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Parex Resources Inc. — Interim / Quarterly Report 2021
May 5, 2021
46494_rns_2021-05-05_acbf9ac2-c528-41d2-ba9c-ae65c30094c2.pdf
Interim / Quarterly Report
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MANAGEMENT’S DISCUSSION AND ANALYSIS
The following Management’s Discussion and Analysis (“MD&A”) of the financial condition and results of operations of Parex Resources Inc. (“Parex” or “the Company”) for the period ended March 31, 2021 is dated May 5, 2021 and should be read in conjunction with the Company’s unaudited condensed interim consolidated financial statements for the period ended March 31, 2021, as well as the Company’s audited consolidated annual financial statements for the year ended December 31, 2020. The unaudited condensed interim consolidated financial statements and the audited consolidated annual financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board.
Additional information related to Parex and factors that could affect the Company’s operations and financial results are included in reports on file with Canadian securities regulatory authorities, including the Company’s Annual Information Form dated March 3, 2021 (“AIF”), and may be accessed through the SEDAR website at www.sedar.com.
All financial amounts are in United States (US) dollars unless otherwise stated.
Company Profile
Parex is an oil and gas company actively engaged in crude oil exploration, development and production in Colombia. Headquartered in Calgary, Canada, Parex, through its foreign subsidiaries, holds interests in onshore exploration and production blocks. The common shares of the Company trade on the Toronto Stock Exchange (“TSX”) under the symbol PXT.
Abbreviations
Refer to the end of the MD&A for commonly used abbreviations in the document. Refer to the Advisory on Forward-Looking Statements and Non-GAAP Terms used.
Three months ended March 31, 2021 (“first quarter or Q1”) Highlights
-
Quarterly average production was 46,779 boe/d (96% crude oil), an increase of approximately 3% on a per basic share basis over the previous quarter ended December 31, 2020. Production decreased 6% on a per basic share basis over the prior year comparative period as a result of the Company reducing capital investment in the low oil price pandemic environment of 2020. Refer to "Consolidated Results of Operations" for production split by product type;
-
Recognized net income of $47.5 million ($0.37 per share basic) compared to net income of $56.2 million ($0.42 per share basic) in the previous quarter ended December 31, 2020 and a net loss of $3.8 million ($0.03 per share basic) in the comparative quarter of 2020;
-
Generated an operating netback of $37.38/boe (2020 - $24.41/boe) and funds flow provided by operations ("FFO") netback of $29.98/boe (2020 - $20.63/boe) from an average Brent price of $61.32/bbl (2020 - $51.05/bbl);
-
Funds flow provided by operations were $125.0 million ($0.96 per share basic) as compared to funds flow provided by operations of $97.3 million ($0.69 per share basic) for the prior year comparative period; FFO increased in the current quarter due to higher global oil prices;
-
Capital expenditures were $39.6 million compared to $71.3 million in the comparative period of 2020;
-
Utilized a portion of free funds flow of $85.4 million to purchase and cancel 3,501,685 of the Company's common shares for a total cost of $60.1 million (average price of Cdn$21.11/share) pursuant to the Company's normal course issuer bid ("NCIB") program;
-
Working capital was $341.7 million at March 31, 2021 compared to $320.2 million at December 31, 2020 and $330.4 million at March 31, 2020. The Company has an undrawn syndicated bank credit facility of $200.0 million; and
-
Participated in drilling 9 gross (5.05 net) wells in Colombia resulting in 6 oil wells, 1 disposal well, 1 well under test and 1 well abandoned prior to total depth, for a success rate of 86% compared to drilling 20 gross (13.05 net) wells in the comparative period of 2020.
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1
March 31, 2021
Financial Summary
| For the three | months | |
|---|---|---|
| ended March 31, | ||
| (Financial figures in$'000s exceptper share amounts) | 2021 | 2020 |
| Light Crude Oil and Medium Crude Oil (bbl/d) | 8,131 | 8,380 |
| Heavy Crude Oil (bbl/d) | 36,948 | 44,657 |
| Average daily oil production (bbl/d)(1) | 45,079 | 53,037 |
| Average daily conventional natural gas production (mcf/d)(1) | 10,200 | 7,548 |
| Average oil and natural gas production (boe/d) | 46,779 | 54,295 |
| Production split (% crude oil) | 96 | 98 |
| Realized sales price ($/boe) | 52.80 | 38.47 |
| Operating netback ($/boe)(2) | 37.38 | 24.41 |
| Oil and natural gas sales | 222,058 | 193,618 |
| Funds flow provided by operations(2) | 124,969 | 97,313 |
| Per share – basic(2) | 0.96 | 0.69 |
| Per share – diluted(2) | 0.96 | 0.68 |
| Net income (loss) | 47,460 | (3,779) |
| Per share – basic | 0.37 | (0.03) |
| Per share – diluted | 0.36 | (0.03) |
| Capital expenditures | 39,592 | 71,266 |
| Free funds flow(2) | 85,377 | 26,047 |
| Total assets (end of period) | 1,550,441 | 1,610,341 |
| Working capital surplus (end of period)(3) | 341,686 | 330,356 |
| Bank debt (end of period)(4) | — | — |
| Weighted average shares outstanding (000s) | ||
| Basic | 129,715 | 141,805 |
| Diluted | 130,856 | 143,996 |
| Outstanding shares (end of period) (000s) | 128,589 | 139,801 |
(1) Reference to crude oil or natural gas production in the above table and elsewhere in this MD&A refer to the light crude oil and medium crude oil and heavy crude oil and conventional natural gas, respectively, product types as defined in National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities. (2) Non-GAAP term. Refer to “Non-GAAP Terms”.
(3) Working capital calculation does not take into consideration the undrawn amount available under the Company's syndicated bank credit facility (“credit facility”). (4) Credit facility borrowing base of $200.0 million as at March 31, 2021.
2021 Corporate Guidance
As per the Company's normal annual disclosure practices, provided below is Parex' corporate guidance for 2021:
| 2020 Results 2021 Guidance |
2020 Results 2021 Guidance |
2020 Results 2021 Guidance |
|---|---|---|
| Production(average forperiod) | 46,518 boe/d(2) | 47,000-49,000 boe/d |
| Total capital expenditures(1) | $141 million | $250-$270 million |
| Current tax effective rate on FFO at$65/bbl Brent | — | 16-18% |
| Share buy-backprogram (shares repurchased) | 13.9 million | 12.9 million |
| Outstandingshares(end ofperiod) | 131 million | 119-120 million |
(1) 2021 work program is dependent on ensuring the health and safety of staff and the communities where the Company operates, therefore, planned capital expenditures may only be partially completed.
(2) Consisting of 6,021 bbls/d of light crude oil and medium crude oil, 39,197 bbls/d of heavy crude oil and 7,800 mcf/d of conventional natural gas.
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2
March 31, 2021
Higher Brent oil prices to date in 2021 and Parex' unhedged oil price exposure are expected to contribute to a significant increase to Parex' 2021 FFO. With higher FFO, an increasing cash position and a debt-free balance sheet, Parex is strategically accelerating assessment of its portfolio of operated assets, through increasing exploration and appraisal activity to provide for a strengthened future development inventory.
The planned 2021 capital expenditures are split between maintenance, development/appraisal and exploration/new growth programs. The midpoint of the 2021 production guidance reflects year-over-year production growth of approximately 3% as compared to 2020 average production. The increased 2021 capital expenditure program, as announced by Parex on April 15, 2021, along with the share buy-back program discussed below, is expected to be fully funded from FFO.
The Company's 2021 priority remains the health and safety of its employees, partners and the communities where we operate. Parex will continue to be responsive to changes in commodity prices by managing its production volumes, capital budget and cash costs, further protecting its balance sheet and shareholder value.
Financial and Operational Results
Consolidated Results of Operations
Parex’ oil and gas operations are conducted in Colombia with head office functions conducted in Canada.
| For the three months | For the three months | For the three months | |||
|---|---|---|---|---|---|
| ended March 31, | |||||
| 2021 | 2020 | ||||
| Average daily production | |||||
| Light Crude Oil and Medium Crude Oil (bbl/d) | 8,131 | 8,380 | |||
| HeavyCrude Oil(bbl/d) | 36,948 | 44,657 | |||
| Crude oil (bbl/d) | 45,079 | 53,037 | |||
| Conventional Natural Gas(mcf/d) | 10,200 | 7,548 | |||
| Total(boe/d) | 46,779 | 54,295 | |||
| Production split (% crude oil production) | 96 | 98 | |||
| Average daily sales of oil and natural gas | |||||
| Produced crude oil (bbl/d) | 44,618 | 50,589 | |||
| Purchased crude oil (bbl/d) | 409 | 3,463 | |||
| Produced naturalgas(mcf/d) | 10,200 | 7,548 | |||
| Total(boe/d) | 46,727 | 55,310 | |||
| Operating netback (000s)(1) | |||||
| Oil and natural gas sales | $ | 222,058 | $ | 193,618 | |
| Royalties | **(25,571) ** | (22,217) | |||
| Net revenue | 196,487 | 171,401 | |||
| Production expense | (24,416) | (25,062) | |||
| Transportation expense | (14,438) | (20,336) | |||
| Purchased oil | **(2,583) ** | (10,241) | |||
| Operatingnetback | **$ ** | 155,050 | $ | 115,762 | |
| Operating netback (per boe)(1) | |||||
| Oil and natural gas sales | $ | 52.80 | $ | 38.47 | |
| Royalties | **(6.13) ** | (4.71) | |||
| Net revenue | 46.67 | 33.76 | |||
| Production expense | (5.86) | (5.31) | |||
| Transportation expense | **(3.43) ** | (4.04) | |||
| Operatingnetback | $ | 37.38 | $ | 24.41 |
(1) Refer to "Non-GAAP Terms" for a description and details of the operating netback calculation.
