CALGARY, ALBERTA - March 5, 2015 /CNW/ - Paramount Resources Ltd. (TSX:POU)
- Proved reserves increased 159 percent to 226.8 MMBoe, after production of 9.0 MMBoe and dispositions of 2.4 MMBoe (replacement ratio of 17 times).
- Conventional proved and probable ("P+P") reserves increased 159 percent to 347.1 MMBoe (replacement ratio of 25 times), a record level for the Company.
- P+P condensate and Other NGLs reserves increased to 163.7 MMBbl, a 183 percent increase over 2013, and represent 47 percent of conventional P+P reserves.
- The net present value of conventional P+P reserves (10% discount, before tax) more than doubled to $3.8 billion, or $36.59 per share, despite significantly lower future commodity prices.
- P+P finding and development ("F&D") costs, excluding facilities and gathering capital, were $14.29 per Boe.
OIL AND GAS OPERATIONS
- Paramount's sales volumes averaged approximately 40,000 Boe/d in February 2015, the highest monthly average since the 2005 Trilogy Energy spin-out. The Company expects third-party NGLs processing constraints that have limited its ability to maximize production will begin to abate in the second quarter.
- Sales volumes in the fourth quarter of 2014 increased 70 percent to 34,430 Boe/d compared to the same period in 2013. Outages and apportionments of transportation and fractionation capacity impacted Paramount's ability to sustain production over 40,000 Boe/d in the fourth quarter. The Company's annual sales volumes increased 17 percent to 24,524 Boe/d in 2014 compared to 20,914 Boe/d in 2013.
- Fourth quarter 2014 liquids sales volumes totaled 10,443 Bbl/d, 226 percent higher than the same period in 2013, and included 5,320 Bbl/d of condensate and oil. Approximately 30 percent of fourth quarter sales volumes and 46 percent of petroleum and natural gas sales revenues were from liquids.
- The Kaybob COU's fourth quarter 2014 operating expense was $3.85 per Boe. Paramount's operating expense per Boe in 2014 was $7.96, 15 percent lower than 2013. Per-unit operating costs are expected to continue to decrease in 2015.
- Netbacks in the fourth quarter increased 108 percent to $61.0 million in 2014 from $29.3 million in 2013. Higher sales volumes, including an increasing proportion of liquids, more than offset the impact of lower liquids prices.
- The Company's two 10-well Montney pads in Kaybob have been completed. Aggregate test rates for the 10 wells on the 3-20 pad were 108 MMcf/d (10.8 MMcf/d per well) plus liquids. Aggregate test rates for the 10 wells on the 8-22 pad were 130 MMcf/d (13.0 MMcf/d per well) plus liquids.
- The three wells on the 3-20 pad with at least 30 days of production have averaged 6.0 MMcf/d of natural gas production over their first 30 days. Following the recovery of load oil volumes, wellhead condensate gas ratios for these wells have averaged 193 Bbl/MMcf.
- In the first quarter of 2015, Paramount finished drilling the Dunedin d-71-G shale gas exploration well in the Liard Basin and has commenced drilling the c-37-D shale gas exploration well at La Biche.
- Commissioning of Fox Drilling's two new triple-sized walking rigs is scheduled for the fourth quarter of 2015.
- Cavalier Energy received regulatory approval for the initial 10,000 Bbl/d phase of its Hoole Grand Rapids development in the second quarter of 2014.
- Paramount completed the acquisition of all of the outstanding common shares of MGM Energy Corp. that it did not already own in exchange for 1.1 million Common Shares of Paramount in June 2014.
- Sales volumes are expected to surpass 70,000 Boe/d in 2015 following the start-up of Paramount's condensate stabilizer expansion in the second quarter and the completion of third-party de-ethanization facilities expansions. Annual sales volumes in 2015 are expected to average between 55,000 and 65,000 Boe/d. The Company has 33 wells behind-pipe as of February 28, 2015 that can be brought on-stream in 2015, with estimated first-month production capability of 210 MMcf/d plus liquids.
- Paramount's 2015 capital budget totals $400 million, focused on the Company's Deep Basin development and maintaining the optionality of future growth initiatives.
- The Company is continuing planning and detailed engineering work for the construction of incremental natural gas processing capacity in the Deep Basin. We have temporarily deferred the ordering of long-lead-time items until summer. Paramount expects that the first new 100 MMcf/d plant would be on-stream 18 to 22 months following the placement of long-lead-time orders. The second new 100 MMcf/d plant is expected to commence operations 9 to 12 months after the first.
- Paramount expects to fund its 2015 capital program with increasing funds flow from operations and available capacity under its bank credit facility. The Company's capital budget remains flexible and activity levels may be adjusted depending on commodity prices and other factors.
