Paramount Resources Ltd. Reports Second Quarter 2019 Results
CALGARY, Aug. 8, 2019 /CNW/ -
HIGHLIGHTS
- Sales volumes averaged 81,793 Boe/d (37 percent liquids) in the second quarter of 2019.
- Paramount's second quarter netback was $82.1 million compared to $115.7 million in the first quarter of 2019, primarily as a result of weaker natural gas and NGLs prices. Second quarter 2019 operating costs of $86.8 million ($11.66 per Boe) were lower than first quarter operating costs of $90.4 million ($12.35 per Boe).
- The liquids-rich Karr and Wapiti Montney developments accounted for $46.1 million (56 percent) of the Company's total netback in the second quarter.
- Cash from operating activities was $48.1 million in the second quarter of 2019. Adjusted funds flow was $54.2 million ($0.41 per share).
- The Company commenced production from the Wapiti 9-3 pad on an intermittent basis in May and June 2019 as the start-up and commissioning of the new third-party Wapiti gas plant progressed. Estimated Wapiti sales volumes for July averaged approximately 6,300 Boe/d, including approximately 10.5 MMcf/d of natural gas and 4,500 Bbl/d of liquids, as runtime at the plant increased.
- The five wells started-up on the Wapiti 9-3 pad that have produced for at least 60 days had an average wellhead CGR of 376 Bbl/MMcf over their first 60 producing days, significantly exceeding internal type curves.(1)
- On August 1, 2019, Paramount closed the sale of its Karr 6-18 natural gas facility (the ʺ6-18 Facilityʺ) for total cash proceeds of approximately $330 million (the ʺMidstream Transactionʺ). The cash proceeds included the reimbursement of approximately $75 million of capital expenditures related to the expansion of the 6-18 Facility (ʺD2ʺ), which is scheduled to be commissioned in the second half of 2020. As a consequence of the Midstream Transaction, operating costs at Karr will increase in the second half of 2019 due to incremental processing fees.
- Paramount's June 30, 2019 long-term debt balance, pro forma the closing of the Midstream Transaction, was approximately $585 million. The Company has a $1.5 billion bank credit facility that matures in November 2022.
- Paramount's sales volumes averaged 81,546 Boe/d in the first half of 2019. Sales volumes are expected to increase in the second half of the year at Wapiti, Karr and Kaybob South Duvernay, with fourth quarter sales volumes expected to average between 85,000 Boe/d and 90,000 Boe/d. The Company is reaffirming its annual average production guidance of between 81,000 Boe/d and 85,000 Boe/d.
- Base capital spending totaled $86.0 million for the second quarter and $154.6 million for the first half of 2019, primarily related to the Wapiti, Karr and Kaybob South Duvernay developments. The Company continues to expect 2019 annual spending to be in line with its $350 million base capital budget.
______________________ |
(1) CGR means condensate to gas ratio and is calculated by dividing raw wellhead oil, condensate and other hydrocarbon liquids (ʺWellhead Liquidsʺ) volumes by raw wellhead natural gas volumes. The stated CGRs excludes days when the wells did not produce. CGRs stated are over a short period of time and, therefore, are not necessarily indicative of long-term performance or of ultimate recovery from the wells |
REVIEW OF OPERATIONS
Paramount's sales volumes averaged 81,793 Boe/d in the second quarter of 2019. Cash from operating activities was $48.1 million compared to $88.5 million in the first quarter of 2019. Second quarter revenues were reduced by $45.4 million due to weaker AECO and US natural gas prices. NGLs prices were also lower in the second quarter of 2019, resulting in a 57 percent decrease in NGLs revenue despite higher sales volumes. Second quarter adjusted funds flow was $54.2 million ($0.41 per share) compared to $100.5 million ($0.77 per share) in the first quarter of 2019. Operating costs were $86.8 million ($11.66 per Boe) in the second quarter of 2019, four percent lower than first quarter operating costs of $90.4 million ($12.35 per Boe).
