CALGARY, Alberta, Nov. 09, 2022 (GLOBE NEWSWIRE) —
(PIPE – TSX)
Pipestone Energy Corp. (
“Pipestone”
or the
“Company”
) is reporting its third quarter 2022 financial and operational results. It is also providing an operations update and an update on its 3-year plan that forecasts moderated production growth, and a focus on shareholder returns.
MODERATED GROWTH WITH A FOCUS ON SHAREHOLDER RETURNS
:
Since the startup of Pipestone Energy Corp in January 2019, the Company has achieved significant production growth from approximately 1,500 boe/d at inception to Q3 2022 production of 32,100 boe/d, a 20-fold increase in less than four years. As a result of current and expected inflationary pressures and technical constraints, Pipestone is moderating its forecast annual growth rate over the next three years and shifting its focus toward maximizing free cash flow generation and shareholder returns. Average annual production growth for 2022 – 2025 is now expected to be 7 – 10%, versus approximately 16% previously. The Company’s 2023 production guidance is now 34,000 – 36,000 boe/d, down from 40,000 – 42,000 boe/d. Pipestone is also now targeting a long-term production plateau of 45,000 boe/d by year-end 2025, down from 55,000 boe/d previously. This moderated growth plan will enable the Company’s shift in focus towards delivering meaningful returns to shareholders.
Going forward, the implementation of a base dividend will provide a consistent cash return to shareholders. The Pipestone Board of Directors (the “
Board
”) has declared an inaugural quarterly dividend of $0.030 per common share, which will be payable on March 31, 2023, to shareholders of record at the close of business on March 15, 2023. This dividend rate provides an annualized yield of approximately 2.7% at the current share price. The dividend will be designated as an eligible dividend for Canadian income tax purposes. The Company forecasts that this base dividend can be maintained at a long-term average commodity price of approximately US$55 per barrel WTI and AECO $3.00 per GJ natural gas.
Pipestone has received board approval to seek a renewal of its Normal Course Issuer Bid (“NCIB”) with the TSX for a new 12-month period, commencing on November 25
th
, 2022. Pipestone’s inaugural NCIB was launched in November 2021 and was fully executed with the purchase and cancellation of 9.6 million common shares for an average price of approximately $4.44 per share. Presuming no material changes to the commodity price or macro environment, Pipestone plans to initiate a substantial issuer bid (“
SIB
”) in Q1 2023, under which Pipestone intends to offer to purchase for cancellation up to $50 million of its common shares (the “
Shares
”).
The Company will continue to target a run-rate average debt level of approximately $100 million, which equates to ~0.2x trailing debt-to-cash flow in 2023 at US$85 WTI, and ~0.5x at US$55 WTI. Free cash flow in excess of Pipestone’s announced debt target will be primarily allocated towards further shareholder returns, including the NCIB, future potential SIBs, and/or future additional dividends. Additionally, Pipestone expects to maintain a rolling hedge position of between 25 – 50% of forward 12 months net after royalties condensate and natural gas production, to mitigate the impact of commodity price volatility and support its shareholder return objectives.
THIRD QUARTER 2022 CORPORATE HIGHLIGHTS:
- In Q3 2022, Pipestone achieved record average quarterly production totaling 32,109 boe/d (28% condensate, 40% total liquids), representing a 7,405 boe/d or 30% increase over Q3 2021 production of 24,704 boe/d (30% condensate, 44% total liquids) and a 1,339 boe/d or 4% increase over Q2 2022 production of 30,770 boe/d (28% condensate, 41% total liquids);
- The Company generated revenue of $174.4 million, which represents a $74.2 million or 74% increase from Q3 2021 revenue of $100.2 million;
-
In Q3 2022, the Company’s operating netback
(
1)
was $31.88/boe, an increase of 45% over the Q3 2021 operating netback
(1)
of $22.01/boe. Excluding the realized loss on commodity risk management contracts of $2.52/boe, Pipestone’s operating netback
(
1)
for Q3 2022 was $34.40/boe; -
The Company produced adjusted funds flow from operations
(
1)
of $86.5 million ($0.46 per share basic and $0.30 per share fully diluted), nearly doubling its adjusted funds flow from operations
(1)
of 43.7 million ($0.23 per share basic and $0.16 per share fully diluted) in Q3 2021; -
Pipestone has realized robust returns on invested capital with Q3 2022 annualized ROCE
(
1)
and CROIC
(1)
of 33% and 31%, respectively, as compared to Q3 2021 annualized ROCE
