Paramount Resources Ltd. Reports 2019 Annual Results and Provides 2020 Guidance

March 4, 2020 12:00 PM

CALGARY – HIGHLIGHTS

Annual sales volumes averaged 82,394 Boe/d (39 percent liquids) in 2019. Fourth quarter 2019 sales volumes averaged 85,411 Boe/d (42 percent liquids).^⁽¹⁾
Cash from operating activities was $256 million in 2019. Adjusted funds flow in 2019 was $299 million or $2.29 per share. Fourth quarter 2019 adjusted funds flow was $93.5 million or $0.71 per share.⁽²⁾
Strong execution and a continued focus on cost control resulted in lower per well capital costs at both Karr and Wapiti. This allowed the Company to accelerate the drilling of two five-well pads and a water disposal well at Karr into the fourth quarter of 2019 (from the first quarter of 2020) and construct a crude oil terminal in the Kaybob Region in 2019, while still maintaining its 2019 base capital budget of $350 million. ^⁽²⁾
Base capital spending in 2019 totalled $351 million. The Company spent $29 million on abandonment and reclamation activities in 2019 compared to guidance of $32 million. Net cash proceeds from dispositions in 2019 totalled $393 million.
At Karr, 5 (5.0 net) new Montney wells on the 4-24 pad were brought on production in the third quarter of 2019, averaging 1,047 Bbl/d per well of raw wellhead liquids (1,635 Boe/d raw wellhead total) over the first five months of production, resulting in an average condensate to gas ratio (“CGR”) of 298 Bbl/MMcf.⁽³⁾ In the fourth quarter of 2019, 3 (3.0 net) new Montney wells on the 1-19 pad were brought on production, averaging 1,542 Boe/d per well of gross peak 30-day production, with an average CGR of 486 Bbl/MMcf.⁽³⁾Fourth quarter sales volumes at Karr averaged 24,943 Boe/d (54 percent liquids).
At Wapiti, 11 (11.0 net) new Montney wells on the 9-3 pad were brought on production in 2019, but at restricted rates due to continued intermittent operations at the third-party Wapiti natural gas processing facility (the “Wapiti Plant”). All 12 (12.0 net) new Montney wells on the 5-3 pad were temporarily brought-on production through inline test facilities to recover completion fluids in late 2019. Two of these wells were later brought on production through permanent facilities. Currently, six of these wells are on production. Fourth quarter sales volumes at Wapiti averaged 11,498 Boe/d (66 percent liquids).
- To date, average well performance at Wapiti has exhibited higher liquids production and lower natural gas production than originally anticipated. As a consequence, additional debottlenecking activities are planned for the second half of 2020 in order to accommodate higher fluid handling requirements.
- Sales volumes have been, and continue to be, impacted by curtailment and reliability issues at the Wapiti Plant. The Company has lowered its run-time assumptions to account for this in 2020.
Paramount completed the construction of a crude oil terminal in the Kaybob Region in the fourth quarter of 2019. This terminal is pipeline connected and has been commissioned and placed into service. It will provide Paramount the opportunity to increase netbacks for its Kaybob area crude and condensate volumes (including volumes which were until recently being trucked to third-party terminals) and capture incremental value in price differentials. Total capital expenditures associated with this project were approximately $13 million.
Paramount closed the sale of its Karr 6-18 facility for gross cash proceeds of $332 million in August 2019. In December 2019, Paramount also closed the sale of certain natural gas-weighted properties in West Central Alberta for gross cash proceeds of $52 million.
In 2019, the Company commenced its first area-based closure (“ABC”) abandonment and reclamation projects at both Hawkeye and Zama. Economies of scale gained under the ABC programs have resulted in significantly lower costs than prior estimates. In addition, property dispositions coupled with additional abandonment and reclamation spending in 2019 further reduced the Company’s asset retirement obligations (“ARO”). Paramount’s discounted ARO liability at December 31, 2019 was approximately $238 million lower than at year-end 2018.