In response to seasonally weak natural gas prices, the Company temporarily shut-in approximately 600 Boe/d of dry gas production in the Kaybob Region in June 2019. Paramount permanently shut-in its Hawkeye property in late-2018 and its Zama property in the first half of 2019 due to challenging economics. In total, the Company has shut-in approximately 2,100 Boe/d of uneconomic production since the fourth quarter of 2018 as it focuses on operating profitably and reducing operating costs.
Base capital spending totaled $86.0 million in the second quarter of 2019, primarily related to drilling and completion programs at Wapiti and Karr in the Grande Prairie Region and at South Duvernay in the Kaybob Region. The Company also incurred $11.0 million of capital spending in the second quarter related to the D2 expansion project at the 6-18 Facility, which was reimbursed on closing of the Midstream Transaction. Second quarter 2019 field activities also included $2.0 million of asset retirement obligation settlements. Paramount plans to increase production, including a higher proportion of liquids, in the second half of the year as new liquids-rich Montney and Duvernay wells from the 2019 capital program are brought-on production.
GRANDE PRAIRIE REGION
Karr
Q2 2019 |
Q1 2019 |
|||
Sales volumes |
||||
Natural gas (MMcf/d) |
68.5 |
75.0 |
||
Condensate and oil (Bbl/d) |
8,858 |
10,712 |
||
Other NGLs (Bbl/d) |
1,505 |
1,579 |
||
Total (Boe/d) |
21,782 |
24,786 |
||
% liquids |
48% |
50% |
||
Netback |
($ millions) |
($/Boe) |
($ millions) |
($/Boe) |
Petroleum and natural gas sales |
72.0 |
36.32 |
89.0 |
39.89 |
Royalties |
(9.8) |
(4.90) |
(7.4) |
(3.31) |
Operating expense |
(20.1) |
(10.14) |
(21.4) |
(9.59) |
Transportation and NGLs processing |
(5.2) |
(2.65) |
(7.4) |
(3.33) |
36.9 |
18.63 |
52.8 |
23.66 |
|
Second quarter 2019 sales volumes at Karr averaged 21,782 Boe/d compared to 24,786 Boe/d in the first quarter of 2019. The decrease in the netback at Karr in the second quarter was primarily caused by lower natural gas prices and lower production.
Production levels at Karr in the second quarter were impacted by natural declines and the temporary shut-in of certain wells due to offsetting completion activities at the 4-24 pad and drilling operations at the 1-19 pad. The Company scheduled completion operations for the 5 (5.0 net) Montney wells on the 4-24 pad after spring breakup to capture cost savings from operating in warmer conditions. The 4-24 pad is scheduled to start-up in the third quarter.
Paramount is drilling 3 (3.0 net) new Montney wells on the 1-19 pad, which are scheduled to be completed in the third quarter and onstream in the fourth quarter of 2019. Karr area sales volumes are expected to increase through the second half of the year as new production is added from these two new pads. Production levels in July were impacted by a previously scheduled 10-day turnaround at the 6-18 Facility.
The Company drilled its initial Lower Montney well (the 00/4-25 well in the table below) in 2018 and two additional wells in the current year development program are also targeting the Lower Montney. The 4-24 and 1-19 pads each include one Lower Montney well, and these wells are scheduled to be brought-on production in the third and fourth quarters, respectively. To date, no Lower Montney locations have been included in the reserves recognized for Karr. The results of these three wells will be incorporated in Paramount's reserves evaluations at the end of the year and will be used to determine the Company's inventory of potential Lower Montney drilling locations.
