/d, the Company has kicked off front-end engineering design and site clearing on a 50 MMcf/d expansion, which will see Karr achieve throughput capacity of 150 MMcf/d in 2020. This new owned and operated facility is being designed to allow for a further 50 MMcf/d expansion, which would bring total owned and contracted natural gas processing at Karr to 200 MMcf/d. Firm transportation with TCPL is in place to achieve the goal of 150 MMcf/d of throughput capacity by the third quarter of 2020.

Kaybob Montney Oil

Approximately 13 percent of the 2018 capital program has been assigned to the Kaybob Montney oil asset. This will consist of drilling, completions, optimizations and infield infrastructure projects to handle growth in oil production from the current 6,000 Bbl/d to approximately 8,000 Bbl/d. The 2018 program will see about 22 new wells (100 percent working interest) drilled and completed, plus an additional five completions from late-2017 drills.

The solution gas from the asset is produced into Paramount's operated Kaybob North 08-09 gas plant (the ?08-09 Plant?) where firm natural gas transportation is secured with TCPL. The gas plant is dually connected to both TCPL and Alliance, providing for future optionality.

Oil emulsion is treated at Paramount's owned and operated 12-10 oil battery with capacity of 20,000 Bbl/d, which is pipeline connected to Pembina. The Company has downstream contracts in place to match throughput at the battery.

Paramount's development strategy at the Kaybob Montney Oil asset is to maintain oil production flat at about 8,000 Bbl/d, with optionality to increase throughput in the event of higher oil prices.

Kaybob Smoky Duvernay

The 2018 capital program for the Kaybob Smoky Duvernay will see a new four well pad (100 percent working interest, average 2,600 meter lateral length with proppant loading intensities up to 4.5 tonnes per meter) spudded in late-2017 (part of the fourth quarter 2017 capital spend estimate) and come on-stream in middle of 2018.

The new four well pad will produce to Paramount's owned and operated Smoky 06-16 gas plant, which will have approximately 12 MMcf/d of throughput capacity after some minor capital investments. The Smoky 06-16 plant is TCPL connected with firm transportation to accommodate natural gas production. Condensate and NGLs will be trucked to the 08-09 Plant and the 12-10 oil battery, which is located about 15 miles east.

The 2018 capital program is Phase 1 of the development of the Kaybob Smoky Duvernay asset. Phase 2 will consist of further modifications to the Smoky 06-16 gas plant to increase throughput capacity to about 20 MMcf/d in 2019. Phase 3 of the development will include a pipeline connection to the Kaybob North 08-09 gas plant and some modifications/enhancements to the Kaybob North 08-09 gas plant for handling Duvernay liquids. Phase 3 will add incremental throughput capacity of approximately 40 MMcf/d, bringing the total throughput capacity for the asset up to 60 MMcf/d for middle of 2020.

The growth plan at the Kaybob Smoky Duvernay asset is supported by firm natural gas transportation on TCPL and downstream contracts for the condensate and NGLs.

Kaybob South Duvernay

In 2018 the Company will allocate up to $50 million to the Kaybob South Duvernay asset. Paramount's average working interest in the asset is about 60 percent and the 2018 program average working interest is 51 percent. The program will consist of drilling up to 11 gross wells and completing five of those wells in 2018 with the remainder being completed in early-2019.

The asset produces through third party facilities under firm contracts with current throughput capacity limited to 40 MMcf/d at the 15-28 compression and dehydration facility. The 15-28 facility is expandable and the Company has firm service natural gas processing capacity in excess of 80 MMcf/d at a downstream third-party natural gas processing plant.

Paramount has firm natural gas transportation on TCPL that aligns with the current third-party facilities solution and would be addressed in an expansion scenario.

Other Exploration and Development Capital

The 2018 capital program includes about $60 million for other high-graded development projects including Birch Montney, Willesden Green Duvernay, Hoadley Glauconite, Gething oil and Ante Creek Montney. In total, the Company plans to drill around 11 gross wells (7.8 net wells) and complete 10 gross wells (6.8 net wells). All but one of the completed wells will produce through owned and operated infrastructure which is accompanied by firm transportation contracts for natural gas. The exception is Birch Montney, where Paramount has ownership in facilities that are operated by a joint-venture partner.