(1)
and CROIC
(1)
of 18% and 21%, respectively; - Total capital expenditures, including capitalized general and administrative expenses (“G&A”), were $60.4 million during the three months ended September 30, 2022. The Company continued its 2022 Montney capital program with 5.5 net (7 gross) wells drilled and rig released and 7.5 net (9 gross) wells completed in the quarter;
-
In Q3 2022, the Company generated free cash flow
(
1)
of $26.1 million, representing 30% of its adjusted funds flow from operations
(1)
(three months ended September 30, 2021 – free cash flow deficit of $10.1 million). In executing its return of capital to shareholders plan, the Company utilized $13.2 million or 51% of the free cash flow
(
1)
to repurchase common shares during Q3 2022 pursuant to its normal course issuer bid (“
NCIB
”), with the remainder allocated to deleveraging its balance sheet. The Company anticipates that it will continue to produce free cash flow
(
1)
in Q4 2022 which it will direct primarily to deleveraging and buying back common shares; - As previously announced, the Company commenced its inaugural NCIB in Q4 2021. In Q3 2022, Pipestone purchased 3,150,000 common shares for cancellation at a weighted average price of $4.18 per share for a total consideration of $13.2 million including related commissions and fees. Subsequent to the quarter, and up to the date of this release, Pipestone has purchased an additional 1,188,547 common shares for a total of 9,598,347 common shares purchased to date since the launch of the NCIB program; and
-
The Company exited the third quarter of 2022 with net debt
(1)
of $180.2, representing a $24.2 million or 12% reduction from its December 31, 2021 net debt
(
1)
balance of $204.4. Pipestone’s net debt
(
1)
to annualized trailing quarter adjusted funds flow from operations
(1)
ratio at September 30, 2022 is 0.5x (September 30, 2021 – 1.3x) which demonstrates the strength of the Company’s current financial position. As Pipestone advances its business plan, it expects to continue to deleverage and improve upon these metrics.
(1) See “Advisory Regarding Non-GAAP Measures – Non-GAAP measures” advisory.
2022 GUIDANCE UPDATE:
2022 Corporate Guidance Update:
Pipestone is increasing its capital expenditure guidance for 2022, from $225 – $235 million to an estimate of $240 million. This increase of approximately $10 million (~4%) from the midpoint reflects the anticipated rig release of one additional well, additional infrastructure spending (including blending equipment at the 9-14 padsite) and inflationary pressures. Full year 2022 production guidance is unchanged, but Pipestone anticipates being in the lower half of the 31,000 – 33,000 boe/d range.
3-YEAR PLAN & CORPORATE GUIDANCE UPDATE (2022-2024):
|
Prev. 2022 Guidance |
2022 Guidance Update |
Prev. 2023 Forecast |
2023 Guidance Update |
2024 Forecast Update |
||||||
| Price Forecast |
US$95 WTI $0.80 CAD |
US$85 WTI $0.75 CAD |
US$90 WTI $0.80 CAD |
US$85 WTI | $0.75 CAD $4.00 AECO |
||||||
| $5.00 AECO | $5.00 AECO | $4.00 AECO | ||||||||
| Full Year Production (boe/d) | 31,000 – 33,000 | 31,000 – 33,000 | 40,000 – 42,000 | 34,000 – 36,000 | 40,000 – 42,000 | |||||
| AT Cash Flow ($MM) | $380 – $420 | $370 – $400 | $510 | $400 – $430 |
$400 (net of ~$55 MM in cash taxes) |
|||||
| Capex ($MM) | $225 – $235 | $235 – $245 | $250 | $245 – $265 | $220 | |||||
| Free Cash Flow C$MM) | $155 – $185 | $130 – $160 | $260 | $135 – $165 | $180 | |||||
| Base Dividend ($MM) | n.a. | n.a. | n.a. | $32 | $32 | |||||
| NCIB / SIB ($MM) | $50 – $60 | $45 | $50 | $50+ | – | |||||
| (Net Debt) / Net Cash ($MM) |
($95) – ($75) net debt |
($115) – ($95) net debt |
$125 net cash |
Pipestone is targeting a run-rate net debt of $100 million | ||||||
| LTM Debt / Cash Flow (x) |
0.2x |
0.3x |
n.a. |
|||||||
Note: For 2023E, a change of +/- US$10/bbl on WTI pricing increases / decreases free cash flow by ~$50 million. A change of +/- C$1/GJ in AECO pricing increases / decreases free cash flow by ~$30 million. Forecast net debt is inclusive of the base dividend, but exclusive of potential share repurchases under a SIB or the NCIB.
As a result of several technical, inflationary, and other economic factors discussed below, Pipestone is modifying its 3-year production forecast and target production plateau from approximately 55,000 boe/d to approximately 45,000 boe/d. Average annual production growth for 2022 – 2025 is now expected to be approximately 7 – 10%, versus approximately 16% previously. This reduced production growth rate will allow the Company to maximize free cash flow and returns to investors.