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3
March 31, 2021
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Change in Operating Netback by Component
Q1/20 vs. Q1/21
$45.00
$40.00 $14.33 $0.61 $37.38
$35.00 $(1.42) $(0.55)
$30.00
$24.41
$25.00
$20.00
$15.00
$10.00
$5.00
$0.00
Q1, 2020 Netback Revenue Royalties Production CostsTransportation Costs Q1, 2021 Netback
$ / boe
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Overall, the Company’s benchmark Brent crude oil price increased by $10.27/bbl, while revenue increased by $14.33/boe in the first quarter of 2021 as compared to the first quarter of 2020. The increase in revenue relative to the Brent crude benchmark increase is mainly the result of stronger Vasconia crude oil pricing (and thereby a lower differential to Brent oil price) and decreased wellhead oil sales in the quarter as compared to the comparative period. Royalties increased by $1.42/boe as a result of higher crude oil benchmark prices in the quarter. Production costs increased by $0.55/boe mainly as a result of increased well workovers in the current quarter on Block LLA-34 and also bringing back production on legacy fields where production costs are higher on a per bbl basis. Transportation costs decreased $0.61/boe mainly as a result of a change in sales mix as a higher percentage of crude was transported and exported in the prior period vs. sold at the wellhead. Also the tie-in of additional Block LLA-34 volumes to the Oleoductos de Los Llanos ("ODL") pipeline which carries a lower tariff than the cost of truck transport for this particular volume of crude has reduced transportation costs.
Overall, the operating netback increased by $12.97/boe vs a Brent benchmark crude increase of $10.27/bbl.
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Change in Operating Netback by Component
Q4/20 vs. Q1/21
$45.00 $15.85
$40.00 $0.31 $37.38
$35.00 $(2.94) $(0.60)
$30.00 $24.76
$25.00
$20.00
$15.00
$10.00
$5.00
$0.00
Q4, 2020 Netback Revenue Royalties Production CostsTransportation Costs Q1, 2021 Netback
$ / boe
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In the first quarter of 2021, the Company’s benchmark Brent oil price increased by $16.06/bbl, while revenue increased by $15.85/boe. The decrease in revenue relative to the Brent crude oil benchmark increase is mainly a result of increased well head sales in the quarter. Royalties increased by $2.94/boe as a result of higher crude oil benchmark prices in the quarter. Production costs increased by $0.60/boe mainly as a result of increased well workovers in the current quarter in Block LLA-34 and bringing back production on legacy fields where production costs are higher. Transportation costs decreased $0.31/boe mainly due to the tie-in of additional Block LLA-34 volumes to the ODL pipeline which carries a lower tariff than the cost of truck transport for this particular volume of crude.
Overall, the operating netback increased by $12.62/boe vs a Brent benchmark crude increase of $16.06/bbl.
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March 31, 2021
4
Oil and Natural Gas Sales
a) Average Daily Production and Sales Volumes (boe/d)
| For the three months | For the three months | ||
|---|---|---|---|
| ended March 31, | |||
| 2021 | 2020 | ||
| Block LLA-34 (Tigana, Jacana and Tua fields) | 30,392 | 39,303 | |
| Block Cabrestero (Bacano and Akira fields) | 5,853 | 5,233 | |
| Block Capachos (Capachos and Andina fields) | 4,719 | 3,140 | |
| Block LLA-26 (Rumba field) | 1,107 | 1,686 | |
| Block LLA-32 (Kananaskis, Calona, Carmentea and Azogue fields) | 1,206 | 1,974 | |
| Other | 1,802 | 1,701 | |
| Total Crude Oil Production | 45,079 | 53,037 | |
| Naturalgasproduction | 1,700 | 1,258 | |
| Total Crude oil and naturalgasproduction | 46,779 | 54,295 | |
| Crude oil inventory (build) | **(461) ** | (2,448) | |
| Average daily sales ofproduced oil and naturalgas | 46,318 | 51,847 | |
| Purchased oil | 409 | 3,463 | |
| Sales Volumes | 46,727 | 55,310 |
Oil and natural gas production for the first quarter of 2021 averaged 46,779 boe/d, a decrease of approximately 14% from the comparative first quarter of 2020 and comparable to the fourth quarter of 2020. In the third quarter of 2020 the Company began bringing back additional production from previously shut-in or curtailed fields. Further, in the first quarter of 2021 there was a higher downtime of production on Block LLA-34 which is expected to be reduced to more historic levels for the remainder of 2021. In the second quarter of 2020 production was voluntarily curtailed in response to the significant decline in world oil prices and ongoing uncertainty in market conditions resulting from the COVID-19 pandemic.
Oil and natural gas sales in the first quarter of 2021 were 46,727 boe/d compared to 55,310 boe/d for the first quarter of 2020. The decrease in oil sales was a result of the decrease in oil production and purchased oil purchases/sales over the comparative period.
Production
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55,000 98% 97% 97% 96% 96%
50,000
45,000
40,000
35,000
30,000
25,000
20,000
15,000
10,000
Q1/2020 Q2/2020 Q3/2020 Q4/2020 Q1/2021
Crude Oil (bbls/d) Natural gas (boe/d) Crude Oil Production as a % of Total Production
bbls/d or boe/d
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March 31, 2021
5
Production By Area (Three Months ended March 31, 2021)
Block LLA-34 : 70%
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Block Cabrestero : 14% Block LLA-26 : 3% Block LLA-32 : 3% Capachos : 11%
b) Crude Oil Reference and Realized Prices
| For the three months | For the three months | ||
|---|---|---|---|
| ended March 31, | |||
| 2021 | 2020 | ||
| Reference Prices | |||
| Brent ($/bbl) | 61.32 | 51.05 | |
| Vasconia ($/bbl) | 58.71 | 45.97 | |
| WTI($/bbl) | 58.13 | 46.10 | |
| Average Realized Prices | |||
| Realized salesprice($/boe) | 52.80 | 38.47 | |
| Realizedprice(differential)to Brent crude($/boe) | **(8.52) ** | (12.58) |
During Q1 2021, the differential between Brent reference pricing and the Company's realized sale price was $8.52/boe. The differential to Brent crude during Q1 2021 increased by $0.21/boe compared to the fourth quarter of 2020 where the differential was $8.31/boe (see below).
The table below provides a quarter-by-quarter view of Parex' historical oil pricing in Colombia:
| Averageprice for theperiod | Q1 2021 | Q4 2020 | Q3 2020 | Q2 2020 | Q1 2020 |
|---|---|---|---|---|---|
| Brent ($/bbl) | 61.32 | 45.26 | 43.34 | 33.39 | 51.05 |
| Vasconia($/bbl) | 58.71 | 42.69 | 40.35 | 26.70 | 45.97 |
| Brent/Vasconia crude (differential) ($/bbl) | (2.61) | (2.57) | (2.99) |
(6.69) |
(5.08) |
| Parex quality differential ($/bbl) | (0.20) | (0.15) | (0.35) |
(0.44) |
(0.18) |
| Parex wellhead sales discount($/bbl) | **(5.71) ** | (5.59) | (6.12) | (7.01) | (7.32) |
| Parex realized salesprice($/boe) | 52.80 | 36.95 | 33.88 | 19.25 | 38.47 |
| Parex realized price (differential) to Brent crude ($/boe) | (8.52) | (8.31) | (9.46) |
(14.14) |
(12.58) |
| Parex transportation expense($/boe)(1) | **(3.43) ** | (3.74) | (2.81) | (2.33) | (4.04) |
| Parexprice differential and transportation expense($/boe) | **(11.95) ** | (12.05) | (12.27) | (16.47) | (16.62) |
(1) See Transportation section below. Applies only to direct export cargo sales where Parex incurs the pipeline fees directly.
Differences between Parex’ realized price and Vasconia crude price is mainly related to quality adjustments, wellhead sale marketing contracts, and timing of oil sales compared to quarter averages. The differential between Vasconia crude pricing and Brent crude pricing also affects Parex’ realized sales price and is set in liquid global markets and therefore attributed to factors that are beyond the Company’s control. The significant decrease in global crude oil prices beginning in March 2020 widened the Brent/Vasconia differential to as high as $10/bbl in April and May 2020. In the first quarter of 2021 the Vasconia differential improved to $2.61/bbl average vs $6.69/bbl in Q2 2020. Parex' Colombian oil production is fully exposed to swings in the Vasconia differential to Brent.
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6
March 31, 2021
Parex realized price differential to Brent and Vasconia crudes can fluctuate period over period due to, among other factors, the type of sales contract and the accounting treatment for oil sold at the wellhead versus a direct export cargo sales contract. Parex’ combined transportation costs plus Brent price differential has been trending lower since Q2 2019, except for the period of the COVID-19 pandemic oil price shock in Q1 & Q2 2020. This improvement is primarily the result of an improvement of global heavy crude oil differentials and Colombia’s location allowing Parex crude oil access to all the major global crude oil buying markets and recovery in global oil prices. Also having a positive impact on transportation costs is the ODL pipeline tie-in of Block LLA-34 crude which volumes began to be transported through this pipeline tie-in in Q1 2021.