The 2018 capital plan excludes non-operated opportunities which may arise throughout the year, which will be evaluated on a case-by-case basis to determine the economic feasibility, risk profile, and strategic rationale.

Optimization Capital

In 2018 the Company has allocated approximately $45 million to maintenance and optimization projects to add production, reduce base decline, and achieve operating cost savings. The focus of these optimization projects is in the Kaybob area, where there are a number of opportunities to re-route production from third party facilities to owned and operated facilities. These investment opportunities are possible due to the overlap of the Trilogy and Apache Canada land and infrastructure positions in Kaybob, which provide significant opportunities for cost saving synergies.

TECHNOLOGY UPDATE

Over the course of three years Paramount has evolved completion designs from open-hole packer systems with oil-based fluid to cased hole designs with slickwater fluid and pump rates more than 14 m3/min. Stage spacing has decreased from up to 100m down to as low as 40m with proppant loading intensities increasing from 0.6 t/m to as high as 4.5 t/m.

Paramount continues to investigate and research the evolution of well design and will test concepts around plug optimization, zipper fracturing techniques, casing string design, and artificial lift technologies in 2018.

In 2018 a key focus for Paramount is data acquisition projects including micro-seismic, production logging with fiber, pilot wells and coring, landing zone optimization, well density tests, stacked development tests and water reuse applications.

Paramount strives to be a leader in well completion designs and optimizing well performance with a specific focus on condensate recoveries. The Company has embraced data analytics and is monitoring competitors in its own basin and plays as well as operators south of the border. Paramount is focused on the optimal asset allocation and maximizing oil and condensate recovery from our liquids-rich resource plays.

SUBSEQUENT EVENTS

Since October 1, 2017, Paramount has entered into hedges for 10,000 Bbl/d of Liquids for 2018 at an average WTI price of C$69.84/Bbl. For the remainder of 2017, the Company has 4,000 Bbl/d of Liquids hedged at an average WTI price of C$70.80/Bbl and 2,000 Bbl/d hedged at a WTI price of US$54.48/Bbl.

The Company will receive US$1.1 million of locked-in gains on natural gas hedging contracts in the fourth quarter of 2017 and has an additional 20,000 MMBtu/d hedged at a NYMEX price of US$3.40/MMbtu until the end of the year.

The Company has secured firm service transportation capacity for approximately 60,000 GJ/d of natural gas for delivery to the Dawn natural gas hub in Ontario for sale to eastern natural gas markets.


    OPERATING AND FINANCIAL RESULTS (1)

    ($ millions, except as noted)

                                                                                               Three months ended              Nine months ended

                                                                                                  September 30                    September 30
                                                                                                  ------------                    ------------

                                                                                    2017      2016    % Change        2017      2016    % Change
                                                                                    ----      ----    --------        ----      ----    --------

    Sales Volumes (Boe/d)

                                                     PRL (2)                               25,294       11,148         127    19,975       11,583        72

                                                     Apache Canada                         18,960            -        100     6,389            -      100

                                                     Trilogy                                4,769            -        100     1,607            -      100
                                                     -------                                -----          ---               -----          ---

    Ongoing Operations                                                                   49,023       11,148         340    27,971       11,583       141

                                                     Musreau Assets (2)                         -      13,638       (100)        -      26,979     (100)
                                                     -----------------                        ---      ------                  ---      ------

    Total                                                                                49,023       24,786          98    27,971       38,562      (27)
    =====                                                                                ======       ======               ======       ======

    Netback

                                                     Natural gas revenue                     30.9         21.6          43      62.9         68.6       (8)

                                                     Condensate and oil revenue              74.2         25.1         196     152.2        121.7        25

                                                     Other NGLs revenue (3)                   9.8          4.8         104      15.2         25.3      (40)