2023 Corporate Guidance:
Pipestone is guiding to 2023 production of 34,000 – 36,000 boe/d, which represents annual growth of approximately 10% over the midpoint of 2022 guidance and approximately 15% below previous guidance. The Company forecasts spending $245 – $265 million next year, which includes ~$30 – $35 million in delineation capital for the eastern portion of its land base. At a budget price forecast of US$85 WTI | $4.00 AECO | $0.75 CADUSD, this plan is expected to generate cash flow of $400 – $430 million, and free cash flow of $135 – $165 million.
OPERATIONS UPDATE
Drilling & Completions Update:
During the third quarter, Pipestone rig released 5.5 net (7 gross) wells, which includes 2 wells (of 6 total) from its 14-19 pad, 1.5 net (3 gross) wells on the 13-9 pad, and 2 wells (of 6 total) on its 11-05 pad. Pipestone anticipates drilling an additional 5 net wells during 2022, which includes the remaining wells on the 11-05 pad, as well as one well on the second phase of development at the 2-25 pad. On the 11-05 pad, Pipestone recently rig released its longest well drilled to date, with a lateral length of ~4,500 metres (vs. a previous record of ~3,800 metres).
The Company completed 7.5 net (9 gross) wells during the quarter, which includes 6 wells on the 14-19 pad, and 1.5 net (3 gross) wells on the 13-9 pad. Pipestone does not anticipate completing the 6 well 11-05 pad until early January 2023, and as such, does not have any additional completions planned for 2022.
New Well Results:
The four well 2-25 pad, which piloted reduced inter-well spacing of 200m (vs. 300m on the offsetting pad), has achieved an average IP90 of 3.8 MMcf/d raw gas + 365 bbl/d wellhead condensate (condensate gas ratio (“
CGR
”) of ~95 bbl/MMcf). While the well results at 2-25 are highly economic, Pipestone has concluded that 200m inter-well spacing within Upper/Middle Montney package (‘A’ & ‘B’) is suboptimal and has no plans at this time to further pilot this spacing. The six well 2-32 pad, which was brought on-stream in late August, has achieved an average IP60 of 2.2 MMcf/d raw gas + 293 bbl/d wellhead condensate (CGR of ~133 bbl/MMcf). These wells have produced with higher than forecast initial water cuts, resulting in a longer clean up time to achieve peak rates. Both the 2-25 and 2-32 pads are forecast to pay out in approximately 12 months at current strip commodity prices.
In early October, Pipestone brought the six well 14-19 pad on production, which includes three wells each in the Montney ‘B’ and Lower Montney ‘D’ bench. The Montney ‘B’ wells have achieved an average IP30 of 3.8 MMcf/d raw gas + 757 bbl/d wellhead condensate (CGR of ~201 bbl/MMcf), while the Lower Montney ‘D’ wells delivered 2.2 MMcf/d raw gas + 581 bbl/d wellhead condensate (CGR of ~263 bbl/MMcf) over the same producing duration. Lower Montney ‘D’ wells H
2
S levels are approximately 5% and are within the pipeline specifications of 8%, so blending is not required to produce these wells into production facilities. Payout periods of 6 and 8 months, for the Montney ‘B’ and Lower Montney ‘D’ wells, respectively, are forecast at current strip commodity prices.
In late October 2022, Pipestone equipped the 100/01-07-71-06 Lower Montney ‘D’ well drilled southeast off the 9-14 pad earlier this year with an H
2
S blending and testing skid. This well was originally tested in July and demonstrated strong deliverability. However, this well had elevated H
2
S readings of 11 – 15%, exceeding Pipestone’s pipeline limitations. With a blending skid installed, the Company has been able to produce the well into its gathering system. The well has been producing for 10 days at an average rate of 3.2 MMcf/d raw gas + 482 bbl/d of wellhead condensate (CGR of ~151 bbl/MMcf). While these early production results are encouraging, the Company will require more production data to fully quantify the economic impact of incremental facility capital and operating costs on developing the higher H
2
S content Lower Montney ‘D’ in this portion of the land base. As a result, Pipestone’s 2023 capital program will be predominantly focused on developing the Montney ‘B’ while it formulates its Lower Montney ‘D’ development strategy.
Facilities Update:
In early October 2022, a Pipestone funded expansion to the existing Keyera 8-15 compressor station was completed. Following the installation of a fourth compressor, the capacity of the 8-15 compressor station has increased by 30 MMcf/d to 120 MMcf/d. Based on field capital spending estimates to date, the Company anticipates earning an approximate 14% working interest in the entire 8-15 facility.