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Brent Realized Price Differential & Transportation Expense
$-10.00
$-12.00
$(12.27) $(12.05) $(11.95)
$-14.00
$-16.00
$(16.62) $(16.47)
$-18.00
Q1/2020 Q2/2020 Q3/2020 Q4/2020 Q1/2021
$ / boe
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c) Natural Gas Revenue and Realized Prices
| c) Natural Gas Revenue and Realized Prices | |||
|---|---|---|---|
| For the three months | |||
| ended March 31, | |||
| 2021 | 2020 | ||
| Revenue (000’s) | $ | 5,651 $ |
3,974 |
| Realized sales price ($/Mcf) | 6.16 | 5.79 |
Parex natural gas revenues were $5.7 million for the three months ended March 31, 2021 compared to $4.0 million in the same period of 2020. The increase in natural gas sales from the prior period is related to increased natural gas volumes sold from Block LLA-32 and the Capachos block. At the Capachos block, Parex completed a gas processing facility and a related natural gas in-field flowline during 2020.
d) Oil and Natural Gas Revenue
First quarter 2021 oil and natural gas revenue increased $28.4 million or 15% as reconciled in the table below to the first quarter of 2020:
| ($000s) | ||
|---|---|---|
| Oil and natural gas revenue, three months ended March 31, 2020 | $ | 193,618 |
| Sales volume of produced oil, a decrease of 12% (5,971 bopd) | (22,643) | |
| Sales volume of purchased oil, a decrease of 88% (3,054 bopd) | (10,732) | |
| Oil sales price increase of 38% | 60,138 | |
| Sales volume andprice change ofproduced naturalgas | 1,677 | |
| Oil and naturalgas revenue, three months ended March 31, 2021 | $ | 222,058 |
Oil and natural gas revenue increased in the three months ended March 31, 2021 compared to the same period in 2020 mainly due to the increase in world oil prices, partially offset by decreased sales volumes of produced and purchased oil.
e) Crude Oil Inventory in Transit
| As at March 31, | ||||
|---|---|---|---|---|
| ($000s) | 2021 | 2020 | ||
| Crude oil in transit | $ | 3,255 | $ | 5,336 |
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March 31, 2021
7
As at March 31, 2021, the Company had 140.9 mbbls of crude oil inventory in transit compared to 250.5 mbbls at March 31, 2020, which was injected into the Colombian pipelines. The inventory was valued based on direct and indirect expenditures (including production costs, certain transportation costs, depletion expense and royalty expense) at approximately $23/bbl incurred in bringing the crude oil to its existing condition and location.
A reconciliation of quarter to quarter crude oil inventory movements is provided below:
| For the periods ended | ||||
|---|---|---|---|---|
| (mbbls) | Mar. 31, 2021 | Dec. 31,2020 | Sep. 30,2020 | Jun. 30,2020 |
| Crude oil inventory in transit - beginning of the period | 99.5 | 88.0 | 75.9 | 250.5 |
| Oil production | 4,037.4 | 4,118.9 | 3,940.2 | 3,615.2 |
| Oil sales | (4,032.9) | (4,354.7) | (4,179.9) |
(4,073.5) |
| Purchased oil | 36.9 | 247.3 | 251.8 | 283.7 |
| Crude oil inventoryin transit - end of theperiod | 140.9 | 99.5 | 88.0 | 75.9 |
| % ofperiodproduction | 3.5 | 2.4 | 2.2 | 2.1 |
Crude oil inventory build and (draw) from period to period are subject to factors that the Company does not control such as timing of the number of shipments from storage to export. Crude oil inventory as a percentage of quarterly production at March 31, 2021 was 3.5%. Parex expects crude oil inventory in future periods to remain in line with normal historic levels of below 5% of period production.
f) Purchased Oil
| For the three months | ||
|---|---|---|
| ended March 31, | ||
| 2021 2020 |
||
| Purchased oil expense ($000s) | $ | 2,583 $ 10,241 |
Purchased oil expense for the three months ended March 31, 2021 was $2.6 million compared to $10.2 million for the 2020 comparative period and $7.5 million in the fourth quarter of 2020. Purchased oil expense has decreased in the first quarter of 2021 compared to the same period of 2020 as a result of a decrease in oil blending operations and a decrease in purchases of partner crude at certain fields, primarily at the Capachos field. Transportation costs are incurred by the Company to transport purchased oil to sale delivery points.
Royalties
| For the three months | For the three months | For the three months | |||
|---|---|---|---|---|---|
| ended March 31, | |||||
| 2021 | 2020 | ||||
| Royalties ($000s) | $ | 25,571 | $ | 22,217 | |
| Per unit($/boe) | 6.13 | 4.71 | |||
| Percentage of sales(1) | 11.6 | 12.2 |
(1) Calculated based on Company working interest sales volumes excluding purchased oil volumes sold.
In the three months ended March 31, 2021 royalties as a percentage of sales were 11.6% compared to 8.6% during the three months ended December 31, 2020, and 12.2% for the 2020 comparative period. The increase in royalties as a percentage of sales in the quarter from the previous quarter ended December 31, 2020 is a result of higher benchmark WTI prices which are used in the high price share royalty ("HPR") calculation. Benchmark WTI price for three months ended March 31, 2021 were $58.13 compared to $42.63 during the three months ended December 31, 2020, and $46.10 for the 2020 comparative period.
The increase in royalty expense to $25.6 million in the three months ended March 31, 2021 compared to $22.2 million for the 2020 comparative prior year period is a result of higher benchmark WTI prices used in the calculation of royalties, partially offset by decreased oil production and sales over the prior period.
For further information concerning the HPR please refer to the Company’s AIF, which may be accessed through the SEDAR website at www.sedar.com.
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8
March 31, 2021
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Royalties
40 12.2% 11.6%
10.3%
30 8.8% 8.6%
20
10
0
Q1/2020 Q2/2020 Q3/2020 Q4/2020 Q1/2021
Royalties As a % of Oil and Gas Realized Sales per boe
$ millions
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Production Expense
| For the three months | |||
|---|---|---|---|
| ended March 31, | |||
| 2021 2020 |
|||
| Production expense (000s) | $ | 24,416 $ 25,062 |
|
| Per unit($/boe)(1) | 5.86 5.31 |
(1) Calculated based on Company working interest sales volumes excluding purchased oil volumes sold.
A breakdown of the production expense on a per boe basis between operated and non-operated fields are provided below:
| For the three months | For the three months | |
|---|---|---|
| ended March 31, | ||
| 2021 | 2020 | |
| Per unit ($/boe) – based on sales volumes – operated(1) | 7.50 | 8.52 |
| Per unit ($/boe) – based on sales volumes – non-operated(1) | 4.97 | 4.16 |
(1) Calculated based on Company working interest sales volumes excluding purchased oil volumes sold.
Production expense includes the cost of activities in the field to operate wells and facilities, lift to surface, gather, process, treat and store production.
Production expense for the three months ended March 31, 2021 was $5.86/boe compared to $5.31/boe in the three months ended March 31, 2020. Production expense for the fourth quarter of 2020 was $5.26/boe.
Operated properties production expense in the first quarter of 2021 was $7.50/boe compared to $7.38/boe for the fourth quarter of 2020 and non-operated properties production expense in the first quarter of 2021 was $4.97/boe compared to $4.27/boe for the fourth quarter of 2020.
The decrease in operated production expense for the three months ended March 31, 2021 over the 2020 comparative period is mainly the result of additional production from the lower cost Capachos field, and the voluntary shut-in of higher operating cost fields compared to the prior period. Some of the higher operating cost fields were brought back on stream in mid Q1 2021.
The increase in non-operated production expense for three months ended March 31, 2021 over the 2020 comparative period is mainly the result of increased well workovers in the current quarter in Block LLA-34 compared to the prior period.
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9
March 31, 2021
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Production Expense
30
$5.86
25 $5.31 $4.98 $5.00 $5.26
20
15
10
5
Q1/2020 Q2/2020 Q3/2020 Q4/2020 Q1/2021
Production Expenses Production Expenses ($/boe)
Transportation Expense
For the three months
ended March 31,
2021 2020
Transportation expense ($000s) $ 14,438 $ 20,336
Per unit ($/boe) 3.43 4.04
$ millions
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Transportation expense includes trucking costs incurred to transport production to several offloading stations for sale and in some instances an oil transportation tariff from delivery point to the buyer’s facility and pipeline tariffs.
For the three months ended March 31, 2021 the cost of transportation on a per boe basis has decreased to $3.43/boe from the fourth quarter of 2020 of $3.74/boe and decreased from the comparative period in 2020 of $4.04/boe. Transportation expense will fluctuate period over period due to the mix of sales contract types in force during the period. The decrease from the comparative period of Q1 2020 is a result of a change in sales mix as a higher percentage of crude was transported and exported in the prior period vs. sold at the wellhead. The decrease from the fourth quarter of 2020 is mainly due to the tie-in of additional Block LLA-34 volumes to the ODL pipeline which carries a lower tariff than the cost of truck transport for this particular volume of crude.
The combined transportation expense and price differential from Brent, on a per boe basis, has decreased from the second quarter of 2020 and is comparable to the prior year comparative period. See "Crude Oil Reference and Realized Prices".
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Transportation Expenses
30
25 $4.04
$3.74
$3.43
20 $2.81
$2.33
15
10
5
0
Q1/2020 Q2/2020 Q3/2020 Q4/2020 Q1/2021
Transportation Expense Transportation Expenses ($/boe)
$ millions
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10
March 31, 2021
General and Administrative Expense (“G&A”)
| For the three months | For the three months | For the three months | |||
|---|---|---|---|---|---|
| ended March 31, | |||||
| (000s) | 2021 | 2020 | |||
| Gross G&A | $ | 12,086 | $ | 11,423 | |
| G&A recoveries | (601) | (263) | |||
| Capitalized G&A | **(2,637) ** | (2,061) | |||
| Total net G&A | $ | 8,848 | $ | 9,099 | |
| Per unit($/boe)(1) | 2.10 | 1.84 |
(1) Calculated based on Company working interest production volumes .