_________________________________
(1)	See “Oil and Gas Measures and Definitions” in the Advisories section.
(2)	“Adjusted funds flow” and “base capital” are Non-GAAP measures. See “Non-GAAP Measures” in the Advisories section.
(3)	Production measured at the wellhead. Natural gas sales volumes are lower by approximately 10 percent and wellhead liquids sales volumes are lower by approximately 12 percent due to shrinkage, under normalized operations. 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 or of ultimate recovery from the wells. CGRs calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See Oil and Gas Measures and Definitions in the Advisories section.

2020 GUIDANCE

The Company’s capital budget for 2020 is expected to range between $350 million and $450 million, excluding land acquisitions and abandonment and reclamation activities, assuming average benchmark commodity prices of US$55.00/Bbl for WTI and CDN$1.80/GJ for AECO natural gas and a $0.76 CDN/US exchange rate. The capital plan remains flexible, with the lower end of the range reflecting the deferral of capital expenditures largely associated with production benefits in 2021. Activities denoted as “contingent” in the descriptions below highlight these activities. The 2020 program is largely focused on the ongoing development of Karr and Wapiti, where the Company plans to continue to grow its Montney production, resulting in higher liquids contribution and per-unit netbacks. Recently, world oil prices have been adversely affected by uncertainty surrounding the economic impact of the COVID-19 (Coronavirus) outbreak. The Company is committed to prudently managing its capital resources and may adjust its capital plans depending on commodity prices and other factors. Paramount may also determine to divest of assets or investments in securities to raise capital to reduce indebtedness or fund operations.
- Activities at Karr in 2020 will focus on drilling and completion operations. Drilling operations on two five-well pads commenced in late 2019, with drilling of a third five-well pad and a contingent four-well pad planned in 2020. These 19 (19.0 net) new Montney wells (4 (4.0 net) of which are contingent) are planned to be staged and brought on production starting in the third quarter of 2020 following the completion of the Karr 6-18 facility expansion by the third-party owner. Paramount also plans to bring into service 3 (3.0 net) water disposal wells at Karr.
- At Wapiti, Paramount plans to drill a total of 13 (13.0 net) new Montney wells and complete and bring onstream a five-well pad and a contingent eight-well pad. A tenure well that was drilled and completed in 2015 is also scheduled to be brought onstream in 2020. Drilling operations on 6 (6.0 net) additional new Montney wells on the contingent 6-27 pad are planned to commence in late 2020. In addition, several liquids debottlenecking initiatives are planned to alleviate second half 2020 fluid handling constraints.
Paramount’s December 2019 sales volumes averaged approximately 80,000 Boe/d following the December 2019 disposition of Central Alberta and Other Region assets that had sales volumes of approximately 8,350 Boe/d.
Paramount’s 2020 annual sales volumes are expected to average between 75,000 Boe/d and 80,000 Boe/d (43 percent liquids).
- Sales volumes are anticipated to average between 70,000 Boe/d and 74,000 Boe/d in the first half of 2020. Early 2020 production was impacted by extremely cold weather conditions that resulted in unscheduled third-party outages and well freeze offs. More significantly, Wapiti sales volumes were impacted by the unscheduled full shut-down of the Wapiti Plant (due to an electrical failure) for approximately two weeks in January and are expected to be further impacted by an additional scheduled 7-day outage in March. There are two significant scheduled expansion-related outages, totaling two weeks, during the second quarter at the third-party Karr 6-18 facility. Production from a number of older pads at Karr has been temporarily backed out, which is also contributing to lower first half production. Paramount plans to install compression and pumping to minimize these impacts for the second half of 2020. There are also four scheduled turnarounds at other facilities in the Kaybob and Central Alberta and Other Regions planned during the second quarter of 2020.
- Paramount expects production growth to resume in the second half of the year as volumes ramp up at Karr following the completion of the third-party Karr 6-18 facility expansion and as additional wells are brought onstream at Wapiti. Fourth quarter sales volumes are expected to average between 84,000 Boe/d and 90,000 Boe/d.
- Average annual sales volumes would be impacted by approximately 1,000 Boe/d by the deferral of contingent capital expenditures.
The Company has budgeted $39 million for abandonment and reclamation activities in 2020, the majority of which will be directed to Hawkeye and Zama. Over the course of the year, approximately 238 inactive wells are planned to be abandoned.

