CALGARY, May 8, 2019 /CNW/ -
OIL AND GAS OPERATIONS
- Sales volumes averaged 81,296 Boe/d (37 percent liquids) in the first quarter of 2019.
- Paramount's netback increased 61 percent to $115.7 million in the first quarter of 2019 compared to $72.0 million in the fourth quarter of 2018, mainly due to a 26 percent average increase in realized prices.
- The liquids-rich Karr development accounted for $52.8 million (46 percent) of the Company's total netback in the first quarter.
- Adjusted funds flow increased 121 percent to $100.5 million ($0.77 per share) in the first quarter of 2019 compared to $45.5 million ($0.35 per share) in the prior quarter.
- The Company is delivering test volumes from its Wapiti 9-3 pad as part of the commissioning of the new third-party processing plant. First sales are expected in May 2019.
- Paramount is reaffirming its 2019 production guidance, including first half average sales volumes of between 80,000 Boe/d and 81,000 Boe/d and annual average sales volumes of between 81,000 Boe/d and 85,000 Boe/d. Production is expected to increase in the second half of the year as Wapiti ramps up, with fourth quarter sales volumes expected to average between 85,000 Boe/d and 90,000 Boe/d.
- First quarter base capital spending totaled $68.6 million, primarily related to drilling and completion programs at Wapiti and Kaybob Montney Oil.
- The Company's $350 million base capital budget for 2019 remains unchanged.
- The expansion of the Karr 6-18 natural gas facility (the ʺ6-18 Facilityʺ) remains on track for start-up in the second half of 2020. First quarter spending on the project totaled $34.5 million. Total forecast spending for the project for 2019 remains at $145 million. The Company continues to evaluate funding alternatives to complete the project.
- Paramount's natural gas diversification strategy includes approximately 122,000 GJ/d of sales under long-term contracts priced at the Dawn, US Midwest and Malin markets. The Company's average realized natural gas sales price for the first quarter of 2019 was $3.37/Mcf compared to average AECO prices of $2.17/GJ.
- The Company has 15,000 Bbl/d of liquids hedged for the remainder of 2019 at an average price of $77.58/Bbl and 3,000 Bbl/d hedged for 2020 at an average price of $80.07/Bbl.
- The Company's net debt position was $903.3 million as at March 31, 2019, relatively unchanged from December 31, 2018, as first quarter capital spending was largely funded by cash flow.
REVIEW OF OPERATIONS
Paramount's sales volumes averaged 81,296 Boe/d in the first quarter of 2019. The Company's first quarter netback increased 61 percent to $115.7 million from $72.0 million in the fourth quarter of 2018. First quarter 2019 adjusted funds flow increased 121 percent to $100.5 million compared to $45.5 million in the prior quarter.
Base capital spending totaled $68.6 million in the first quarter of 2019, primarily related to drilling and completion programs at Wapiti and Kaybob Montney Oil. Total capital spending in the first quarter of 2019, including spending related to the 6-18 Facility expansion, corporate projects and land acquisitions, was $104.1 million.
GRANDE PRAIRIE REGION
Natural gas (MMcf/d)
Condensate and oil (Bbl/d)
Other NGLs (Bbl/d)
% Change in
Petroleum and natural gas sales
Transportation and NGLs processing
First quarter 2019 sales volumes at the Karr development averaged 24,786 Boe/d compared to 26,282 Boe/d in the fourth quarter of 2018. First quarter production was impacted by an unplanned outage at a downstream third-party processing facility in February and the effects of severe cold weather. The 6-18 Facility achieved an overall runtime rate of 98 percent in the first quarter, excluding the duration of the unplanned third-party outage. The decrease in operating expenses in the first quarter was primarily due to lower processing fees and reduced water disposal costs. A higher-rate water injection system was installed at the 6-18 Facility in February, which increased water injection capacity and reduced water hauling and disposal costs.
Royalty rates for the Karr development increased in the first quarter of 2019 compared to the fourth quarter of 2018, as a number of wells had fully utilized new well royalty incentives. New wells at Karr will continue to benefit from a five percent initial royalty rate up to the maximum incentive.
Development activities at Karr will resume in the second quarter of 2019 with the completion of five Montney wells drilled in 2018 on the 4-24 pad. The Company scheduled completion operations after spring breakup to capture cost savings resulting from operating in warmer conditions. Paramount also plans to commence drilling three new wells on the 1-19 pad. These eight new Montney wells will be brought-on production as required to offset natural production declines.