Net G&A was $8.8 million for the three months ended March 31, 2021 compared to $9.1 million for the same period in 2020. Net G&A has decreased mainly as a result of increased capitalized G&A and G&A recoveries compared to the prior year. Gross G&A was $12.1 million for the three months ended March 31, 2021 (three months ended March 31, 2020 - $11.4 million). For the three months ended March 31, 2021 on a per boe basis net G&A has increased 14% compared to the comparative period in 2020 as result of decreased production.
The Company’s G&A expense is denominated in local currencies of COP and Cdn dollar which as they appreciate/depreciate have an impact on G&A expense. Refer to the "Foreign Exchange Sensitivity Analysis" for further information.
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Net General and Administrative Expenses
15
12 $2.27 $2.10 $2.32 $2.10
$1.84
9
6
3
0
Q1/2020 Q2/2020 Q3/2020 Q4/2020 Q1/2021
Net G&A Expenses Net G&A Expenses ($/boe)
$ millions
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Share-Based Compensation
| Share-Based Compensation | |||||
|---|---|---|---|---|---|
| For the three months | |||||
| ended March 31, | |||||
| ($000s) | 2021 | 2020 | |||
| Equity settled share-based compensation expense | $ | 898 | $ | 1,156 | |
| Cash settled share-based compensation expense(recovery) | 9,504 | (9,291) | |||
| Total net expense(recovery) | $ | 10,402 | $ | (8,135) |
Share-based compensation expense was $10.4 million for the three months ended March 31, 2021 compared to an $8.1 million recovery of expense recorded for the same period in 2020. The increase is primarily due to the increase in the Company's share price and its impact on cash-settled compensation as explained below.
Equity settled share-based compensation expense was $0.9 million for the three months ended March 31, 2021 compared to $1.2 million for the same period in 2020. Equity settled share-based compensation includes the Company's stock option plan and the restricted share unit ("RSU") plan pursuant to which RSUs and performance based RSUs ("PSUs") have been awarded up until 2019.
Cash settled share-based compensation relates to the Company's cash settled incentive plans and includes share appreciation rights ("SARs"), cash settled restricted share units ("CRSUs"), cash or share settled restricted share units ("CosRSUs"), cash or share settled performance share units ("CosPSUs") and deferred share units ("DSUs"). For the three months ended March 31, 2021 there was an expense of $9.5 million related to cash settled incentive plans compared to a $9.3 million recovery for the same period in 2020. The increase in expense is attributable to the increase in Parex share price to Cdn$22.41 at March 31, 2021 from Cdn $11.90 at March 31, 2020. Obligations for payments of cash under the Company's cash settled incentive plans are accrued as expense over the vesting period based on the fair value of the units as described in note 14 of the interim financial statements for the three months ended March 31, 2021. As at March 31, 2021, the total cash settled incentive plans liability accrued was $22.3 million (December 31, 2020 - $23.7 million).
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11
March 31, 2021
Cash payments to settle cash settled share-based compensation in the three months ended March 31, 2021 was $12.6 million compared to $8.3 million for the same period in 2020.
Depletion, Depreciation and Amortization Expense (“DD&A”)
| For the three months | ||
|---|---|---|
| ended March 31, | ||
| 2021 2020 |
||
| DD&A expense (000s) | $ | 29,161 $ 29,669 |
| Per unit ($/boe)(1) | 6.93 6.00 |
(1) DD&A per unit ($/boe) is calculated using Company working interest production volumes and does not include inventory adjustments.
First quarter 2021 DD&A was $29.2 million ($6.93/boe) compared to $29.7 million ($6.00/boe) for the same period in 2020. DD&A on a $/boe basis increased compared to the prior period due to changes in the CGU production mix as well as adding to our depletable base in Q4 2020 based on transfers from exploration and evaluation assets to developed and producing assets.
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DD&A
35 $6.00 $6.79 $6.45 $7.59 $6.93
30
25
20
15
Q1/2020 Q2/2020 Q3/2020 Q4/2020 Q1/2021
Depletion, Depreciation and Amortization Expense DD&A per boe, before impairment (recovery) ($/boe)
$ millions
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Foreign Exchange (Gain)
| For the three months | For the three months | ||
|---|---|---|---|
| ended March 31, | |||
| 2021 | 2020 | ||
| Foreign exchange (gain) | $ | (4,235)$ | (16,656) |
| Foreign currency risk management contracts loss | — | 508 | |
| Total foreign exchange (gain) | $ | (4,235)$ | (16,148) |
| Average foreign exchange rates | |||
| USD$/CAD$ | 1.27 | 1.34 | |
| USD$/Colombian peso | 3,553 | 3,536 |
The Company’s main exposure to foreign currency risk relates to the pricing of foreign currency denominated in Canadian dollars and Colombian pesos, as the Company’s functional currency is the US dollar. The Company has exposure in Colombia and Canada on costs, such as capital expenditures, local wages, royalties and income taxes, all of which may be denominated in local currencies. The main drivers of foreign exchange gains and losses recorded on the consolidated statements of comprehensive income is the Colombian peso denominated income tax payable and tax withholdings receivable, accounts payable and accounts receivable. The timing of payment settlements, accruals and their adjustments have impacts on foreign exchange gains/losses.
For the three months ended March 31, 2021, the total foreign exchange gain was $4.2 million (three months ended March 31, 2020 – gain of $16.1 million) attributable to the appreciation of COP against the USD. Unrealized foreign exchange gains and losses may be reversed in the future as a result of fluctuations in exchange rates and are recorded in the Company’s consolidated statements of comprehensive income.
The Company reviews its exposure to foreign currency variations on an ongoing basis and maintains cash deposits primarily in USD denominated deposits in Canada, Barbados, Bermuda and Colombia.
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12
March 31, 2021
Foreign Exchange Sensitivity Analysis
| Cost component Estimated percent of cost denominated in local currency |
$/boe Impact of change in local currency/$USD exchange rate |
|---|---|
10% appreciation of local currency 10% depreciation of local currency |
|
| Production expense 80% Transportation expense 80% G&A expense 100% |
$ 0.47 $ (0.47) $ 0.27 $ (0.27) $ 0.21$ (0.21) |
The table above displays the estimated per boe impact of a change in Parex' local currencies and the effect on Parex' key cost components. The component impact in $/boe terms uses Q1 2021 per boe costs. This analysis ignores all other factors impacting cost structure including efficiencies, cost reduction strategies, etc.
Net Finance Expense
| For the three months | For the three months | For the three months | ||
|---|---|---|---|---|
| ended March 31, | ||||
| 2021 | 2020 | |||
| Bank charges and credit facility fees | $ | 577 | $ | 740 |
| Accretion on decommissioning and environmental liabilities | 946 | 1,093 | ||
| Interest and other income | (213) | (922) | ||
| Right of use asset interest | 2 | 20 | ||
| Loss (gain) on settlement of decommissioning liabilities | 356 | (96) | ||
| Expected credit loss (recovery) provision | (228) | 1,343 | ||
| Other | 0 | 1,077 | ||
| Net finance expense | $ | 1,440 | $ | 3,255 |
| For the three months | ||||
| ended March 31, | ||||
| 2021 | 2020 | |||
| Non-cash finance expense | $ | 1,074 | $ | 3,417 |
| Cash finance expense(income) | 366 | (162) | ||
| Net finance expense | $ | 1,440 | $ | 3,255 |
Bank taxes and credit facility fees relate to bank taxes paid in Colombia and the standby fees related to the undrawn credit facility. The noncash components of net finance expense include the accretion on decommissioning and environmental liabilities, loss on settlement of decommissioning liabilities, and the expected credit loss (recovery) provision which has increased due to the COVID-19 pandemic and its impact on credit markets and ratings.
Risk Management
Management of cash flow variability is an integral component of Parex’ business strategy. Changing business conditions are monitored regularly and, where material, reviewed with the Board of Directors to establish risk management guidelines to be used by management. The risk exposure inherent in movements in the price of crude oil, fluctuations in the US/COP exchange rate and interest rate movements are all proactively reviewed by Parex and as considered appropriate may be managed through the use of derivatives primarily with financial institutions that are members of Parex’ syndicated bank credit facility. The Company considers these derivative contracts to be an effective means to manage and forecast cash flow.
Parex has elected not to apply IFRS prescribed “hedge accounting” rules and, accordingly, pursuant to IFRS the fair value of the financial contracts is recorded at each period-end. The fair value may change substantially from period to period depending on commodity and foreign exchange forward strip prices for the financial contracts outstanding at the balance sheet date. The change in fair value from period-end to period-end is reflected in the earnings for that period. As a result, earnings may fluctuate considerably based on the period-ending commodity and foreign exchange forward strip prices, in respect of any outstanding commodity or foreign exchange derivative contracts.
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13
March 31, 2021
a) Risk Management Contracts - Brent Crude
At March 31, 2021 the Company had no crude oil risk management contracts in place.
b) Risk Management Contracts – Foreign Exchange
The Company is exposed to foreign currency risk as various portions of its cash balances are held in Colombian pesos (COP$) and Canadian dollars (Cdn$) to fund ongoing costs denominated in those currencies while its committed capital expenditures are primarily denominated in US dollars.