In late October 2022, Pipestone completed the commissioning of a water handling and disposal facility at its 15-25 pad, expanding the Company’s in-field water handling capacity by approximately 15,000 bbl/d. Pipestone partnered with Catapult Water Midstream and Topaz Energy Corp. to fund the facility, which earned each partner a 49.5% working interest, while Pipestone retains a 1% working interest and operatorship. This is an important project in optimizing the field with additional flexibility, production capacity and is expected to lower future operating costs. The arrangement carries a fixed monthly capital fee and an option to expand the water handling infrastructure in the future for an incremental capital fee. Inclusive of the implied capital fee and variable operating costs, Pipestone expects its water disposal cost to be approximately 50% lower per barrel of water at this facility as compared to previously disposing through other 3rd party disposal options.
Well Performance Expectations:
Over the past year, Pipestone has made significant progress in delineating the central and northern portions of its asset base. Appropriately characterizing the productivity, fluid windows and gas composition of the entire acreage position is critical to determining an appropriate development profile. Well performance observed to date in the central portion of the acreage, while still highly economic, is on average approximately 20% lower than historical results to the west of Pipestone’s north-south gathering trunkline. This reduction is attributable to both lower expected absolute productivity and lower expectations for initial and terminal condensate-gas-ratios on the go-forward development wells. As a result, the Company expects the majority of proved undeveloped locations at year-end 2022 to carry a modified lower CGR (VRGC1) type curve, with minimal remaining booked in the higher CGR (VRGC2 & VRGC3) type curve locations
(
1)
.
(1)
Please refer to Pipestone’s updated November 2022 Corporate Presentation for further details on specific type curve information, located at www.pipestonecorp.com. VRGC = “Very Rich Gas Condensate”
Processing Capacity Availability & Timing:
As a result of increased area development activity and production, Pipestone is reducing its expected go-forward utilization at the Pembina Gas Infrastructure (“
PGI
”) Hythe Gas Plant. The Company will continue to access its full firm capacity of 25 MMcf/d through the PGI facilities, but the consistent future availability of the 25 MMcf/d in interruptible processing capacity is less certain.
Additionally, as originally disclosed in its March 9, 2022 press release, Pipestone had originally expected incremental gas processing capacity from the expansion of an existing area sour gas plant to become available in Q3 2023. This capacity is now expected to become available in mid-2024 and remains subject to a successful final investment decision by the plant owner and operator.
Capital & Operating Costs:
In 2023, Pipestone expects inflation on oilfield services and consumables to persist, due to tight supply chains and increased labor and input costs worldwide and has incorporated an inflation factor of between 10 – 15% in its 2023 guidance. Additionally, Pipestone is experiencing upward pressure on its operating costs, both on in-field and flowthrough operating costs at the 3
rd
party processing facilities it utilizes. As a result, 2023 operating costs are currently expected to average between $12.00 and $13.00 per boe.
Pipestone Energy Corp. Third Quarter 2022 Highlights Table:
Pipestone Energy Corp. – Financial and Operating Highlights
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||
|
($ thousands, except per unit and per share amounts) |
2022 |
2021 |
2022 |
2021 | ||||||||||
|
Financial |
||||||||||||||
| Sales of liquids and natural gas |
$ |
174,440 |
$ | 100,227 |
$ |
538,350 |
$ | 254,031 | ||||||
| Cash from operating activities |
89,075 |
34,225 |
282,686 |