Producing Montney wells at Karr continue to exhibit strong production rates and condensate yields. The following table summarizes the performance of the five wells on the 1-2 pad brought on-stream in the third quarter of 2018 and the 27 wells drilled in the 2016/2017 Karr capital program:
Peak 30-Day (1) |
Cumulative (2) |
||||||
Total |
Wellhead |
CGR (3) |
Total |
Wellhead |
CGR (3) |
Days on |
|
(Boe/d) |
(Bbl/d) |
(Bbl/MMcf) |
(MBoe) |
(MBbl) |
(Bbl/MMcf) |
||
1-2 Pad |
|||||||
00/04-25-065-05W6/0 |
1,598 |
975 |
261 |
338 |
195 |
227 |
319 |
02/04-25-065-05W6/0 |
1,703 |
951 |
211 |
405 |
199 |
161 |
301 |
00/01-26-065-05W6/0 |
1,878 |
1,180 |
282 |
460 |
259 |
215 |
320 |
02/01-26-065-05W6/0 |
2,108 |
1,333 |
287 |
371 |
216 |
232 |
268 |
00/02-26-065-05W6/0 |
2,058 |
1,286 |
278 |
519 |
300 |
228 |
313 |
2016/2017 Wells |
|||||||
27 wells |
|||||||
(Peak 30 day – avg. per well) |
1,971 |
1,186 |
252 |
16,366 |
8,506 |
180 |
586 (4) |
(1) |
Peak 30-Day is the highest daily average production rate over a 30-day consecutive period for each well, measured at the wellhead. Natural gas sales volumes |
(2) |
Cumulative is the aggregate production measured at the wellhead to July 31, 2019. Natural gas sales volumes are approximately 10 percent lower and Wellhead |
(3) |
CGRs calculated by dividing raw Wellhead Liquids volumes by raw wellhead natural gas volumes |
(4) |
Average days on production per well for the 2016/2017 Wells |
Wapiti
Sales volumes at Wapiti averaged 3,903 Boe/d in the second quarter of 2019, including 5.5 MMcf/d of natural gas and 2,982 Bbl/d of liquids, and generated a netback of $9.2 million ($25.94 per Boe). Paramount began flowing test volumes from up to nine of the 11 (11.0 net) new wells on the 9-3 pad in May 2019 as part of the commissioning program at the new third-party Wapiti natural gas processing plant (the ʺWapiti Plantʺ). The start-up of the two remaining wells were intentionally delayed due to completion activities at Paramount's offsetting 5-3 pad. Production was intermittent as the commissioning program progressed, and fuel gas and shrink losses were higher through the start-up period. Shrink losses are expected to diminish as operations at the Wapiti Plant continue to stabilize and throughput increases.
Estimated sales volumes at Wapiti in July averaged approximately 6,300 Boe/d, including approximately 10.5 MMcf/d of natural gas and 4,500 Bbl/d of liquids, as production from the 9-3 pad increased due to higher runtime at the Wapiti Plant. Wells at Wapiti continue to be produced at restricted rates.
The wells on the 9-3 pad are the Company's first Wapiti wells fracked with the same completion design as utilized at Karr. This 11-well pad consists of a six-well block drilled to the south and a five-well block drilled to the north. The north and south blocks are specifically designed to test landing zone and spacing patterns. Initial well results have indicated significantly higher CGR's than third-party offsetting wells which were completed with a different completion design. The five wells started-up on the Wapiti 9-3 pad that have produced for at least 60 days had an average wellhead CGR of 376 Bbl/MMcf over their first 60 producing days.(1)
Second quarter 2019 capital spending at Wapiti was $21.3 million, focused on completion operations for 12 (12.0 net) wells on the new 5-3 pad, which were drilled in the first quarter of 2019. All 12 wells are scheduled to be completed by the end of the third quarter. This pad is scheduled to be equipped and brought-on production in the fourth quarter.
KAYBOB REGION
Kaybob Region sales volumes averaged 37,127 Boe/d (31 percent liquids) in the second quarter of 2019 compared to 37,143 Boe/d (32 percent liquids) in the first quarter of the year. Capital spending totaled $29.2 million in the second quarter, with development activities focused on well completions and tie-ins of new Duvernay and Montney wells.