As at March 31, 2021, the Company had no outstanding foreign currency risk management contracts.
The table below summarizes the loss on the foreign currency risk management contracts:
| For the three months | For the three months | ||
|---|---|---|---|
| ended March 31, | |||
| 2021 | 2020 | ||
| Unrealized loss on foreign currency risk management contracts | $ | — $ |
508 |
| Total | $ | — $ |
508 |
The Company recorded a $0.5 million unrealized loss on these contracts in the three months ended March 31, 2020 which is recorded in the financial statement line item "Foreign exchange (gain)".
Income Tax
The components of tax expense for the three months ended March 31, 2021 and 2020 were as follows:
| For the three months | For the three months | For the three months | ||
|---|---|---|---|---|
| ended March 31, | ||||
| 2021 | 2020 | |||
| Current tax expense | $ | 22,276 | $ | 10,099 |
| Deferred tax expense | 39,698 | 84,702 | ||
| Tax expense | $ | 61,974 | $ | 94,801 |
Current tax expense in the first quarter of 2021 was $22.3 million as compared to $10.1 million expense in the comparative period. The increase from the prior year comparative period is mainly a result of an increase in operating cash flows from the prior period.
Deferred tax expense in the three months ended March 31, 2021 was $39.7 million, the decrease from the comparative period is mainly related to the foreign exchange impact of the Colombian peso denominated tax basis, which has decreased as a result of the appreciation of the Colombian peso to US dollar at the period end date compared to the prior year and its effect on the Colombian tax provision.
The calculation of current and deferred income tax in Colombia is based on a number of variables which can cause swings in current and deferred income tax. These variables include but are not limited to the year-end producing reserves used in calculating depletion for tax purposes, the timing and number of dry hole write-offs permissible for Colombian tax purposes and currency fluctuations.
Capital Expenditures
| For the three months ended March 31, | Colombia | Colombia | Canada | Canada | Total | Total | ||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|
| ($000s) | 2021 | 2020 | 2021 | 2020 | 2021 | 2020 | ||||||
| Acquisition of unproved properties | $ | — | $ | 66 | $ | — | $ | — | $ | — | $ | 66 |
| Geological and geophysical | 167 | 740 | — | — | 167 | 740 | ||||||
| Drilling and completion | 28,982 | 67,944 | — | — | 28,982 | 67,944 | ||||||
| Well equipment and facilities | 10,355 | 2,377 | — | — | 10,355 | 2,377 | ||||||
| Other | 25 | 75 | 63 | 64 | 88 | 139 | ||||||
| Total capital expenditures | $ | 39,529 | $ | 71,202 | $ | 63 | $ | 64 | **$ ** | 39,592 | $ | 71,266 |
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14
March 31, 2021
Capital Expenditures Summary
During the three months ended March 31, 2021 the Company incurred $39.6 million of capital expenditures compared to $71.3 million in the same period of 2020. During Q1 2021 the Company drilled 9 gross (5.05 net) wells, compared to drilling 20 gross (13.05 net) wells in the comparative period upon the re-activation of the development and exploration program. During Q1, 2021, total drilling and completion costs were $29.0 million of which the majority related to drilling, completion and capitalized workover costs at Block LLA-34, Block LLA-32 and Boranda block. Facilities costs in Q1 2021 were due to the Block LLA-34 flowline construction.
During the three months ended March 31, 2021 capital expenditures of $39.6 million were self-funded from funds flow provided by operations of $125.0 million. The Company strives to fund its annual capital expenditures from funds flow and has demonstrated this goal since 2012 however on a quarterly basis funds flow may be greater or less than capital expenditures due to timing of capital programs and other variables.
Non-cash Impairment Charges
| Non-cash Impairment Charges | ||||
|---|---|---|---|---|
| For the three months | ||||
| ended March 31, | ||||
| ($000s) | 2021 | 2020 | ||
| Impairment of PP&E related to Boranda CGU | $ | — $ |
7,000 | |
| Total non-cash impairment charges before deferred income tax recoveries | $ | — $ |
7,000 |
As a result of the COVID-19 pandemic and the significant decrease in forecast global crude oil prices compared to those at December 31, 2019, an indication of impairment was identified for all CGUs at March 31, 2020 and impairment tests were performed. The Company determined that the carrying amount of the Boranda CGU in the Magdalena Basin exceeded its recoverable amount and an impairment of $7 million was recorded in the consolidated statements of comprehensive (loss) for the three month period ended March 31, 2020. All other CGU's were found to have recoverable amounts greater than carrying amounts. The recoverable amount for this testing was determined using fair value less cost of disposal. Future cash flows for the CGU's declined due to lower crude oil prices.
The fair value as determined for the Company's producing properties was consistent with the Company's independent qualified reserve evaluators reserve estimate at December 31, 2019, updated for forecast oil prices at March 31, 2020 and adjusting for first quarter production and future development capital expenditures. There are no E&E assets associated with this CGU. Future cash flows were discounted using a rate of 11%. As at March 31, 2020, the recoverable amount of the CGU was estimated to be $16.5 million. The impairment of $7.0 million was due to the lower crude oil price forecast at March 31, 2020 assumed in the fair value calculation compared to the prior year. A 1% change to the assumed discount rate or a 5% change in forward price estimates over the life of the reserves would have an immaterial impact on the impairment.
At March 31, 2021 there were no indicators of impairment noted for PP&E, or indicators of requiring a reversal of previously recorded impairments.
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15
March 31, 2021
Summary of Quarterly Results
| Summary of Quarterly Results | ||||||||
|---|---|---|---|---|---|---|---|---|
| Three months ended ($000s) | Mar. 31, 2021 | Dec. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | ||||
| Average daily oil and natural gas production (boe/d) | 46,779 | 46,642 | 44,305 | 40,858 | ||||
| Average realized sales price - oil ($/boe) | 52.80 | 36.95 | 33.88 | 19.25 | ||||
| Financial (000s except per share amounts) | ||||||||
| Oil and natural gas sales | $ | 222,058 | $ | 167,264 | $ | 146,231 | $ | 80,407 |
| Funds flow provided by operations(1) | $ | 124,969 | $ | 81,567 | $ | 79,384 | $ | 38,777 |
| Per share – basic(1) | 0.96 | 0.61 | 0.57 | 0.28 | ||||
| Per share – diluted(1) | 0.96 | 0.60 | 0.57 | 0.27 | ||||
| Net income | $ | 47,460 | $ | 56,192 | $ | 27,619 | $ | 19,290 |
| Per share – basic | 0.37 | 0.42 | 0.20 | 0.14 | ||||
| Per share – diluted | 0.36 | 0.42 | 0.20 | 0.14 | ||||
| Capital Expenditures, excluding corporate acquisitions | $ | 39,592 | $ | 46,932 | $ | 17,756 | $ | 5,310 |
| Total assets (end of period) | $ | 1,550,441 | $ | 1,541,081 | $ | 1,548,484 | $ | 1,533,377 |
| Workingcapital surplus(end ofperiod) (2) | $ | 341,686 | $ | 320,155 | $ | 370,722 | $ | 339,310 |
| (1) Non-GAAP term. See “Non-GAAP Terms” below. | ||||||||
| (2) Working capital does not include the undrawn amount available | under the credit facility. | |||||||
| Three months ended ($000s) | Mar. 31, 2020 | Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | ||||
| Average daily oil and natural gas production (boe/d) | 54,295 | 54,221 | 53,045 | 52,252 | ||||
| Average realized sales price - oil ($/boe) | 38.47 | 53.00 | 53.59 | 59.92 | ||||
| Financial (000s except per share amounts) | ||||||||
| Oil and natural gas sales | $ | 193,618 | $ | 289,585 | $ | 275,693 | $ | 301,750 |
| Funds flow provided by operations(1) | $ | 97,313 | $ | 143,269 | $ | 142,733 | $ | 150,973 |
| Per share – basic(1) | 0.69 | 1.00 | 0.99 | 1.03 | ||||
| Per share – diluted(1) | 0.68 | 0.98 | 0.97 | 1.00 | ||||
| Net (loss) income | $ | (3,779) | $ | 87,218 | $ | 57,257 | $ | 101,505 |
| Per share – basic | (0.03) | 0.61 | 0.40 | 0.69 | ||||
| Per share – diluted | (0.03) | 0.60 | 0.39 | 0.67 | ||||
| Capital Expenditures, excluding corporate acquisitions | $ | 71,266 | $ | 58,321 | $ | 48,600 | $ | 48,742 |
| Total assets (end of period) | $ | 1,610,341 | $ | 1,684,581 | $ | 1,593,802 | $ | 1,574,528 |
| Workingcapital surplus(end ofperiod) (2) | $ | 330,356 | $ | 344,031 | $ | 279,949 | $ | 240,087 |
(1) Non-GAAP term. See “Non-GAAP Terms” below.
(2) Working capital does not include the undrawn amount available under the credit facility.
Factors that Caused Variations Quarter Over Quarter
During the first quarter of 2021, production of 46,779 boe/d was comparable to production for the previous quarter ended December 31, 2020. Revenue and funds flow provided by operations were higher than the previous quarter mainly due to an increase in realized prices. Working capital increased to $341.7 million from $320.2 million at December 31, 2020.