RESERVES ⁽¹⁾

Despite the disposition of assets in the Central Alberta and Other Region in December 2019, Paramount’s 2019 proved plus probable (ʺP+Pʺ) reserves were relatively unchanged at 632 MMBoe compared to 634 MMBoe in 2018. The liquids weighting of the Company’s 2019 P+P reserves increased to 47 percent (from 43 percent in 2018).
Paramount’s proved reserves decreased 14 percent to 335 MMBoe in 2019 compared to 391 MMBoe in 2018. The decrease was primarily a result of dispositions and changes in future development capital (primarily in the Kaybob Region).
The Company’s reserves replacement ratio was 1.5 times for P+P reserves, net of dispositions.
Total proved plus probable developed reserves were 151 MMBoe in 2019, with an estimated net present value of future net revenue of $1.2 billion (discounted at 10 percent, before tax).
P+P finding and development costs were $10.28 per Boe in 2019.
The Company’s estimated net present value of future net revenue at December 31, 2019 totalled $4.5 billion for P+P reserves, up approximately eight percent from December 31, 2018, and $2.4 billion for proved reserves, up approximately 14 percent from December 31, 2018 (in each case discounted at 10 percent, before tax). The increase in net present value of future net revenue is mainly attributed to the Company’s higher liquids weighting and the optimization of future capital spending.

________________________________

(1)

Readers are referred to the advisories concerning “Reserves Data” and “Oil and Gas Measures and Definitions” in the Advisories section of this document. Reserves evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”) as of December 31, 2019 and December 31, 2018 in accordance with National Instrument 51-101 definitions, standards and procedures. Reserves are gross reserves representing working interest before royalties. Net present values of future net revenue were determined using forecast prices and costs and do not represent fair market value.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE

Paramount is committed to creating value for our shareholders and stakeholders in an environmentally and socially responsible manner. Environmental, Social and Governance (“ESG”) information with respect to Paramount can be found on our website at http://www.paramountres.com. As part of our ESG program:
- Paramount participates in the ABC program introduced by the Alberta Energy Regulator that allows companies to undertake abandonment and reclamation activities in an efficient and cost-effective manner by targeting efforts in concentrated areas. Pursuant to this program Paramount has permanently suspended operations at its legacy Zama and Hawkeye fields and commenced abandonment and reclamation activities in both these areas. The Company abandoned 104 wells in 2019, 84 of which were at Zama and Hawkeye. The Company plans to abandon 238 wells in 2020, including 93 wells at Zama and the remaining 135 wells at Hawkeye.
- In 2018 and 2019 Paramount replaced approximately 1,700 high-bleed controllers at various sites with modern low-bleed units, eliminating approximately 120,000 tonnes per year of GHG emissions.

CORPORATE

Paramount’s average realized natural gas sales price was $2.36/Mcf in 2019, 45 percent higher than AECO monthly index prices for the year, as a result of the Company’s natural gas diversification strategy.
Paramount’s natural gas sales diversification strategy includes arrangements to sell approximately 60,000 GJ/d of natural gas at Dawn, approximately 22,000 GJ/d of natural gas at Malin, and 40,000 GJ/d of natural gas sales priced in the US Midwest. The Company also has AECO fixed-price physical contracts in place to sell 50,000 GJ/d of natural gas at $2.36/GJ for winter 2020 and 80,000 GJ/d of natural gas at $1.61/GJ for summer 2020.
Paramount has 4,000 Bbl/d of oil hedged in 2020 at an average price of CDN$80.11/Bbl.
In November 2019, Paramount completed a private placement of approximately 5.9 million common shares, issued on a ʺflow-throughʺ basis in respect of Canadian development expenses, at a price of $6.65 per share for gross proceeds of approximately $39.2 million.
The Company’s long-term debt balance at December 31, 2019 was $632 million. Paramount has a $1.5 billion covenant-based bank credit facility that matures in November 2022.
The Company purchased a total of 2.6 million common shares for cancellation under its 2019 normal course issuer bid program at an average price of $5.47 per share. In January 2020, Paramount implemented a new normal course issuer bid program under which the Company may purchase up to 7.0 million common shares for cancellation.