- Paramount's revolving bank credit facility was increased to $900 million in December 2014 and the maturity date was extended to November 2016.
- The Company's coverage ratios improved in 2014 as a result of the start-up of the Musreau Deep Cut Facility and are expected to continue to strengthen in 2015 due to further growth in sales volumes and cash flows, despite the plunge in commodity prices.
- There are no financial maintenance covenants under the terms of Paramount's bank credit facility or its senior unsecured notes.
- In February 2015, Moody's Investors Services affirmed Paramount's corporate credit rating of B2, Positive Outlook and Standard & Poor's Rating Services upgraded Paramount's corporate credit rating to B, Positive Outlook.
|FINANCIAL AND OPERATING HIGHLIGHTS (1)|
|($ millions, except as noted)||Q4 2014||Q4 2013||%
|Natural gas (MMcf/d)||143.9||102.5||40||110.5||106.1||4|
|Condensate and oil (Bbl/d)||5,320||2,530||110||3,986||2,313||72|
|Other NGLs (Bbl/d) (3)||5,123||674||660||2,128||911||134|
|Petroleum and natural gas sales||99.4||57.8||72||350.0||232.5||51|
|Funds flow from operations||41.6||18.3||127||141.0||70.6||100|
|Per share - diluted ($/share)||0.40||0.19||1.39||0.75|
|Net income (loss)||(106.5)||0.3||(71.7)||(59.1)||(21)|
|Per share - diluted ($/share)||(1.02)||-||(0.71)||(0.63)|
|Principal Properties Capital (4)||224.6||171.8||31||813.9||612.8||33|
|Cash proceeds from divestitures (5)||0.5||8.3||(94)||100.0||37.9||164|
|Investments in other entities - market value (6)||256.9||688.5||(63)|
|Common shares outstanding (thousands)||104,844||96,993||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.
(2) Amounts include the results of discontinued operations. Refer to Paramount's Management's Discussion and Analysis for the year ended December 31, 2014.
(3) Other NGLs means ethane, propane and butane.
(4) Principal Properties Capital includes capital expenditures and geological and geophysical costs related to the Company's Principal Properties, and excludes land acquisitions and capitalized interest.
(5) Excludes shares of other companies and/or properties received in consideration for properties sold.
(6) Based on the period-end closing prices of publicly-traded investments and the book value of the remaining investments.
|RESERVES HIGHLIGHTS (1)(2)|
|Proved||Proved & Probable|
|Natural gas (Bcf)||703.8||301.3||134||1,090.9||450.5||142|
|Light and Medium crude oil (MBbl)||1,108||680||63||1,526||885||72|
|Total Conventional (MBoe)||226,812||87,677||159||347,085||133,813||159|
|Oil sands bitumen (MBbl)||-||-||-||93,468||93,468||-|
|Total Company (MBoe)||226,812||87,677||159||440,553||227,281||94|
|Conventional F&D costs|
|Excluding facilities & gathering ($/Boe) (3)||19.72||17.79||11||14.29||10.87||31|
|Conventional reserves replacement||17 X||6 X||183||25 X||8 X||213|
|NPV10 future net revenue before tax ($ millions)|
|(1) Readers are referred to the advisories concerning Oil and Gas Measures and Definitions in the Advisories section of this document.
(2) Reserves evaluated by the Company's independent reserves evaluator, McDaniel & Associates Consultants Ltd. as of December 31, 2014 in accordance with National Instrument 51-101 definitions, standards and procedures. Amounts are working interest reserves before royalty deductions. Net present values were determined using forecast prices and costs and do not represent fair market value.
(3) P+P F&D costs, excluding facilities and gathering capital, were $10.87 per Boe in 2013 and $12.18 per Boe in 2012 and the three-year average for the period 2012 to 2014 is $13.37 per Boe.
Paramount is an independent, publicly traded, Canadian corporation that explores for and develops conventional petroleum and natural gas prospects, pursues longer-term non-conventional exploration and pre-development projects and holds 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 2014 annual report, including Management's Discussion and Analysis and the Company's Consolidated Financial Statements can be obtained at: download/2015+Mar+5.pdf
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 expected first month production volumes from the Company's inventory of behind-pipe wells);
- forecast capital expenditures;
- exploration, development, and associated operational plans and strategies, and the anticipated timing of and sources of funding for such activities;
- anticipated increases in funds flow from operations and decreases in per unit operating costs;
- the further strengthening of the Company's financial coverage ratios that is expected to occur in 2015;
- projected timelines for constructing, and starting-up new and expanded natural gas processing and associated facilities;
- projected timelines for constructing and commissioning new drilling rigs;
- the projected availability of third party processing, transportation, de-ethanization, fractionation and other capacity;
- estimated reserves and the discounted present value of future net revenues therefrom; and
- 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, condensate, Other NGLs, oil and bitumen prices;
- royalty rates, taxes and capital, operating, general & administrative and other costs;
- foreign currency exchange rates and interest rates;
- general economic and business conditions;
- the ability of Paramount to obtain the required capital to finance its exploration, development and other operations;
- 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, condensate, Other NGLs, oil and bitumen 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 is reasonable, undue reliance should not be placed on it 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, condensate, Other NGLs, oil and bitumen 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, condensate, Other NGLs, oil and bitumen;
- 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);
- industry wide 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 at an acceptable cost to fund planned exploration, development and operational activities and meet current and future obligations (including costs of anticipated new and expanded facilities and other projects and product processing, transportation, de-ethanization, fractionation and similar commitments);
- 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.