The expansion of the 6-18 Facility remains on track for start-up in the second half of 2020. First quarter 2019 capital spending on the project totaled $34.5 million, primarily related to long-lead time equipment purchases.
The Company drilled its initial lower Montney well on the 1-2 pad in 2018. Two additional wells in the 2019 development program will also target the lower Montney. 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 in the future 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)
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 10 percent lower and liquids sales volumes are approximately 12 percent lower due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes shown are 30-day peak rates over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints.
Cumulative is the aggregate production measured at the wellhead to May 3, 2019. Natural gas sales volumes are approximately 10 percent lower and liquids sales volumes are approximately 12 percent lower due to shrinkage. These wells were produced at restricted rates from time-to-time due to facility and gathering system constraints. The production rates and volumes shown are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells.
CGRs mean condensate to gas ratios and are calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes.
Average days on production per well for the 2016/2017 Wells.
Paramount's new Wapiti resource play is a continuation of the Montney trend that the Company has been successful in developing approximately 25 kilometers to the southeast at Karr. First quarter 2019 capital spending at Wapiti was $32.1 million, focused on the tie-in of 11 (11.0 net) wells on the 9-3 pad and the drilling of 12 (12.0 net) wells on the 5-3 pad.
The Company is delivering test volumes from the 9-3 pad as part of the commissioning of the new third-party Wapiti natural gas processing plant (the ʺWapiti Plantʺ) and first sales are expected in May 2019. Production is expected to increase as throughput at the Wapiti Plant ramps up, with all 11 wells on the 9-3 pad scheduled to be brought-on production in 2019. Drilling operations were completed for 12 wells on the 5-3 pad in the first quarter of 2019, and these wells are scheduled to be completed in the second quarter. Paramount has firm-service third-party natural gas transportation capacity for its Wapiti production volumes, which increases from 50 MMcf/d in 2019 to 130 MMcf/d in 2021.
The Company continues to pursue innovative alternatives to further reduce costs in its drilling and completion programs, including optimizing drilling and completion designs, streamlining logistics and realizing the benefits of economies of scale by utilizing large multi-well pads. As a result of these cost reduction initiatives, total capital costs for the 9-3 pad were reduced by approximately 11 percent compared to the original budget for the project.
As the Company integrated learnings from the 9-3 pad, drilling improvements were achieved on the 5-3 pad. Drilling time decreased in the lateral sections by approximately 25 percent compared with the 9-3 pad. In addition, the wellbores were drilled within the five-meter target zone for 94 percent of the lateral section compared to 83 percent observed for the wells on the 9-3 pad.
Kaybob Region sales volumes averaged 37,143 Boe/d in the first quarter of 2019 compared to 37,262 Boe/d in the fourth quarter of 2018. Capital spending totaled $27.4 million. Development activities in the first quarter focused on drilling and completion operations on the Duvernay and Montney.
Kaybob South Duvernay
At South Duvernay, 5 (2.5 net) new wells on the 2-28 pad were drilled in 2018 and completed in March and April 2019. These wells are expected to be tied-in and brought-on production in the third quarter of 2019. Paramount set new records for these wells, reducing drilling time for the lateral sections by 47 percent compared to the 7-22 pad drilled in 2018. The wellbores for the 2-28 pad were also drilled within the five-meter target zone for 91 percent of the lateral sections compared to 82 percent observed for the wells on the 7-22 pad.
Kaybob Montney Oil
At the Montney Oil development, two wells from the 2018 capital program were brought-on production in the first quarter of 2019 and three new wells were drilled. Two of these new wells are scheduled to be brought-on production in the second quarter.
Kaybob Smoky Duvernay
In November 2018, the Company brought 4 (4.0 net) new wells on production on the 10-35 pad at Smoky Duvernay through Paramount's Smoky 06-16 plant. Cumulative production for these four wells as of May 3, 2019 totaled 674 MBoe, including 437 MBbl of wellhead liquids (average CGR of 310 Bbl/MMcf).(1) Production from the 10-35 pad has been facility constrained at the 06-16 plant and Paramount is currently completing debottlenecking enhancements to provide incremental capacity.
The Company's Kaybob Region drilling program in the first quarter of 2019 also included a tenure well in the North Kaybob Duvernay oil window and an initial appraisal well at the Ante Creek Montney property.