FINANCIAL AND OPERATING RESULTS ⁽¹⁾
($ millions, except as noted)

	Three months ended December 31				Twelve months ended December 31
	2019		2018		2019		2018
Net income (loss)	(31.1)		(170.5)		(87.9)		(367.2)
per share – basic and diluted ($/share)	(0.24)		(1.31)		(0.67)		(2.78)
Cash from operating activities	70.5		12.4		255.7		223.4
per share – basic and diluted ($/share)	0.54		0.10		1.96		1.69
Adjusted funds flow	93.5		45.5		299.0		263.9
per share – basic and diluted ($/share)	0.71		0.35		2.29		2.00
Total assets					3,531.3		4,118.1
Long-term debt					632.3		815.0
Net debt					703.5		896.0
Common shares outstanding (thousands) ⁽²⁾					133,337		130,326

Sales volumes
Natural gas (MMcf/d)	299.0		315.2		303.3		325.9
Condensate and oil (Bbl/d)	28,516		24,898		25,079		24,238
Other NGLs (Bbl/d) ⁽³⁾	7,064		7,059		6,767		7,386
Total (Boe/d)	85,411		84,495		82,394		85,941
*% liquids*	42%		37%		39%		37%
Grande Prairie Region (Boe/d)	36,789		26,976		29,040		26,059
Kaybob Region (Boe/d)	33,167		37,262		35,500		39,004
Central Alberta and Other Region (Boe/d)	15,455		20,257		17,854		20,878
Total (Boe/d)	85,411		84,495		82,394		85,941

Netback		$/Boe ⁽⁴⁾		$/Boe ⁽⁴⁾		$/Boe ⁽⁴⁾		$/Boe ⁽⁴⁾
Natural gas revenue	75.1	2.73	79.2	2.73	261.0	2.36	267.1	2.25
Condensate and oil revenue	175.0	66.70	104.3	45.54	610.2	66.66	599.9	67.81
Other NGLs revenue ⁽³⁾	8.5	13.03	20.4	31.39	37.7	15.24	82.7	30.67
Royalty and sulphur revenue	1.3	─	3.5	─	6.0	─	15.8	─
Petroleum and natural gas sales	259.9	33.08	207.4	26.68	914.9	30.42	965.5	30.78
Royalties	(17.2)	(2.19)	(8.0)	(1.03)	(63.3)	(2.10)	(69.2)	(2.21)
Operating expense	(105.0)	(13.36)	(103.2)	(13.28)	(376.0)	(12.50)	(381.0)	(12.15)
Transportation and NGLs processing ⁽⁵⁾	(22.8)	(2.90)	(24.2)	(3.11)	(94.7)	(3.15)	(93.0)	(2.96)
Netback	114.9	14.63	72.0	9.26	380.9	12.67	422.3	13.46
Commodity contract settlements	4.7	0.60	(9.3)	(1.20)	13.2	0.44	(76.5)	(2.44)
Netback including commodity contract settlements	119.6	15.23	62.7	8.06	394.1	13.11	345.8	11.02

Base Capital ⁽⁶⁾
Grande Prairie Region	60.7		48.1		256.7		265.7
Kaybob Region	9.5		35.6		80.7		215.7
Central Alberta and Other Region	0.6		16.3		7.6		40.9
Corporate	─		2.5		6.0		10.8
Total	70.8		102.5		351.0		533.1

Asset retirement obligations settlements	18.0		8.9		29.4		29.4


(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: Adjusted Funds Flow, Net Debt, Netback, and Base Capital.
(2)	Common shares are presented net of shares held in trust under the Company’s restricted share unit plan (000’s of common shares): 2019: 857.9; 2018: 574.0.
(3)	Other NGLs means ethane, propane and butane.
(4)	Natural gas revenue presented as $/Mcf.
(5)	Includes downstream transportation costs and NGLs fractionation costs.
(6)	Excludes spending related to the expansion of the Karr 6-18 facility prior to its sale, land and property acquisitions