86,054 | ||||||||||
|
Adjusted funds flow from operations (1) |
86,466 |
43,691 |
283,221 |
107,431 | ||||||||||
| Per share, basic |
0.46 |
0.23 |
1.49 |
0.56 | ||||||||||
|
Per share, diluted (4) |
0.30 |
0.16 |
0.99 |
0.38 | ||||||||||
| Capital expenditures |
60,375 |
53,777 |
216,124 |
147,619 | ||||||||||
|
Free cash flow (deficit) (1) |
26,091 |
(10,086 | ) |
67,097 |
(40,188 | ) | ||||||||
| Income and comprehensive income |
57,533 |
18,757 |
166,680 |
16,613 | ||||||||||
| Per share, basic |
0.31 |
0.10 |
0.88 |
0.09 | ||||||||||
|
Per share, diluted (4) |
0.21 |
0.07 |
0.59 |
0.06 | ||||||||||
|
Adjusted EBITDA (1) |
90,963 |
47,986 |
297,046 |
120,215 | ||||||||||
|
Annualized cash return on invested capital (CROIC) (1) |
31 |
% |
21 | % |
33 |
% |
18 | % | ||||||
|
Annualized return on capital employed (ROCE) ( 1) |
33 |
% |
18 | % |
37 |
% |
14 | % | ||||||
|
Net Debt (end of period) ( 1) |
180,234 |
219,538 | ||||||||||||
|
Net debt to annualized adjusted fund flow from operations for the trailing period (1) |
0.5x |
1.3x |
0.5x |
1.5x | ||||||||||
|
Available funding (end of period) ( 1 ) |
99,189 |
5,180 | ||||||||||||
| Amount purchased under NCIB |
13,243 |
– |
34,473 |
– | ||||||||||
|
Common shares purchased under NCIB (000s) |
3,150 |
– |
7,461 |
– | ||||||||||
|
Common shares outstanding (000s) (end of period) |
185,631 |
191,801 | ||||||||||||
|
Weighted-average basic shares outstanding (000s) |
187,461 |
191,692 |
189,716 |
191,353 | ||||||||||
| Weighted-average diluted shares | ||||||||||||||
|
outstanding (000s) (4) |
284,265 |
280,480 |
286,606 |
279,900 | ||||||||||
|
Operations |
||||||||||||||
| Production | ||||||||||||||
|
Condensate (bbls/d) |
8,893 |
7,399 |
8,432 |
7,251 | ||||||||||
|
Other natural gas liquids (NGLs) (bbls/d) |
3,766 |
3,434 |
3,921 |
3,133 | ||||||||||
|
Total NGLs (bbls/d) |
12,659 |
10,833 |
12,353 |
10,384 | ||||||||||
|
Crude oil (bbls/d) |
41 |
78 |
51 |
84 | ||||||||||
|
Natural gas (Mcf/d) |
116,455 |
82,755 |
106,599 |
76,532 | ||||||||||
|
Total (boe/d) ( 2 ) |
32,109 |
24,704 |
30,171 |
23,223 | ||||||||||
|
Condensate and crude oil (mix of total production) |
28 |
% |
30 | % |
28 |
% |
32 | % | ||||||
|
Total liquids (mix of total production) |
40 |
% |
44 | % |
41 |
% |
45 | % | ||||||
|
Average realized prices ( 3 ) |
||||||||||||||
|
Condensate (per bbl) |
110.99 |
85.30 |
121.70 |
75.89 | ||||||||||
|
Other NGLs (per bbl) |
51.94 |
37.15 |
56.53 |
30.46 | ||||||||||
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||
| ($ thousands, except per unit and per share amounts) |
2022 |
2021 |
2022 |
2021 | ||||||||||
|
Total NGLs (per bbl) |
93.42 |
70.03 |
100.95 |
62.18 | ||||||||||
|
Crude oil (per bbl) |
108.64 |
74.05 |
118.08 |
67.14 | ||||||||||
|
Natural gas (per Mcf) |
6.09 |
3.93 |
6.75 |
3.65 | ||||||||||
| Netbacks | ||||||||||||||
|
Revenue (per boe) |
59.05 |
44.10 |
65.36 |
40.07 | ||||||||||
| Realized loss on commodity risk | ||||||||||||||
|
management contracts (per boe) |
(2.52 |
) |
(6.79 | ) |
(5.96 |
) |
(5.46) | |||||||
|
Royalties (per boe) |
(7.75 |
) |
(1.70 | ) |
(6.08 |
) |
(1.20) | |||||||
|
Operating expense (per boe) |
(13.48 |
) |
(10.94 | ) |
(12.54 |
) |
(10.91) | |||||||
|
Transportation expense (per boe) |
(3.42 |
) |
(2.66 | ) |
(3.72 |
) |
(2.67) | |||||||
|
Operating netback (per boe) (1) |
31.88 |
22.01 |
37.06 |
19.83 | ||||||||||
|
Adjusted funds flow netback (per boe) (1) |
29.27 |
19.22 |
34.38 |
16.94 | ||||||||||
(1)
See “Advisory Regarding Non-GAAP measures – Non-GAAP measures” advisory.
(2)
For a description of the boe conversion ratio, see “Oil and Gas Measures – Basis of Barrel of Oil Equivalent”. References to crude oil in production amounts are to the product type “tight oil” and references to natural gas in production amounts are to the product type “shale gas”. References to total liquids include oil and natural gas liquids (including condensate, butane and propane).
(3)
Figures calculated before hedging.