During the fourth quarter of 2020, production of 46,642 boe/d (consisting of 6,637 bbls/d light crude oil and medium crude oil, 38,332 bbls/d of heavy crude oil and 10,038 mcf/d of conventional natural gas) was in excess of production for the previous quarter ended September 30, 2020. Revenue and funds flow provided by operations were higher than the previous quarter due to an increase in volumes sold and realized prices. Working capital decreased to $320.2 million from $370.7 million at September 30, 2020 primarily due to buying back 6.6 million shares pursuant to the Company's NCIB.
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16
March 31, 2021
During the third quarter of 2020, production of 44,305 boe/d (consisting of 4,626 bbls/d light crude oil and medium crude oil, 38,309 bbls/d of heavy crude oil and 8,220 mcf/d of conventional natural gas) was in excess of production for the previous quarter ended June 30, 2020. Revenue and funds flow provided by operations were higher than the previous quarter due to an increase in realized prices and volumes sold. Working capital increased to $370.7 million from $339.3 million at June 30, 2020.
During the second quarter of 2020, production of 40,858 boe/d (consisting of 4,186 bbls/d light crude oil and medium crude oil, 35,478 bbls/d of heavy crude oil and 7,164 mcf/d of conventional natural gas) was lower than production for the previous quarter ended March 31, 2020. Revenue and funds flow provided by operations were lower than the previous quarter mainly due to a decrease in realized prices and volumes sold. Working capital increased to $339.3 million from $330.4 million at March 31, 2020.
During the first quarter of 2020, production of 54,295 boe/d (consisting of 8,380 bbls/d light crude oil and medium crude oil, 44,657 bbls/d of heavy crude oil and 7,548 mcf/d of conventional natural gas) was in excess of production for the previous quarter ended December 31, 2019. Revenue and funds flow provided by operations were lower than the previous quarter mainly due to a decrease in realized prices and volumes sold. Working capital decreased to $330.4 million from $344.0 million at December 31, 2019.
Please refer to “Financial and Operating Results” for detailed discussions on variations during the comparative quarters and to Parex’ previously issued annual and interim MD&As for further information regarding changes in prior quarters.
Liquidity and Capital Resources
As at March 31, 2021 the Company had a working capital surplus of $341.7 million, excluding funds available under the credit facility, as compared to working capital surplus at December 31, 2020 of $320.2 million. Bank debt was $nil as at March 31, 2021, December 31, 2020 and March 31, 2020. The credit facility has a current borrowing base of $200.0 million (December 31, 2020 - $200.0 million). At March 31, 2021 Parex held $369.8 million of cash, compared to $330.6 million at December 31, 2020 and $397.4 million at March 31, 2020. The Company’s cash balances reside in current accounts with chartered institutions, the majority of which are held on account in Canada, Barbados, Bermuda and Colombia in USD.
Parex' senior secured credit facility with a syndicate of banks has a current borrowing base of $200.0 million. Key covenants include a rolling four quarters total funded debt to adjusted EBITDA test of 3:50:1, and other standard business operating covenants. Given there is $nil balance drawn on the facility as at March 31, 2021, the Company is in compliance with all covenants. The next annual review is scheduled to occur in May 2022.
Refer to note 20 - Commitments of the interim financial statements for the period ended March 31, 2021 for a description of the performance guarantee facility with Export Development Canada as well as the unsecured letters of credit.
Outstanding Share Data
Parex is authorized to issue an unlimited number of voting common shares without nominal or par value. As at March 31, 2021 the Company had 128,588,648 common shares outstanding compared to 130,872,676 at December 31, 2020 a decrease of 1.7%. At May 5, 2021 the common shares outstanding has been reduced to 127,884,243.
The Company has a stock option plan and RSU plan. The plans provide for the issuance of stock options and RSUs to the Company’s officers, executive and certain employees to acquire common shares. In 2019, Parex created a new cash or share settled RSU and PSU plan. Under this new plan any employee who chooses share settlement will receive common shares of the Company purchased on the open market, hence there will be no new issuance of common shares from treasury under this new plan. Going forward, it is expected that the only the grants under the Company's stock option plan and the exercise of previously issued RSUs will result in common shares issued from treasury.
As at May 5, 2021 Parex has the following securities outstanding:
| As at May 5, 2021 Parex has the following securities outstanding: | ||
|---|---|---|
| Number | % | |
| Common shares | 127,884,243 | 98 % |
| Stock options | 1,421,401 | 1 % |
| Restricted share units | 595,530 | 0 % |
| 129,901,174 | 99 % |
As of the date of this MD&A, total stock options and RSUs outstanding represent approximately 2% of the total issued and outstanding common shares.
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17
March 31, 2021
Contractual Obligations, Commitments and Guarantees
In the normal course of business, Parex has entered into arrangements and incurred obligations that will affect the Company’s future operations and liquidity. These commitments primarily relate to exploration work commitments including seismic and drilling activities. The Company has discretion regarding the timing of capital spending for exploration work commitments, provided that the work is completed by the end of the exploration periods specified in the contracts or the Company can negotiate extensions of the exploration periods. The Company’s exploration commitments are described in the Company’s AIF under “Description of Business - Principal Properties”. These obligations and commitments are considered in assessing cash requirements in the discussion of future liquidity.
In Colombia, the Company has provided guarantees to the Colombian National Hydrocarbon Agency ("ANH") which on March 31, 2021 were $41.6 million (December 31, 2020 - $46.4 million) to support the exploration work commitments on its blocks. The guarantees have been provided in the form of letters of credit for varying terms. Export Development Canada has provided performance security guarantees under the Company’s $150.0 million (December 31, 2020 - $150.0 million) performance guarantee facility to support approximately $15.7 million (December 31, 2020 - $21.9 million) of the letters of credit issued on behalf of Parex at March 31, 2021. Also at March 31, 2021, there is an additional $25.9 million (December 31, 2020 - $24.5 million) of letters of credit that are provided by a Latin American bank on an unsecured basis. The letters of credit issued to the ANH are reduced from time to time to reflect the work performed on the various blocks.
The following table summarizes the Company’s estimated undiscounted commitments as at March 31, 2021:
| (000s) | Total | <1year | 1 | – 3years | 3 | – 5years | >5years | |||
|---|---|---|---|---|---|---|---|---|---|---|
| Exploration | $ | 173,729 | $ | 45,433 | $ | 39,205 | $ | — | $ | 89,091 |
| Office and accommodations(1) | 6,824 | 2,407 | 3,312 | 1,105 | — | |||||
| Decommissioningand Environmental Obligations | 82,534 | 5,157 | — | — | 77,377 | |||||
| Total | $ | 263,087 | $ | 52,997 | $ | 42,517 | $ | 1,105 | $ | 166,468 |
(1) Includes minimum lease payment obligations associated with leases for office space and accommodations.
Decommissioning and Environmental Liabilities
| Decommissioning and Environmental Liabilities | ||||||
|---|---|---|---|---|---|---|
| Decommissioning | Environmental | Total | ||||
| Balance,December 31,2019 | $ | 37,244 | $ | 14,691 | $ | 51,935 |
| Additions | 2,554 | 480 | 3,034 | |||
| Settlements of obligations during the year | (3,560) | (1,070) | (4,630) | |||
| Loss on settlement of obligations | 803 | — | 803 | |||
| Accretion expense | 2,286 | 1,839 | 4,125 | |||
| Change in estimate - inflation and discount rates | 360 | (2,062) | (1,702) | |||
| Change in estimate - costs | (441) | (286) | (727) | |||
| Foreign exchange(gain) | (1,036) | (691) | (1,727) | |||
| Balance,December 31,2020 | $ | 38,210 | $ | 12,901 | $ | 51,111 |
| Additions | 503 | 6 | 509 | |||
| Settlements of obligations during the period | (1,889) | (7) | (1,896) | |||
| Loss on settlement of obligations | 356 | — | 356 | |||
| Accretion expense | 469 | 477 | 946 | |||
| Change in estimate - inflation and discount rates | (2,237) | 1,449 | (788) | |||
| Foreign exchange(gain) | (3,136) | (1,770) | (4,906) | |||
| Balance, March 31, 2021 | $ | 32,276 | $ | 13,056 | $ | 45,332 |
| Current obligation | (1,739) | (3,418) | (5,157) | |||
| Long-term obligation | $ | 30,537 | $ | 9,638 | $ | 40,175 |
The total environmental, decommissioning and restoration obligations were determined by management based on the estimated costs to settle environmental impact obligations incurred and to reclaim and abandon the wells and well sites based on contractual requirements. The obligations are expected to be funded from the Company’s internal resources available at the time of settlement.
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The total decommissioning and environmental liability is estimated based on the Company’s net ownership in wells drilled as at March 31, 2021, the estimated costs to abandon and reclaim the wells and well sites and the estimated timing of the costs to be paid in future periods. The total undiscounted amount of cash flows required to settle the Company’s decommissioning liability is approximately $61.1 million as at March 31, 2021 (December 31, 2020 – $60.4 million) with the majority of these costs anticipated to occur in 2033 or later. A risk-free discount rate of 7% and an inflation rate of 2.7% were used in the valuation of the liabilities (December 31, 2020 – 5.25% risk-free discount rate and a 2% inflation rate). The risk-free discount rate and the inflation rate used are based on forecast Colombia rates.
Included in the decommissioning liability is $1.7 million (December 31, 2020 – $3.6 million) that is classified as a current obligation.
The total undiscounted amount of cash flows required to settle the Company’s environmental liability is approximately $21.4 million as at March 31, 2021 (December 31, 2020 – $20.5 million) with the majority of these costs anticipated to occur in 2033 or later in Colombia. A riskfree discount rate of 7% and an inflation rate of 2.7% were used in the valuation of the liabilities (December 31, 2020 – 5.25% risk-free discount rate and a 2% inflation rate). The risk-free discount rate and the inflation rate used are based on forecast Colombia rates.