                                                     Royalty and sulphur revenue              1.6          0.2         700       2.3          0.9       156
                                                                                            ---          ---                  ---          ---

    Petroleum and natural gas
     sales                                                                                116.5         51.7         125     232.6        216.5         7

                                                     Royalties                              (5.0)       (0.1)         NM    (7.8)       (2.1)      271

                                                     Operating expense                     (47.8)      (25.0)         91    (79.8)      (86.1)      (7)

                                                      Transportation and NGLs processing
                                                      (4)                                  (12.3)      (12.7)        (3)   (26.6)      (52.2)     (49)
                                                                                         ------        -----                  ---        -----

    Netback                                                                                51.4         13.9         270     118.4         76.1        56

                                                     ($/Boe)                                11.40         6.12          86     15.49         7.20       115


    Exploration and Capital Expenditures

                                                     Wells and exploration                  100.6         46.5         116     330.1         83.1       297

                                                     Facilities and gathering                21.4          0.1          NM     50.8          9.8       418
                                                     --------                                ----                     ---     ----

    Principal Properties
     Capital (5)                                                                          122.0         46.6         162     380.9         92.9       310
                                                                                          =====         ====                =====         ====


    Net income                                                                            223.5      1,029.4        (78)    289.5        952.9      (70)

                                                     per share - diluted ($/share)           1.97         9.64        (80)     2.65         8.97      (70)

    Funds flow from operations                                                      45.3       3.8           NM      108.6      21.3          410

                                                     per share - diluted ($/share)           0.40         0.04          NM     0.99         0.20       395

    Total assets                                                                                      5,020.9     2,130.3       136

    Net debt (cash)                                                                                     564.3     (385.3)    (246)

    Investments in other entities - market value (6)                                                     56.5       466.7      (88)

    Common shares outstanding (thousands)                                                               134.8       106.3        27
    ====================================                                                                =====       =====       ===

             (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.

             (2)    In 2016, the Company sold its natural
                     gas processing facilities and the
                     majority of its oil and gas properties
                     in the Musreau/Kakwa area of west
                     central Alberta (the ?Musreau
                     Assets?). Disclosures of results for
                     the three and nine months ended
                     September 30, 2016 for "Ongoing
                     Operations" exclude amounts
                     attributable to these sold facilities
                     and oil and gas properties. "PRL"
                     means Paramount's existing operations
                     prior to the Apache Canada Acquisition
                     and the Trilogy Merger excluding the
                     Musreau Assets.

             (3)    Other NGLs means ethane, propane and
                     butane.

             (4)    Includes downstream natural gas, NGLs
                     and oil transportation costs and NGLs
                     fractionation costs incurred by the
                     Company.

             (5)    Principal Properties Capital includes
                     capital expenditures and geological
                     and geophysical costs related to the
                     Company's Principal Properties and
                     excludes land acquisitions.

             (6)    Based on the period-end closing prices
                     of publicly-traded investments and
                     the book value of the remaining
                     investments.

             (7)   NM Not meaningful

Paramount is an independent, publicly traded, Canadian energy company that explores and develops conventional and unconventional petroleum and natural gas prospects, including long-term unconventional exploration and pre-development projects, and holds a portfolio of investments in other entities. The Company's principal properties are primarily 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 third quarter 2017 results, including Management's Discussion and Analysis and the Company's Consolidated Financial Statements can be obtained at: http://files.newswire.ca/1509/PRL_Q3_Results.pdf

This information will also be made available shortly through Paramount's website at www.paramountres.com and SEDAR at www.sedar.com.