Kaybob South Duvernay
At Kaybob South Duvernay, 5 (2.5 net) new wells on the 2-28 pad were drilled between September 2018 and January 2019 and completed in the spring of 2019. These wells were tied-in and brought-on production in late-June 2019. These five wells averaged 1,104 Boe/d of production per well over their first 30 days of production, with an average wellhead CGR of 179 Bbl/MMcf.(2)
Kaybob Smoky Duvernay
In November 2018, the Company brought 4 (4.0 net) new wells on production on the 10-35 pad at Kaybob Smoky Duvernay through Paramount's Smoky 06-16 gas plant. The Company is continuing to monitor the performance of these wells and optimize processes at the 06-16 plant as a full field development strategy is evaluated for this play. These wells have exceeded previous type curve estimates for this play in this area. The following table summarizes the performance of the four wells on the 10-35 pad:
____________________________ |
|
(1) |
Calculated over the initial 60 days of production for each well. Production measured at the wellhead, excluding days when the wells did not produce. CGRs stated are over a short period of time and, therefore, are not necessarily indicative of long-term performance or of ultimate recovery from the wells |
(2) |
Production measured at the wellhead. Natural gas sales volumes are approximately nine percent lower and Wellhead Liquids sales volumes are approximately 28 percent lower due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance. |
Peak 30-Day (1) |
Cumulative (2) |
||||||
Total |
Wellhead |
CGR (3) |
Total |
Wellhead |
CGR (3) |
Days on |
|
(Boe/d) |
(Bbl/d) |
(Bbl/MMcf) |
(MBoe) |
(MBbl) |
(Bbl/MMcf) |
||
10-35 Pad |
|||||||
00/16-25-063-21W5/0 |
1,452 |
998 |
366 |
212 |
138 |
311 |
282 |
00/08-25-063-21W5/0 |
1,345 |
897 |
334 |
246 |
148 |
252 |
291 |
02/01-25-063-21W5/0 |
1,303 |
728 |
211 |
265 |
160 |
254 |
246 |
00/09-25-063-21W5/2 |
1,150 |
779 |
350 |
185 |
119 |
301 |
252 |
(1) |
Peak 30-Day is the highest daily average production rate over a 30-day consecutive period for each well, measured at the wellhead. Natural gas sales volumes are approximately 12 percent lower and Wellhead Liquids sales volumes are approximately 4 percent lower due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes shown are 30-day peak rates over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. |
(2) |
Cumulative is the aggregate production measured at the wellhead to July 31, 2019. Natural gas sales volumes are approximately 12 percent lower and Wellhead Liquids sales volumes are approximately 4 percent lower due to shrinkage. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. The production rates and volumes shown are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. |
(3) |
CGRs calculated by dividing raw Wellhead Liquids volumes by raw wellhead natural gas volumes. |
Kaybob Montney
At the Montney Oil development, 4 (4.0 net) new wells have been brought-on production in 2019. The Kaybob Region drilling program for 2019 also included an initial appraisal well at the Ante Creek Montney property. This well has been completed and is scheduled to be brought-on production in the third quarter.
CENTRAL ALBERTA AND OTHER REGION
Central Alberta and Other Region sales volumes averaged 18,862 Boe/d in the second quarter of 2019 compared to 18,623 Boe/d in the first quarter of 2019. The Company participated in drilling operations for one (0.5 net) well at Birch in northeast British Columbia, which was completed and brought-on production in the second quarter of 2019.
At the Zama property in northern Alberta, the Company took advantage of dry weather conditions and completed the full shut-down of area production by the end of June 2019, three months ahead of schedule. The closure program will continue through the balance of the year to permanently abandon over 1,000 kilometers of pipelines and suspend all facilities. The closure of Zama is anticipated to cost $13.4 million and will result in a material reduction in the Company's future operating expenses.