Included in the environmental liability is $3.4 million (December 31, 2020 – $3.4 million) that is classified as a current obligation.
Decommissioning liabilities are considered critical accounting estimates. There are significant uncertainties related to decommissioning expenditures and the impact on the financial statements could be material. The eventual timing of and costs for these expenditures could differ from current estimates. The main factors that can cause expected estimated cash flows in respect of decommissioning liabilities to change are:
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Changes in laws and legislation;
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Construction of new facilities;
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Change in commodity price;
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Change in the estimate of oil reserves and the resulting amendment to the life of reserves;
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Changes in technology; and
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Execution of decommissioning liabilities.
Advisory on Forward-Looking Statements
Certain information regarding Parex set forth in this MD&A, including assessments by the Company’s management of the Company’s plans and future operations, contains forward-looking statements that involve substantial known and unknown risks and uncertainties. The use of any of the words “plan”, “expect”, “forecast”, “project”, “intend”, “believe”, “anticipate”, “estimate” or other similar words, or statements that certain events or conditions “may” or “will” occur are intended to identify forward-looking statements. Such statements represent the Company’s internal projections, estimates or beliefs concerning, among other things, future growth, results of operations, production, future capital and other expenditures (including the amount, nature and sources of funding thereof), competitive advantages, plans for and results of drilling activity, environmental matters, business prospects and opportunities. These statements are only predictions and actual events or results may differ materially. Although the Company’s management believes that the expectations reflected in the forward-looking statements are reasonable, it cannot guarantee future results, levels of activity, performance or achievement since such expectations are inherently subject to significant business, economic, competitive, political and social uncertainties and contingencies. Many factors could cause the Company’s actual results to differ materially from those expressed or implied in any forward-looking statements made by, or on behalf of, Parex. In particular, forward-looking statements contained in this MD&A include, but are not limited to, statements with respect to:
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▪the Company's operational strategy, plans, priorities and focus;
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▪2021 average production and total capital expenditures and the allocation of such capital expenditures;
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▪2021 current tax effective rate on FFO and the assumed Brent crude price;
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▪number of shares to be repurchased under the NCIB;
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▪outstanding number of shares at the end of 2021;
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▪expectation of a significant increase to Parex' 2021 FFO and the reasons therefor;
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▪year-over-year production growth of approximately 3% as compared to 2020;
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▪expectation that FFO will fully fund the 2021 capital expenditure program and the NCIB;
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▪expectation that production downtime on Block LLA-34 is to be reduced to more historic levels for the remainder of 2021;
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▪fluctuation in Brent/Vasconia crude differential;
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▪expectation that crude oil inventory in future periods to be in line with normal historic levels;
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▪the amount and timing of payment of total decommissioning and environmental liability cost;
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▪the Company’s expectations regarding the per boe and G&A expense impact caused by appreciation and depreciation of the Colombian peso;
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▪the effect of the Colombian peso/US$ exchange rate on the variability of general and administrative, transportation, and production costs;
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▪foreign currency risk and the ability to reverse unrealized foreign exchange gains and losses in the future;
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▪the Company's risk management strategy and the use of derivatives primarily with financial institutions to manage movements in the price of crude oil, fluctuations in the US/COP exchange rate and interest rate movements;
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▪terms of the Company's credit facility including the timing of the next borrowing base redetermination;
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▪terms of certain contractual obligations; and
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▪the Company's expectation that only the grants under the Company's stock option plan and the exercise of previously issued RSUs and PSUs will result in common shares issued from treasury.
These forward-looking statements are subject to numerous risks and uncertainties, including but not limited to: the impact of general economic conditions in Canada and Colombia; industry conditions including changes in laws and regulations including adoption of new environmental laws and regulations, and changes in how they are interpreted and enforced in Canada and Colombia; continued volatility in market prices for oil; the impact of the COVID-19 pandemic and the ability of Parex to carry on its operations as currently contemplated in light of the COVID-19 pandemic; the impact of significant declines in market prices for oil; competition; lack of availability of qualified personnel; the results of exploration and development drilling and related activities; partner approval of capital work programs and other matters requiring approval; imprecision in reserve and resource estimates; the production and growth potential of Parex’ assets; obtaining required approvals of regulatory authorities in Canada and Colombia; risks associated with negotiating with foreign governments as well as country risk associated with conducting international activities; fluctuations in foreign exchange or interest rates; environmental risks; changes in income tax laws or changes in tax laws and incentive programs relating to the oil and natural gas industry; ability to access sufficient capital from internal and external sources; risk that the Company will not be able to obtain contract extensions or fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its undeveloped properties; risk of failure to achieve the anticipated benefits associated with acquisitions; risk of failure to achieve perceived benefits from voluntary tax restructuring; failure of counterparties to perform under the terms of their contracts; changes to pipeline capacity; risk that Parex' evaluation of its existing portfolio of development and exploration opportunities is not consistent with its expectations; failure to meet expected production targets; risk that the review of strategic repositioning alternatives will not result in a transaction; the risks discussed under "Risk Factors" in the Company’s AIF and under “Decommissioning and Environmental Liabilities” in this MD&A, and other factors, many of which are beyond the control of the Company. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect the Company’s operations and financial results are included in reports on file with Canadian securities regulatory authorities and may be accessed through the SEDAR website (www.sedar.com).
Although the forward-looking statements contained in this MD&A are based upon assumptions which management believes to be reasonable, the Company cannot assure investors that actual results will be consistent with these forward-looking statements. With respect to forwardlooking statements contained in this MD&A, Parex has made assumptions regarding, among other things: current and future commodity prices and royalty regimes; the impact (and the duration thereof) that the COVID-19 pandemic will have on (i) the demand for crude oil and conventional natural gas; (ii) the supply chain, including the Company's ability to obtain the equipment and services it requires; and (iii) the Company's ability to produce, transport and/or sell its crude oil and conventional natural gas; availability of skilled labour; timing and amount of capital expenditures; uninterrupted access to areas of the Company’s operations and infrastructure; future exchange rates; the price of oil; the impact of increasing competition; conditions in general economic and financial markets; availability of drilling and related equipment; effects of regulation by governmental agencies; recoverability of reserves and future production rates; timing and number of dry hole write-offs permitted for Colombian tax purposes; royalty rates; future operating costs; foreign exchange rates; the status of litigation; timing of drilling and completion of wells; that the Company will have sufficient cash flow, debt or equity sources or other financial resources required to fund its capital and operating expenditures and requirements as needed; that the Company’s conduct and results of operations will be consistent with its expectations; that the Company will have the ability to develop the Company’s oil and gas properties in the manner currently contemplated; current or, where applicable, proposed industry conditions, laws and regulations will continue in effect or as anticipated as described herein; that the estimates of the Company’s reserves volumes and the assumptions related thereto (including commodity prices and development costs) are accurate in all material respects; that the Company will be able to obtain contract extensions or fulfill the contractual obligations required to retain its rights to explore, develop and exploit any of its undeveloped properties; on-stream timing of production from successful exploration wells; operational performance of non-operated producing fields; pipeline capacity; the benefits of initiating a review of strategic repositioning alternatives; and other matters. The ability of the Company to carry out its business plan is primarily dependent upon the continued support of its shareholders, the discovery of economically recoverable reserves and the ability of the Company to obtain financing or generate sufficient cash flow to develop such reserves.
Forward-looking statements and other information contained in this MD&A concerning the oil and natural gas industry in the countries in which it operates and the Company's general expectations concerning this industry are based on estimates prepared by Management using data from publicly available industry sources as well as from resource reports, market research and industry analysis and on assumptions based on data and knowledge of this industry which the Company believes to be reasonable. However, this data is inherently imprecise, although generally indicative of relative market positions, market shares and performance characteristics. While the Company is not aware of any material misstatements regarding any industry data presented herein, the oil and natural gas industry involves numerous risks and uncertainties and is subject to change based on various factors.
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Management has included forward looking information and the above summary of assumptions and risks related to forward-looking information in this MD&A in order to provide shareholders with a more complete perspective on the Company’s current and future operations and such information may not be appropriate for other purposes. The Company’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do, what benefits Parex will derive there from. These forward-looking statements are made as of the date of this MD&A and Parex disclaims any intent or obligation to update publicly any forwardlooking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.
This MD&A contains future oriented financial information and financial outlook information (collectively "FOFI") about the Company's prospective capital expenditures and working capital. The FOFI has been prepared by management to provide an outlook of the Company's activities and results and may not be appropriate for other purposes. The FOFI has been prepared based on a number of assumptions including the assumptions discussed above. The actual results of operations of the Company and the resulting financial results may vary from the amounts set forth herein, and such variations may be material. The Company and management believe that the FOFI has been prepared on a reasonable basis, reflecting management’s best estimates and judgments. FOFI contained in this MD&A was made as of the date of this MD&A and the Company disclaims any intention or obligations to update or revise any FOFI contained in this MD&A, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.
Oil & Gas Matters Advisory
This report contains a number of oil and gas metrics, including operating netbacks and FFO netbacks. These oil and gas metrics have been prepared by management and do not have standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics have been included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. Management uses these oil and gas metrics for its own performance measurements and to provide security holders with measures to compare the Company's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this report, should not be relied upon for investment or other purposes.