In this document "Funds flow from operations", "Netback", "Net Debt", "Principal Properties Capital", "Investments in other entities - market value" and "Cash proceeds from divestitures", 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 operating activities before net changes in operating non-cash working capital, geological and geophysical expenses and asset retirement obligation settlements. 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. 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. 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 period for the calculation of Net Debt.
Principal Properties Capital includes capital expenditures and geological and geophysical costs related to the Company's Principal Properties, and excludes land acquisitions and capitalized interest. The Principal Properties Capital measure provides management and investors with information regarding the Company's Principal Properties spending on drilling and infrastructure projects separate from land acquisition activity. Refer to the Exploration and Capital Expenditures section of the Company's Management Discussion and Analysis. 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., MEG Energy Corp., Marquee Energy Ltd., 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. Cash Proceeds From Divestitures represents cash proceeds received by the Company on dispositions of oil and gas properties and excludes any non-cash consideration received. This measure is equivalent to Proceeds on Sale of Property, Plant and Equipment in the Company's Consolidated Statement of Cashflows.
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
This document contains disclosures expressed as "MMBoe", "MBoe", "Boe" and "Boe/d". All oil and 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. During 2014, the value ratio between crude oil and natural gas was approximately 18:1. 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. The term "liquids" is used to represent oil and natural gas liquids ("NGLs") volumes. The term "Other NGLs" means ethane, propane and butane.
Test rates for the wells fracked on the Company's 3-20 ten-well pad averaged 10.8 MMcf/d of natural gas per well, and are the average of production test rates over the final period of post clean-up flow-back at the largest choke setting, with durations of between 5 and 53 hours. Flow-back casing pressures for the tests ranged between approximately 2,200 psi and 3,000 psi. Test rates for the wells fracked on the Company's 8-22 ten-well pad averaged 13.0 MMcf/d of natural gas per well, and are the average of production test rates over the final period of post clean-up flow-back at the largest choke setting, with durations of between 4 and 30 hours. Flow-back casing pressures for the tests ranged between approximately 2,000 psi and 2,900 psi.
All 20 of the wells on these two ten-well pads were stimulated using frack oil and substantially all fluids recovered during the test periods were load fluids. As a result, fluid volumes recovered during the tests have not been disclosed. Pressure transient analyses and well-test interpretations have not been carried out for these wells and as such, data should be considered to be preliminary until such analysis or interpretation has been done. Test results are not necessarily indicative of long-term performance or of ultimate recovery.
Wellhead condensate-gas ratios ("CGRs") for the three wells on the 3-20 pad were calculated for each well for the period commencing on the date load oil volumes were completely recovered for such well and ending on February 28, 2015 (the "Post-load Recovery Period"). CGRs were calculated for each well over its applicable Post-load Recovery Period by dividing total raw liquids volumes produced by total raw natural gas volumes produced during such period. Raw volumes as measured at the wellhead. Sales volumes are lower due to shrinkage.
Conventional reserve estimates include nominal amounts of volumes and future net revenues related to Paramount's completed shale gas well. The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the effects of aggregation. In addition, estimates of future net revenue do not represent fair market value.
Finding and Development ("F&D") costs exclude capital costs and reserve volumes related to oil sands and exploratory shale gas properties within Paramount's Strategic Investments business segment because the relationship between capital amounts invested and reserve volumes discovered for such properties is not comparable to conventional oil and gas properties.
The reserves replacement disclosure herein was calculated as the net increase in proved and proved and probable reserves estimates from extensions and discoveries, technical revisions and economic factors divided by the Company's total production in the period.
Behind-pipe wells includes new wells that have been rig-released but have not been placed on production, including wells that have not been completed, wells that have been completed but not yet tied-in and wells that have been completed and tied-in. Estimated volumes are based on the Company's applicable type curves for each well, which vary depending location and formation.