GREENHOUSE GAS REDUCTION INITIATIVE
As part of Paramount's commitment to responsible energy development, the Company is participating in Alberta's Carbon Competitiveness Incentive Program and investing in new equipment to reduce the emission of greenhouse gases (ʺGHGʺ) from its operations.
Paramount has recently completed a project in the Kaybob and Central Alberta and Other Regions, under budget and ahead of schedule, which included the replacement of approximately 1,700 high-bleed controllers with modern low-bleed units at a total cost of $3.0 million. These low-bleed controllers are expected to eliminate approximately 120,000 tonnes of GHG emissions annually. The project is anticipated to generate approximately $9.0 million in GHG credits through 2022.
Planning has also commenced for upgrades to the Company's remaining high-bleed controllers and other equipment to reduce emissions of GHGs, including methane, carbon dioxide, and nitrogen oxides.
CORPORATE
Paramount has 16,000 Bbl/d of liquids hedged for the remainder of 2019 at an average price of $78.05/Bbl and 4,000 Bbl/d hedged for 2020 at an average price of $80.11/Bbl.
As at June 30, 2019, the Company had a $1.5 billion bank credit facility with a maturity date of November 16, 2022.
The Company's June 30, 2019 long-term debt balance, pro forma the closing of the Midstream Transaction, was approximately $585 million.
In January 2019, Paramount implemented a normal course issuer bid program under which the Company may purchase up to 7.1 million Paramount common shares for cancellation. In July 2019, the Company purchased 33,100 shares for cancellation at a total cost of $0.2 million.
As a result of a reduction in Alberta income tax rates enacted in the second quarter of 2019, the carrying value of the Company's deferred tax asset was reduced by approximately $106 million with a corresponding charge to deferred tax expense.
FINANCIAL AND OPERATING RESULTS (1) ($ millions, except as noted) |
|||||
Q2 2019 |
Q1 2019 |
||||
Net loss |
(121.0) |
(76.7) |
|||
per share – basic and diluted ($/share) |
(0.93) |
(0.59) |
|||
Cash from operating activities |
48.1 |
88.5 |
|||
Adjusted funds flow |
54.2 |
100.5 |
|||
per share – basic and diluted ($/share) |
(0.41) |
(0.77) |
|||
Total assets |
4,031.8 |
4,108.0 |
|||
Long-term debt |
909.7 |
827.3 |
|||
Net debt |
964.8 |
903.3 |
|||
Common shares outstanding (thousands) |
130,912 |
130,904 |
|||
Sales volumes |
|||||
Natural gas (MMcf/d) |
309.7 |
308.0 |
|||
Condensate and oil (Bbl/d) |
23,312 |
23,679 |
|||
Other NGLs (Bbl/d) (3) |
6,859 |
6,284 |
|||
Total (Boe/d) |
81,793 |
81,296 |
|||
% liquids |
37% |
37% |
|||
Grande Prairie Region (Boe/d) |
25,804 |
25,530 |
|||
Kaybob Region (Boe/d) |
37,127 |
37,143 |
|||
Central Alberta and Other Region (Boe/d) |
18,862 |
18,623 |
|||
Total (Boe/d) |
81,793 |
81,296 |
|||
Netback |
$/Boe (2) |
$/Boe (2) |
|||
Natural gas revenue |
49.5 |
1.76 |
93.3 |
3.37 |
|
Condensate and oil revenue |
150.7 |
71.02 |
134.8 |
63.26 |
|
Other NGLs revenue (3) |
6.9 |
11.01 |
16.2 |
28.55 |
|
Royalty and sulphur revenue |
2.1 |
─ |
1.8 |
─ |
|
Petroleum and natural gas sales |
209.2 |
28.10 |
246.1 |
33.63 |
|
Royalties |
(18.7) |
(2.51) |
(15.4) |
(2.10) |
|
Operating expense |
(86.8) |
(11.66) |
(90.4) |
(12.35) |
|
Transportation and NGLs processing (4) |
(21.6) |
(2.91) |
(24.6) |
(3.36) |
|
Netback |
82.1 |
11.02 |
115.7 |
15.82 |
|
Commodity contract settlements |
(2.8) |
(0.37) |
5.6 |
0.77 |
|
Netback including commodity contract settlements |
79.3 |
10.65 |
121.3 |
16.59 |
|
Exploration and Development Capital (5) |
|||||
Grande Prairie Region |
56.2 |
33.2 |
|||
Karr 6-18 Facility Expansion |
11.0 |
34.5 |
|||
Kaybob Region |
29.2 |
27.4 |
|||
Central Alberta and Other Region |
0.4 |
5.5 |
|||
Total |
96.8 |
100.6 |
|||
Asset retirement obligations settlements |
2.0 |
5.8 |
|||
(1) |
Readers are referred to the advisories concerning Non-GAAP Measures and Oil and Gas Measures and Definitions in the Advisories section of this document. This table contains the following Non-GAAP measures: Net Debt, Netback, Adjusted Funds Flow and Exploration and Development Capital |
(2) |
Natural gas revenue presented as $/Mcf |
(3) |