Non-GAAP Terms
This report contains financial terms that are not considered measures under GAAP such as operating netback, operating netback per boe, funds flow provided by operations, funds flow provided by operations per boe, funds flow netback per boe, free funds flow and diluted funds flow per share that do not have any standardized meaning under IFRS and may not be comparable to similar measures presented by other companies. Management uses these non-GAAP measures for its own performance measurement and to provide shareholders and investors with additional measurements of the Company’s efficiency and its ability to fund a portion of its future capital expenditures.
Funds flow provided by operations, is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital. A reconciliation from cash provided by operating activities to funds flow provided by operations is as follows:
| For the three months | For the three months | For the three months | |||
|---|---|---|---|---|---|
| ended March 31, | |||||
| ($000s) | 2021 | 2020 | |||
| Cash provided by operating activities | $ | 128,142 | $ | 155,299 | |
| Net change in non-cash workingcapital | **(3,173) ** | (57,986) | |||
| Funds flowprovided by operations | $ | 124,969 | $ | 97,313 |
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Funds flow provided by operations per boe or funds flow netback per boe , is a non-GAAP measure that includes all cash generated from operating activities and is calculated before changes in non-cash working capital, divided by produced oil and natural gas sales volumes. The Company considers funds flow netback to be a key measure as it demonstrates Parex’ profitability for all cash costs relative to current commodity prices and is calculated as follows:
| For the three months | For the three months | |||
|---|---|---|---|---|
| ended March 31, | ||||
| ($000s) | 2021 | 2020 | ||
| Funds flowprovided by operations | $ | 124,969 | $ 97,313 | |
| Denominator(BOEs) | ||||
| Company produced oil and naturalgas sales inperiod | 4,168,620 | 4,718,077 | ||
| Funds flowprovided by operationsper boe | $ | 29.98 | $ 20.63 |
Free funds flow is determined by funds flow provided by operations less capital expenditures as follows:
| For the three months | For the three months | For the three months | ||
|---|---|---|---|---|
| ended March 31, | ||||
| ($000s) | 2021 | 2020 | ||
| Funds flow provided by operations | $ | 124,969 | $ | 97,313 |
| Capital expenditures | 39,592 | 71,266 | ||
| Free funds flow | $ | 85,377 | $ | 26,047 |
Funds flow per share is calculated by dividing funds flow provided by operations by the weighted average number of shares outstanding. Parex presents basic and diluted funds flow provided by operations per share whereby per share amounts are calculated using weightedaverage shares outstanding, consistent with the calculation of earnings per share. The following table shows the variables used in the calculation of funds flow per share:
| For the three months | For the three months | For the three months | ||
|---|---|---|---|---|
| ended March 31, | ||||
| (000s) | 2021 | 2020 | ||
| Funds flowprovided by operations | $ 124,969 | $ | 97,313 | |
| Weighted average number of shares for the purposes of basic funds flow | 129,715 | 141,805 | ||
| Dilutive effect of share options onpotential common shares | 1,141 | 2,191 | ||
| Weighted average number of shares for thepurposes of diluted funds flow | 130,856 | 143,996 |
Adjusted EBITDA is defined as net income (loss) before interest, taxes, depletion and depreciation and adjusted for other non-cash items, transaction costs and extraordinary and non-recurring items. Adjusted EBITDA is solely used in the calculation of the bank covenant and is not considered a key performance measure by Management.
Operating netback per boe
The Company considers operating netbacks to be a key measure as they demonstrate Parex’ profitability relative to current commodity prices. Below is a description of each component of the Company's operating netback and how it is determined.
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Oil and natural gas sales per boe is determined by sales revenue excluding risk management contracts divided by total equivalent sales volume including purchased oil volumes. A reconciliation of the calculation of oil and natural gas sales per boe is provided below:
| For the three months | For the three months | For the three months | ||
|---|---|---|---|---|
| ended March 31, | ||||
| ($000s) | 2021 | 2020 | ||
| Oil and naturalgas revenue excludingrisk management contracts | $ | 222,058 |
$ | 193,618 |
| Denominator (BOEs) | ||||
| Company produced oil and natural gas sales in period | 4,168,620 | 4,718,077 | ||
| Purchased oil volumes sold | 36,810 | 315,133 | ||
| Total oil and naturalgas sales volumes | 4,205,430 | 5,033,210 | ||
| Salespriceper boe | $ | 52.80 |
$ | 38.47 |
Royalties per boe is determined by dividing royalty expense by the total equivalent sales volume and excludes purchased oil volumes. A reconciliation of royalties per boe is provided below:
| For the three months | For the three months | For the three months | ||
|---|---|---|---|---|
| ended March 31, | ||||
| ($000s) | 2021 | 2020 | ||
| Royalty expense | $ | 25,571 |
$ | 22,217 |
| Denominator(BOEs) | ||||
| Company produced oil and naturalgas sales inperiod | 4,168,620 | 4,718,077 | ||
| Royalty expenseper boe | $ | 6.13 |
$ | 4.71 |
Production expense per boe is determined by dividing production expense by the total equivalent sales volume and excludes purchased oil volumes. A reconciliation of production expense per boe is provided below:
| For the three months | For the three months | For the three months | ||
|---|---|---|---|---|
| ended March 31, | ||||
| ($000s) | 2021 | 2020 | ||
| Production Expense | $ | 24,416 |
$ | 25,062 |
| Denominator(BOEs) | ||||
| Company produced oil and naturalgas sales inperiod | 4,168,620 | 4,718,077 | ||
| Production expenseper boe | $ | 5.86 |
$ | 5.31 |
Transportation expense per boe is determined by dividing the transportation expense by the total equivalent sales volumes including purchased oil volumes. A reconciliation of transportation expense per boe is provided below:
| For the three | months | months | ||
|---|---|---|---|---|
| ended March 31, | ||||
| ($000s) | 2021 | 2020 | ||
| Transportation Expense | $ | 14,438 |
$ | 20,336 |
| Denominator(BOEs) | ||||
| Company produced oil and natural gas sales in period | 4,168,620 | 4,718,077 | ||
| Purchased oil volumes sold | 36,810 | 315,133 | ||
| Total oil and naturalgas sales volumes | 4,205,430 | 5,033,210 | ||
| Transportation expenseper boe | $ | 3.43 |
$ | 4.04 |
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Business Environment and Risks
Parex is exposed to various market and operational risks. For a discussion of these risks please refer to the Parex' AIF for the year ended December 31, 2020 as filed on SEDAR at www.sedar.com or Parex' website at www.parexresources.com.
Internal Controls over Financial Reporting
There has been no change in Parex' internal controls over financial reporting ("ICFR") or disclosure controls and procedures ("DC&P) during the period covered by this MD&A that materially affected, or is reasonably likely to materially affect, its ICFR or DC&P.
Off-Balance-Sheet Arrangements
The Company did not enter into any off-balance-sheet arrangements during the three months ended March 31, 2021.
Financial Instruments and Other Instruments
The Company’s non-derivative financial instruments recognized in the consolidated balance sheet consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair value. The fair values of the current financial instruments approximate their carrying value due to their short-term maturity.
Summary of Significant Accounting Policies
The accounting policies adopted are consistent with those of the previous financial year as described in note 3 of the Company’s consolidated financial statements for the year ended December 31, 2020.
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DIRECTORS
Wayne Foo Chairman of the Board
Lisa Colnett
Sigmund Cornelius
Robert Engbloom
Bob MacDougall
Glenn McNamara
Imad Mohsen
CORPORATE HEADQUARTERS
Parex Resources Inc. 2700, Eighth Avenue Place, West Tower 585 8 Avenue S.W., Calgary, Alberta, Canada T2P 1G1
Tel: 403-265-4800 Fax: 403-265-8216 E-mail: [email protected]
OPERATING OFFICES
Parex Resources Colombia Ltd. Sucursal Calle 113 No. 7-21, Of. 611, Edificio Teleport, Torre A, Bogotá, Colombia
AUDITORS
PricewaterhouseCoopers LLP Calgary, Alberta
LEGAL COUNSEL
Burnet, Duckworth & Palmer LLP Calgary, Alberta
TRANSFER AGENT AND REGISTRAR
Computershare Trust Company of Canada Calgary, Alberta
RESERVES EVALUATORS
Carmen Sylvain
Paul Wright
Tel: 571-629-1716 Fax: 571-629-1786
GLJ Petroleum Consultants Ltd. Calgary, Alberta
INVESTOR RELATIONS
OFFICERS & SENIOR EXECUTIVES
Imad Mohsen President and Chief Executive Officer
Eric Furlan Chief Operating Officer
Kenneth Pinsky Chief Financial Officer & Corporate Secretary
Daniel Ferreiro President, Parex Colombia & Country Manager
Michael Kruchten Sr. Vice President, Capital Markets & Corporate Planning
Tel: 403-517-1733 Fax: 403-265-8216
E-mail: [email protected]
Website: www.parexresources.com
Ryan Fowler Sr. Vice President, Exploration & Business Development
Michael Kruchten Sr. Vice President, Capital Markets & Corporate Planning
Jeff Meunier Vice President, New Ventures
Joshua Share Vice President, Corporate Services
ABBREVIATIONS
Oil and Natural Gas Liquids
bbl(s) barrel(s) mbbls one thousand barrels bbl(s)/d or bopd barrel(s) of oil per day BOE or boe barrel of oil equivalent, using the conversion factor of 6 Mcf: 1 bbl boe/d barrels of oil equivalent per day mcf thousand cubic feet mcf/d thousand cubic feet per day Other WTI West Texas Intermediate Brent Brent Ice Vasconia Vasconia Crude FFO Funds flow provided by operations
"BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 mcf: 1 bbl) is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
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March 31, 2021