RESERVES ⁽¹⁾

	Proved			Proved plus Probable
	2019	2018	% Change	2019	2018	% Change
Natural gas (Bcf)	1,059.5	1,366.6	(22)	1,993.8	2,169.2	(8)
NGLs (MBbl) ⁽²⁾	141,238	146,791	(4)	264,917	238,325	11
Crude oil (MBbl)	16,997	16,130	5	34,875	34,550	1
Total (MBoe)	334,817	390,688	(14)	632,097	634,403	─

Future Net Revenue NPV₁₀ ($ millions)	2,427	2,136	14	4,478	4,134	8


(1)	Readers are referred to the advisories concerning “Reserves Data” and “Oil and Gas Measures and Definitions” in the Advisories section of this document. Reserves evaluated by McDaniel & Associates Consultants Ltd. (“McDaniel”) as of December 31, 2019 and December 31, 2018 in accordance with National Instrument 51-101 definitions, standards and procedures. Reserves are gross reserves representing working interest before royalties. Net present values of future net revenue were determined using forecast prices and costs and do not represent fair market value.
(2)	Includes ethane, propane, butane, pentanes-plus, and condensate.

APPOINTMENT OF CHIEF FINANCIAL OFFICER

The Board of Directors of Paramount is pleased to announce the appointment of Paul Kinvig to the role of Chief Financial Officer. Paul has most recently served as Paramount’s Vice President Finance, Capital Markets and has held roles of increasing responsibility in Paramount’s finance area throughout his 15 years with the Company. Bernie Lee will continue to serve as Executive Vice President, Finance of the Company. The Board recognizes and appreciates the significant contributions that Bernie Lee has made as Chief Financial Officer to Paramount’s success over the last 17 years and looks forward to his continuing contributions.

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 reserves and resources, including longer-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 2019 annual results, including the Review of Operations, Management’s Discussion and Analysis and the Company’s Consolidated Financial Statements can be obtained at: https://mma.prnewswire.com/media/1099299/Paramount_Resources_Ltd__Paramount_Resources_Ltd__Reports_2019_A.pdf

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

[expand title=”Advisories & Contact”]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 2020 and certain periods within 2020;
planned capital expenditures for 2020 and potential changes thereto;
planned abandonment and reclamation activities and expenditures for 2020;
planned exploration, development and production activities;
the expected completion of the 6-18 facility expansion and the timing thereof;
planned continued growth of Montney production at Karr and Wapiti, including increasing liquids contribution and per unit netbacks;
the timing of the alleviation of fluid handling constraints at Wapiti; and
planned facility outages and turnarounds.

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 and the capacity and reliability of facilities;
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, the construction, commissioning and start-up of new and expanded facilities, including third-party facilities and facility turnarounds and maintenance).

Statements relating to reserves are also deemed to be forward looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

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 capital spending plans and planned exploration and development activities;
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, 2019, 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”, “Base capital”, “Netback” and “Net Debt”, together 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, dispute settlements 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. Asset retirement obligation settlements are excluded from the calculation of adjusted funds flow because such expenditures are not directly linked to the revenue generating activities of the Company. Paramount manages the timing of expenditures related to asset retirement obligation settlements in accordance with regulatory requirements and its overall approach to managing its asset retirement obligations and, as a result, amounts incurred may vary from period to period. Adjusted funds flow is not intended to represent cash from operating activities, net loss or any other GAAP measure and should not be construed as being an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS. The following are the calculations of adjusted funds flow from the nearest GAAP measure for the years ended December 31, 2019 and December 31, 2018 and for the three months ended December 31, 2019 and December 31, 2018:

Year ended December 31, 2019	2019 (MM$)	2018 (MM$)
Cash from operating activities	255.7	223.4
Change in non-cash working capital	(15.9)	(7.0)
Geological and geophysical expenses	11.0	12.5
Asset retirement obligations settled	29.4	29.4
Closure costs	14.0	–
Transaction and reorganization costs	2.3	5.6
Dispute settlements	2.5	–
Adjusted funds flow	299.0	263.9