CENTRAL ALBERTA AND OTHER REGION
Central Alberta and Other Region sales volumes averaged 18,623 Boe/d in the first quarter of 2019 compared to 20,257 Boe/d in the fourth quarter of 2018. Capital spending totaled $5.5 million. The Company participated in drilling operations for one (0.5 net) well at Birch in northeast British Columbia in the first quarter of 2019. A tenure well is scheduled to be drilled in the East Shale Basin later in 2019.
The Company has commenced the closure program at Zama in northern Alberta, with approximately 25 percent of wells shut-in to date. The program will continue through the balance of the year as conditions permit.
Cumulative is the aggregate production measured at the wellhead to May 3, 2019. Natural gas sales volumes are approximately 10 percent lower and liquids sales volumes are approximately four percent lower due to shrinkage. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells.
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 is executing a project in the Central Alberta and Other and Kaybob regions to replace approximately 1,700 high-bleed controllers with modern low-bleed units at a total estimated cost of $3.5 million. Once installed, these low-bleed controllers are expected to eliminate approximately 120,000 tonnes of GHG emissions annually. This project is anticipated to generate approximately $9 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.
Paramount's natural gas diversification strategy includes approximately 122,000 GJ/d of sales under long-term contracts priced at the Dawn, US Midwest and Malin markets. The Company's average realized natural gas sales price for the first quarter of 2019 was $3.37/Mcf compared to average AECO prices of $2.17/GJ.
To protect the Company's cash flows and support its capital programs, Paramount has 15,000 Bbl/d of liquids hedged for the remainder of 2019 at an average price of $77.58/Bbl and 3,000 Bbl/d hedged for 2020 at an average price of $80.07/Bbl.
In the first quarter of 2019, the Company entered into interest rate swaps to fix interest rates on a portion of its bank debt; $250 million notional amount for four years and an additional $250 million notional amount for seven years.
As at March 31, 2019, $827.3 million was drawn on the Company's $1.5 billion bank credit facility. The Company's net debt position was $903.3 million as at March 31, 2019, relatively unchanged from December 31, 2018, as first quarter capital spending was largely funded by cash flow.
In January 2019, Paramount implemented a normal course issuer bid program under which the Company may purchase up to 7.1 million Paramount common shares for cancellation. No purchases have been made under the program to date.
OPERATING AND FINANCIAL RESULTS (1)
($ millions, except as noted)
Natural gas (MMcf/d)
Condensate and oil (Bbl/d)
Other NGLs (Bbl/d) (3)
Grande Prairie Region (Boe/d)
Kaybob Region (Boe/d)
Central Alberta and Other Region (Boe/d)
Adjusted Funds Flow
Natural gas revenue
Condensate and oil revenue
Other NGLs revenue (3)
Royalty and sulphur revenue
Petroleum and natural gas sales
Transportation and NGLs processing (4)
Commodity contract settlements
General and administrative
Interest and financing expense
Adjusted funds flow
per share – diluted ($/share)
Exploration and Development Capital (5)
Grande Prairie Region
Karr 6-18 Facility Expansion
Central Alberta and Other Region
per share – basic and diluted ($/share)
Common shares outstanding (thousands)
Readers are referred to the advisories concerning Non-GAAP Measures and Oil and Gas Measures and Definitions in the Advisories section of this document.
Natural gas revenue presented as $/Mcf.
Other NGLs means ethane, propane and butane.
Includes downstream transportation costs and NGLs fractionation costs.
Excludes land and property acquisitions and spending related to corporate assets.
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 first 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/883733/PRL_Q1_2019_Results.pdf.
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 first sales at Wapiti;
- expected average sales volumes for 2019, including for the first half of 2019 and the fourth quarter of 2019;
- budgeted capital expenditures;
- an expected increase in sales volumes as additional new wells are brought-on production at Wapiti;
- the 6-18 Facility expansion remaining on track for a start-up in the second half of 2020 and forecast spending on the project for 2019;
- 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.
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 and transaction and reorganization costs. Adjusted funds flow 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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 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 months ended March 31, 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.
Barrels per day
Gigajoules per day
Thousands of barrels
Thousands of cubic feet
Natural gas liquids
Millions of cubic feet
Pentane and heavier hydrocarbons
Millions of cubic feet per day
AECO-C reference price
New York Mercantile Exchange
Barrels of oil equivalent
Thousands of barrels of oil equivalent
Barrels of oil equivalent per day
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 three months ended March 31, 2019, the value ratio between crude oil and natural gas was approximately 36:1. 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 wellhead raw liquids volumes by wellhead raw natural gas volumes. 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.