Other NGLs means ethane, propane and butane |
(4) |
Includes downstream transportation costs and NGLs fractionation costs |
(5) |
Excludes land and property acquisitions and spending related to corporate assets |
ABOUT PARAMOUNT
Paramount is an independent, publicly traded, liquids-focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas resources. The Company also pursues long-term strategic exploration and pre-development plays and holds a portfolio of investments in other entities. The Company's principal properties are located in Alberta and British Columbia. Paramount's Class A common shares are listed on the Toronto Stock Exchange under the symbol "POU".
Paramount's second quarter 2019 results, including Management's Discussion and Analysis and the Company's Consolidated Financial Statements, can be obtained at: https://mma.prnewswire.com/media/958196/Paramount_Resources_Ltd__Paramount_Resources_Ltd__Reports_Second.pdf
This information will also be made available through Paramount's website at www.paramountres.com and on SEDAR at www.sedar.com.
Advisories
Forward-looking Information
Certain statements in this press release constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "will", "expect", "plan", "schedule", "intend", "propose", or similar words suggesting future outcomes or an outlook. Forward-looking information in this press release includes, but is not limited to:
- expected average sales volumes for 2019 and in the fourth quarter of 2019;
- budgeted capital expenditures and the expectation that 2019 annual spending will be in line with the base capital budget;
- the expected increase in sales volumes (and the liquids component thereof) in the second half of 2019 as additional new wells are brought-on production;
- an expected decrease in shrink losses at Wapiti as the Wapiti Plant continues to stabilize and throughput increases;
- the timing of commissioning of the 6-18 Facility expansion;
- the scheduled completion of the Zama closure program by year-end 2019, the anticipated costs thereof and the impact on future operating costs;
- planned GHG reduction measures and expenditures and expected GHG credits; and
- planned exploration, development and production activities, including the anticipated timing of bringing new wells on production.
Such forward-looking information is based on a number of assumptions which may prove to be incorrect. Assumptions have been made with respect to the following matters, in addition to any other assumptions identified in this press release:
- 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, 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;
- the application of regulatory requirements respecting abandonment and reclamation; 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, including third-party facilities).
Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of this press release, undue reliance should not be placed on the forward-looking information as Paramount can give no assurance that such expectations will prove to be correct. 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, 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, fractionation, and storage capacity on acceptable terms;
- operational risks in exploring for, developing, producing and transporting natural gas and liquids, including the risk of spills, leaks or blowouts;
- 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 and fractionation infrastructure outages, disruptions and constraints;
- risks and uncertainties involving the geology of oil and gas deposits;
- the uncertainty of reserves 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, 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 obtain and maintain leases and licenses;
- the effects of weather and other factors including wildlife and environmental restrictions which affect field operations and access;
- 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 annual information form for the year ended December 31, 2018, which is available on SEDAR at www.sedar.com. The forward-looking information contained in this press release is made as of the date hereof and, except as required by applicable securities law, Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise.