Three months ended December 31, 2019	2019 (MM$)	2018 (MM$)
Cash from operating activities	70.4	12.4
Change in non-cash working capital	(7.9)	21.2
Geological and geophysical expenses	3.5	1.9
Asset retirement obligations settled	18.0	8.9
Closure costs	4.7	–
Transaction and reorganization costs	2.3	1.1
Dispute settlements	2.5	–
Adjusted funds flow	93.5	45.5

“Base 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 the expansion of the Karr 6-18 facility prior to its sale and land and property acquisitions. The base 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. The following is a reconciliation of base capital from the nearest GAAP measure for the years ended December 31, 2019 and December 31, 2018:

	2019 (MM$)	2018 (MM$)
Property, plant and equipment and exploration	404.1	580.2
Karr 6-18 facility expansion	(45.5)	(35.9)
Land and property acquisitions	(7.6)	(11.2)
Base capital	351.0	533.1

“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 table under the heading “Financial and Operating Results” for the calculation thereof.

“Net Debt” 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.

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.

Reserves Data

Reserves data set forth in this press release is based upon an evaluation of the Company’s reserves prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”) dated March 3, 2020 and effective December 31, 2019 (the “McDaniel Report”). The price forecast used in the McDaniel Report is an average of the January 1, 2020 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the December 31, 2019 price forecast of Sproule Associates Ltd. The estimates of reserves contained in the McDaniel Report and referenced in this press release are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates contained in the McDaniel Report and referenced in this press release. There is no assurance that the forecast prices and costs assumptions used in the McDaniel Report will be attained, and variances could be material. Estimated future net revenue does not represent fair market value. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. Readers should refer to the Company’s annual information form for the year ended December 31, 2019, which is available on SEDAR at www.sedar.com, for a complete description of the McDaniel Report and the material assumptions, limitations and risk factors pertaining thereto.

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
Bbl			Barrels	GJ	Gigajoules
Bbl/d			Barrels per day	GJ/d	Gigajoules per day
MBbl			Thousands of barrels	Mcf	Thousands of cubic feet
NGLs			Natural gas liquids	MMcf	Millions of cubic feet
Condensate			Pentane and heavier hydrocarbons	MMcf/d	Millions of cubic feet per day
				AECO	AECO-C reference price
Oil Equivalent				WTI	West Texas Intermediate
Boe		Barrels of oil equivalent
MBoe	Thousands of barrels of oil equivalent
MMBoe	Millions of barrels of oil equivalent
Boe/d	Barrels of oil equivalent per day

This press release contains disclosures expressed as “Boe”, “$/Boe”, “MBoe”,”MMBoe” 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 year ended December 31, 2019, the value ratio between crude oil and natural gas was approximately 45:1. 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. The metrics are “CGR”, “reserves replacement ratio” and “finding and development costs”. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. Management uses these 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.

“CGR” means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes.

“Reserves replacement ratio” is calculated by dividing: (i) the aggregate changes in reserves from the prior year from extensions and discoveries, technical revisions and economic factors, by (ii) the aggregate production during the year. Reserves replacement ratio is a measure commonly used by management and investors to assess the rate at which reserves depleted by production are being replaced by reserves added through operations.

“Finding and development costs” are calculated by dividing: (i) the sum of the total base capital expenditures for the year excluding corporate expenditures, and net changes in estimated future development costs from the prior year excluding those associated with the Karr 6-18 facility, by (ii) the net changes to reserves from the prior year before production. Finding and development costs are a measure commonly used by management and investors to assess the relationship between capital invested in oil and gas exploration and development projects and reserve additions associated with such projects.

Additional information respecting the Company’s oil and gas properties and operations, including a breakdown of 2019 annual and quarterly production volumes by product type, is provided in the Company’s annual information form for the year ended December 31, 2019 which is available on SEDAR at www.sedar.com.

[/expand]

Paramount Resources Ltd. Reports 2019 Annual Results and Provides 2020 Guidance

Latest Headlines