Weighted-average number of diluted shares outstanding for the purpose of calculating diluted income and comprehensive income and adjusted funds flow from operations per share in the 2022 periods presented includes 93,941,655 common shares that were issuable pursuant to the convertible preferred shares at September 30, 2022 for no additional proceeds to the Company (September 30, 2021 – 88,075,674 common shares issuable). The convertible preferred shares had a total convertible value of $79.9 million on September 30, 2022 (September 30, 2021 – $74.9 million) and were convertible on a conversion ratio equal to the quotient of (i) the liquidation preference of $1,000 per convertible preferred share, subject to adjustment, divided by (ii) the conversion price of $0.85 per share. On October 5, 2022, the 70,000 convertible preferred shares were settled for 93,941,655 common shares based on voluntary conversions by the holders effective September 30, 2022. The impact of other dilutive instruments is also factored into this calculation as applicable.
Third Quarter 2022 Financial Results Conference Call
Third quarter results are expected to be released before market open on November 9, 2022. A conference call has been scheduled for November 9, 2022 at 10:00 am Mountain Time (12:00 pm Eastern Time) for interested investors, analysts, brokers, and media representatives.
Conference Call Details:
Please use the following participant registration URL to register for the Q3 2022 Financial Results Conference Call:
https://register.vevent.com/register/BIeaf9fe749e5f4c76ab43b131fb45c8ba
. This registration link can also be found on the Company’s website. This link will provide each registrant with a toll-free dial in number and a unique PIN to connect to the call.
Pipestone Energy Corp.
Pipestone is an oil and gas exploration and production company focused on moderately growing its condensate-rich Montney asset base, while delivering meaningful shareholder returns. Pipestone expects to grow its production to 32 Mboe/d (midpoint) in 2022 and to approximately 45 Mboe/d by exit 2025, while generating significant free cash flow. Pipestone is committed to building long term value for our shareholders while maintaining the highest possible environmental and operating standards, as well as being an active and contributing member to the communities in which it operates. Pipestone has achieved certification of all its production from its Montney asset under the Equitable Origin EO100
TM
Standard for Responsible Energy Development. Pipestone shares trade under the symbol PIPE on the TSX. For more information, visit
www.pipestonecorp.com
.
Pipestone Energy Contacts:
|
Paul Wanklyn President and Chief Executive Officer (587) 392-8407 [email protected] |
Craig Nieboer Chief Financial Officer (587) 392-8408 [email protected] |
|
Dan van Kessel VP Corporate Development (587) 392-8414 [email protected] |
Advisory Regarding Non-GAAP Measures
Non-GAAP measures
Pursuant to section 5(4) of National Instrument 52-112 –
Non-GAAP and Other Financial Measures Disclosure
(”
NI 52-112
“), quantitative reconciliation of the non-GAAP measures for the current and comparative period to the most directly comparable financial measure cannot be incorporated by reference because this document is an earnings news release. As such, included is a quantitative reconciliation table for cash flow, free cash flow, operating netback, adjusted funds flow netback, net debt, available funding, adjusted EBITDA, CROIC, ROCE and adjusted funds flow from operations below. Additionally, pursuant to section 7(2)(d) of NI 52-112, a description of any significant difference between the non-GAAP financial measure that is forward-looking and the equivalent historical non-GAAP financial measure must be included in proximity to the first instance of the non-GAAP financial measure that is forward-looking information. As such, this information should be included in respect of forecast cashflow on page 3. Additionally, for this forward-looking non-GAAP measure, the following must be included: (i) the news release discloses an equivalent historical non-GAAP financial measure; and (ii) the forecast cashflow that is forward-looking information is presented with no more prominence in the document than that of the equivalent historical non-GAAP financial measure.
This news release includes references to financial measures commonly used in the oil and natural gas industry. The terms “cash flow”, “free cash flow, “operating netback”, “adjusted funds flow netback”, “net debt”, “available funding”, “adjusted EBITDA”, “CROIC”, and “ROCE” and “adjusted funds flow from operations” are not defined under IFRS, which have been incorporated into Canadian GAAP, as set out in Part 1 of the Chartered Professional Accountants Canada Handbook – Accounting, are not separately defined under GAAP, and may not be comparable with similar measures presented by other companies. The reconciliations of these non-GAAP measures to the nearest GAAP measure are discussed in the Non-GAAP measures section of Pipestone’s management’s discussion and analysis (“
MD&A
”) for the quarter ended September 30, 2022 dated November 9, 2022, a copy of which is available electronically on Pipestone’s SEDAR profile at
www.sedar.com
.
Management of the Company believes the presentation of non-GAAP measures provides useful information to investors and shareholders as the measures provide increased transparency and the opportunity to better analyze and compare performance against prior periods.