ADVISORIES

Forward-looking Information

Certain statements in this document 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 document includes, but is not limited to:

    --  projected production and sales volumes (including the Liquids
        component thereof);
    --  forecast capital expenditures (including the plays, regions and
        activities where, or in respect of which, this capital is
        expected to be spent), royalties, operating costs, abandonment
        and suspension costs, and transportation costs;
    --  exploration, development, and associated operational plans and
        strategies (including planned drilling and completion programs,
        well tie-ins, and facility expansions, and the anticipated
        timing thereof) and the Company's anticipated sources of funds
        to carry out such plans and strategies (including planned
        non-core asset divestitures);
    --  plans for securing the necessary drilling, completion and other
        services required to carry out the Company's 2018 development
        program;
    --  anticipated levels of cost inflation for drilling and
        completion services and the Company's anticipated ability to
        offset any additional cost increases by various means including
        increased economies of scale;
    --  the percentage of Paramount's currently booked proved and
        probable and high-graded Montney and Duvernay locations that
        its expects to drill in 2018;
    --  the Company's continued financial flexibility to accelerate its
        capital programs if industry conditions warrant; and
    --  general business strategies and objectives.


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 document:

    --  future natural gas and Liquids prices;
    --  royalty rates, taxes and capital, operating, general &
        administrative and other costs;
    --  foreign currency exchange rates and interest rates;
    --  general business, economic and market conditions;
    --  the ability of Paramount to obtain the required capital to
        finance its exploration, development and other operations and
        meet its commitments and financial obligations;
    --  the ability of Paramount to obtain equipment, services,
        supplies and personnel in a timely manner and at an acceptable
        cost to carry out its activities;
    --  the ability of Paramount to secure adequate product processing,
        transportation, de-ethanization, fractionation, and storage
        capacity on acceptable terms;
    --  the ability of Paramount to market its natural gas and Liquids
        successfully to current and new customers;
    --  the ability of Paramount and its industry partners to obtain
        drilling success (including in respect of anticipated
        production volumes, reserves additions, Liquids yields and
        resource recoveries) and operational improvements, efficiencies
        and results consistent with expectations;
    --  the timely receipt of required governmental and regulatory
        approvals; and
    --  anticipated timelines and budgets being met in respect of
        drilling programs and other operations (including well
        completions and tie-ins and the construction, commissioning and
        start-up of new and expanded facilities).


Although Paramount believes that the expectations reflected in such forward-looking information are reasonable, undue reliance should not be placed on them as Paramount can give no assurance that such expectations will prove to be correct. 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:

    --  fluctuations in natural gas and Liquids prices;
    --  changes in foreign currency exchange rates and interest rates;
    --  the uncertainty of estimates and projections relating to future
        revenue, future production, reserve additions, Liquids yields
        (including condensate to natural gas ratios), resource
        recoveries, royalty rates, taxes and costs and expenses;
    --  the ability to secure adequate product processing,
        transportation, de-ethanization, fractionation, and storage
        capacity on acceptable terms;
    --  operational risks in exploring for, developing and producing,
        natural gas and Liquids;
    --  the ability to obtain equipment, services, supplies and
        personnel in a timely manner and at an acceptable cost;
    --  potential disruptions, delays or unexpected technical or other
        difficulties in designing, developing, expanding or operating
        new, expanded or existing facilities (including third-party
        facilities);
    --  processing, pipeline, de-ethanization, and fractionation
        infrastructure outages, disruptions and constraints;
    --  risks and uncertainties involving the geology of oil and gas
        deposits;
    --  the uncertainty of reserves and resources estimates;
    --  general business, economic and market conditions;
    --  the ability to generate sufficient cash flow from operations
        and obtain financing to fund planned exploration, development
        and operational activities and meet current and future
        commitments and obligations (including product processing,
        transportation, de-ethanization, fractionation and similar
        commitments and obligations);
    --  changes in, or in the interpretation of, laws, regulations or
        policies (including environmental laws);
    --  the ability to obtain required governmental or regulatory
        approvals in a timely manner, and to enter into and maintain
        leases and licenses;
    --  the effects of weather;
    --  the timing and cost of future abandonment and reclamation
        obligations and potential liabilities for environmental damage
        and contamination;
    --  uncertainties regarding aboriginal claims and in maintaining
        relationships with local populations and other stakeholders;
    --  the outcome of existing and potential lawsuits, regulatory
        actions, audits and assessments; and
    --  other risks and uncertainties described elsewhere in this
        document and in Paramount's other filings with Canadian
        securities authorities.