Non-GAAP Measures
In this press release, "Adjusted funds flow", "Netback", "Net debt" and "Exploration and development capital", collectively the "Non-GAAP measures", are used and do not have any standardized meanings as prescribed by International Financial Reporting Standards.
"Adjusted funds flow" refers to cash from operating activities before net changes in operating non-cash working capital, geological and geophysical expenses, asset retirement obligation settlements, closure cost expenditures and transaction and reorganization costs. Adjusted funds flow is used to assist management and investors in measuring the Company's ability to fund capital programs and meet financial obligations, including the settlement of asset retirement obligations. Refer to the Consolidated Results section of the Company's Management's Discussion and Analysis for the three and six months ended June 30, 2019 for the calculation thereof. "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 Operating Results section of the Company's Management's Discussion and Analysis for the three and six months ended June 30, 2019 for the calculation thereof. "Net debt" is a measure of the Company's overall debt position after adjusting for certain working capital 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 three and six months ended June 30, 2019 for the calculation of Net debt. "Exploration and development capital" consists of the Company's spending on wells, infrastructure projects, other property, plant and equipment and exploration and evaluation assets and excludes spending related to land and property acquisitions and corporate assets. The exploration and development capital measure provides management and investors with information regarding the Company's capital spending on wells and infrastructure projects separate from land and property acquisition activity and corporate expenditures. Refer to the Property, Plant and Equipment and Exploration Expenditures of the Company's Management's Discussion and Analysis for the three and six months ended June 30, 2019 for the calculations thereof.
Non-GAAP measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, or other measures of financial performance calculated in accordance with GAAP. The Non-GAAP measures are unlikely to be comparable to similar measures presented by other issuers.
Oil and Gas Measures and Definitions
The term "liquids" includes oil, condensate and Other NGLs (ethane, propane and butane). NGLs consist of condensate and Other NGLs.
Abbreviations
Liquids |
Natural Gas |
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Bbl |
Barrels |
GJ |
Gigajoules |
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Bbl/d |
Barrels per day |
GJ/d |
Gigajoules per day |
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MBbl |
Thousands of barrels |
Mcf |
Thousands of cubic feet |
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NGLs |
Natural gas liquids |
MMcf |
Millions of cubic feet |
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Condensate |
Pentane and heavier hydrocarbons |
MMcf/d |
Millions of cubic feet per day |
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AECO |
AECO-C reference price |
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Oil Equivalent |
NYMEX |
New York Mercantile Exchange |
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Boe |
Barrels of oil equivalent |
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MBoe |
Thousands of barrels of oil equivalent |
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Boe/d |
Barrels of oil equivalent per day |
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This press release contains disclosures expressed as "Boe", "$/Boe", "MBoe" and "Boe/d". Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the six months ended June 30, 2019, the value ratio between crude oil and natural gas was approximately 47:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.
This press release contains metrics commonly used in the oil and natural gas industry. Each of these metrics is determined by the Company as set out below or elsewhere in this press release. "CGR" means condensate to gas ratio and is calculated by dividing raw Wellhead Liquids volumes by raw wellhead natural gas volumes. ʺWellhead Liquidsʺ means oil, condensate and other hydrocarbon liquids. CGR does not have a standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.
SOURCE Paramount Resources Ltd.
Paramount Resources Ltd., J.H.T. (Jim) Riddell, Chairman and President and Chief Executive Officer; B.K. (Bernie) Lee, Executive Vice President, Finance and Chief Financial Officer; Rodrigo (Rod) Sousa, Executive Vice President, Corporate Development and Planning; www.paramountres.com, Phone: (403) 290-3600
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