Adjusted funds flow from operations
Pipestone uses “adjusted funds flow from operations” (cash from operating activities before changes in non-cash working capital, cash share-based compensation and decommissioning provision costs incurred, if applicable), a measure that is not defined under IFRS. Adjusted funds flow from operations should not be considered an alternative to, or more meaningful than, cash from operating activities, income (loss) or other measures determined in accordance with IFRS as an indicator of the Company’s performance. Management of the Company uses adjusted funds flow from operations to analyze operating performance and leverage and believes it is a useful supplemental measure as it provides an indication of the funds generated by Pipestone’s principal business activities prior to consideration of changes in working capital, cash share-based compensation and decommissioning provision costs incurred.
The following table reconciles cash from operating activities to adjusted funds flow from operations:
|
Three months ended September 30, |
Nine months ended September 30, |
|||||
| ($ thousands) |
2022 |
2021 |
2022 |
2021 | ||
|
$ |
$ |
$ |
$ | |||
| Cash from operating activities |
89,075 |
34,225 |
282,686 |
86,054 | ||
| Change in non-cash working capital |
(2,609 ) |
9,244 |
(3,760 ) |
21,155 | ||
| Cash share-based compensation |
– |
– |
4,295 |
– | ||
| Decommissioning provision costs incurred |
– |
222 |
– |
222 | ||
| Adjusted funds flow from operations |
86,466 |
43,691 |
283,221 |
107,431 | ||
Operating netback and adjusted funds flow netback
Operating netback is calculated on either a total dollar or per-unit-of-production basis and is determined by deducting royalties, operating and transportation expense from liquids and natural gas sales adjusted for realized gains/losses on commodity risk management contracts.
The following table details the calculation of operating netback on a total dollar basis:
|
Three months ended September 30, |
Nine months ended September 30, |
|||||||
| ($ thousands) |
2022 |
2021 |
2022 |
2021 | ||||
|
$ |
$ |
$ |
$ | |||||
| Sales of liquids and natural gas |
174,440 |
100,227 |
538,350 |
254,031 | ||||
| Realized loss on commodity risk management contracts |
(7,436 ) |
(15,428) |
(49,120 ) |
(34,626) | ||||
| Royalties |
(22,891 ) |
(3,856) |
(50,038 ) |
(7,582) | ||||
| Operating expense |
(39,831 ) |
(24,862) |
(103,249 ) |
(69,141) | ||||
| Transportation expense |
(10,100 ) |
(6,052) |
(30,672 ) |
(16,912) | ||||
| Operating netback |
94,182 |
50,029 |
305,271 |
125,770 | ||||
The following table reconciles cash from operating activities to operating netback:
|
Three months ended September 30, |
Nine months ended September 30, |
|||
| ($ thousands) |
2022 |
2021 |
2022 |
2021 |
|
$ |
$ |
$ |
$ | |
| Cash from operating activities |
89,075 |
34,225 |
282,686 |
86,054 |
| Change in non-cash working capital |
(2,609 ) |
9,244 |
(3,760 ) |
21,155 |
| G&A expense |
3,219 |
2,043 |
8,225 |
5,555 |
| Cash share-based compensation |
– |
– |
4,295 |
– |
| Cash financing expense |
4,765 |
4,036 |
13,821 |
12,017 |
| Decommissioning provision costs incurred |
– |
222 |
– |
222 |
| Realized (gain) loss on interest rate risk management contracts |
(268 ) |
259 |
4 |
767 |
| Operating netback |
94,182 |
50,029 |
305,271 |
125,770 |
| G&A expense |
3,219 |
2,043 |
8,225 |
5,555 |
| Cash financing expense |
4,765 |
4,036 |
13,821 |
12,017 |
| Realized (gain) loss on interest rate risk management contracts |
(268 ) |
259 |
4 |
767 |
| Adjusted funds flow netback |
86,466 |
43,691 |
283,221 |
107,431 |
Adjusted funds flow netback reflects adjusted funds flow from operations on a per-unit-of-production basis and is determined by dividing adjusted funds flow from operations by total production on a per-boe basis. Adjusted funds flow netback can also be determined by deducting G&A, transaction costs, cash financing expense, adding financing income and adjusting for realized gains/losses on interest rate risk management contracts on a per-unit-of-production basis from the operating netback.
Operating netback and adjusted funds flow netback are common metrics used in the oil and natural gas industry and are used by the Company’s management to measure operating results on a per boe basis to better analyze and compare performance against prior periods, as well as formulate comparisons against peers. These measures should not be considered an alternative to or more meaningful than cash from operating activities defined under IFRS.
