Market Overview

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

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CALGARY, Nov. 9, 2017 /CNW/ -

OIL AND GAS OPERATIONS

  • Paramount completed two major transactions in the third quarter of 2017, acquiring Apache Canada Ltd. (ʺApache Canadaʺ) in August and completing a merger with Trilogy Energy Corp. (ʺTrilogyʺ) 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 ʺFacilityʺ) 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 ʺApache Canada Acquisitionʺ) and the merger with Trilogy (the ʺTrilogy Mergerʺ), 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

Total (1)

(Boe/d)

Peak 30 Day

Condensate (1)

(Bbl/d)

 % Condensate

Days on

Production

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 ʺ06-18 Facilityʺ) 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

Total (1)

(Boe/d)

Peak 30 Day

Oil (1)

(Bbl/d)

 % Oil

Days on

Production

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 ʺ08-09 Plantʺ) 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

September 30

Nine months ended

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 ʺMusreau Assetsʺ). 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", ʺNet Debt (Cash)ʺ, ʺAdjusted Working Capitalʺ, "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.

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