The foregoing list of risks is not exhaustive. For more information relating to risks, see the section titled "RISK FACTORS" in Paramount's current annual information form. The forward-looking information contained in this document 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 document "Funds flow from operations", "Netback", ?Net Debt (Cash)?, ?Adjusted Working Capital?, "Exploration and Capital Expenditures", "Principal Properties Capital" and "Investments in other entities - market value", collectively the "Non-GAAP measures", are used and do not have any standardized meanings as prescribed by International Financial Reporting Standards.

Funds flow from operations refers to cash from (used in) operating activities before net changes in operating non-cash working capital, geological and geophysical expenses, asset retirement obligation settlements and corporate acquisition and merger costs. Funds flow from operations is commonly used in the oil and gas industry to assist management and investors in measuring the Company's ability to fund capital programs and meet financial obligations. Refer to the Consolidated Results section of the Company's Management's Discussion and Analysis for the three and nine months ended September 30, 2017 for the calculation of funds flow from operations. 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 Principal Properties section of the Company's Management's Discussion and Analysis for the three and nine months ended September 30, 2017 for the calculation of netback. Net debt (cash) 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 Management's Discussion and Analysis for the calculation of Net debt (cash) and Adjusted working capital. Exploration and capital expenditures consist of the Company's spending on wells and infrastructure projects, other property, plant and equipment, land and property acquisitions and geological and geophysical costs incurred. The closest GAAP measure to exploration and development expenditures is property, plant and equipment and exploration cash flows under investing activities in the Company's Consolidated Statement of Cash Flows, which includes all of the items included in exploration and capital expenditures, except for geological and geophysical costs, which are expensed as incurred. Principal properties capital includes capital expenditures and geological and geophysical costs related to the Company's Principal Properties business segment, and excludes land acquisitions. The principal properties capital measure provides management and investors with information regarding the Company's Principal Properties spending on wells and infrastructure projects separate from land acquisition activity and capitalized interest. Refer to the Advisories section of the Company's Management's Discussion and Analysis for the three and nine months ended September 30, 2017 for the calculation of exploration and capital expenditures and principal properties capital. Investments in other entities - market value reflects the Company's investments in enterprises whose securities trade on a public stock exchange at their period end closing price (e.g. Trilogy Energy Corp. (2016), MEG Energy Corp., Blackbird Energy Inc., Marquee Energy Ltd., RMP Energy Inc., Strategic Oil & Gas Ltd. and others) and investments in all other entities at book value. Paramount provides this information because the market values of equity-accounted investments, which are significant assets of the Company, are often materially different than their carrying values. Refer to the Strategic Investments section of the Company's Management's Discussion and Analysis for the three and nine months ended September 30, 2017 for information on carrying and market values.

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" means oil, condensate and Other NGLs (ethane, propane and butane).

Abbreviations

    Liquids                                           Natural Gas
    -------                                           -----------

    Bbl            Barrels                           Mcf          Thousands of cubic feet

    Bbl/d          Barrels per day                   MMcf         Millions of cubic feet

    MBbl           Thousands of barrels              MMcf/d       Millions of cubic feet per day

    NGLs           Natural gas liquids               MMbtu        Millions of British thermal units

    Condensate     Pentane and heavier hydrocarbons


    Oil Equivalent
    --------------

    Boe            Barrels of oil equivalent

    Boe/d          Barrels of oil equivalent per day


Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil. 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 nine months ended September 30, 2017, the value ratio between crude oil and natural gas was approximately 23:1. 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.

SOURCE Paramount Resources Ltd.

View original content with multimedia: http://www.newswire.ca/en/releases/archive/November2017/09/c6714.html

SOURCE: Paramount Resources Ltd.

Paramount Resources Ltd., J.H.T. (Jim) Riddell, President and Chief Executive
Officer, B.K. (Bernie) Lee, Chief Financial Officer, www.paramountres.com, Phone:
(403) 290-3600

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