Adjusted working capital and available funding
Available funding is comprised of adjusted working capital and undrawn portions of the Company’s credit facility. The available funding measure allows management of the Company and others to evaluate the Company’s short-term liquidity. Adjusted working capital is a non-GAAP measure and is comprised of current assets less current liabilities on the Company’s consolidated statement of financial position and excludes the current portion of risk management contracts and lease liabilities. Adjusted working capital should not be considered an alternative to, or more meaningful than, working capital as defined under IFRS.
Cash flow
Cash flow is a non-GAAP measure that is calculated as cash from operating activities plus changes in non-cash working capital, cash share-based compensation and decommissioning provision costs incurred, and is not defined under IFRS. Cash flow should not be considered an alternative to, or more meaningful than, cash from operating activities, income (loss) or other measures determined in accordance with IFRS as an indicator of the Company’s performance. Management of the Company uses cash flow to analyze operating performance and leverage and believes it is a useful supplemental measure as it provides an indication of the funds generated by Pipestone’s principal business activities prior to consideration of changes in working capital, cash share-based compensation and decommissioning provision costs incurred.
The following table reconciles cash from operating activities to cash flow:
|
Three months ended September 30, |
Nine months ended September 30, |
||||||
| ($ thousands) |
2022 |
2021 |
2022 |
2021 | |||
|
$ |
$ |
$ |
$ | ||||
| Cash from operating activities |
89,075 |
34,255 |
282,686 |
86,054 | |||
| Change in non-cash working capital |
(2,609 ) |
9,244 |
(3,760 ) |
21,155 | |||
| Cash share-based compensation |
– |
– |
4,295 |
– | |||
| Decommissioning provision costs incurred |
– |
222 |
– |
222 | |||
| Cash flow |
86,466 |
35,498 |
283,221 |
63,740 | |||
Free Cash Flow
Free cash flow should not be considered an alternative to, or more meaningful than, cash from operating activities as determined in accordance with IFRS as an indicator of financial performance. Free cash flow is presented to assist management of the Company and investors in analyzing operating performance by the business and how much cash flow is available for deleveraging and/or shareholder returns in the stated period after capital expenditures have been incurred. Free cash flow equals cash from operating activities plus the change in non-cash working capital and cash share-based compensation less capital expenditures.
The following table reconciles cash from operating activities to free cash flow:
|
Three months ended September 30, |
Nine months ended September 30, |
|||
| ($ thousands) |
2022 |
2021 |
2022 |
2021 |
|
$ |
$ |
$ |
$ | |
| Cash from operating activities |
89,075 |
34,255 |
282,686 |
86,054 |
| Change in non-cash working capital |
(2,609 ) |
9,244 |
(3,760 ) |
21,155 |
| Cash share-based compensation |
– |
– |
4,295 |
– |
| Decommissioning provision costs incurred |
– |
222 |
– |
222 |
| Capital expenditures |
(60,375 ) |
(53,777) |
(216,124 ) |
(147,619) |
| Free cash flow |
26,091 |
(10,086) |
67,097 |
(40,188) |
Net debt
Net debt is a non-GAAP measure that equals bank debt outstanding and adjusted working capital. The Company did not consider its convertible preferred share obligation to be part of net debt as this represented a non-cash obligation that was ultimately settled by conversion into Shares on October 5, 2022 and is reclassified from a liability to share capital on the Company’s statement of financial position. Net debt is considered to be a useful measure in assisting management of the Company and investors to evaluate Pipestone’s financial strength.
Adjusted EBITDA, CROIC and ROCE
Adjusted EBITDA is calculated as profit or loss before interest, income taxes, depletion and depreciation, adjusted for other non-cash and extraordinary items including unrealized gains and losses on risk management contracts, realized losses on interest rate risk management contracts, share-based compensation and E&E expense. Adjusted EBITDA is considered a useful measure by management of the Company to understand and compare the profitability of Pipestone to other companies excluding the effects of capital structure, taxation and depreciation. Adjusted EBITDA is not defined under IFRS and therefore may not be comparable with the calculation of similar measures by other entities and should not be considered an alternative to, or more meaningful than, income (loss) and comprehensive income (loss). Adjusted EBITDA is also used to calculate CROIC. Adjusted EBIT is calculated as adjusted EBITDA less depletion and depreciation. Adjusted EBIT is used to calculate ROCE.
The following table reconciles income (loss) and comprehensive income (loss) to adjusted EBITDA:
|
Three months ended September 30, |
Nine months ended September 30, |
|||
| ($ thousands) |
2022 |
2021 |
2022 |
2021 |
|
$ |
$ |
$ |
$ | |
| Net income and comprehensive income |
57,533 |
18,757 |
166,680 |
16,613 |
| Deferred income tax expense |
18,118 |
6,482 |
50,781 |
7,209 |
| Financing expense |
6,532 |
5,526 |
18,772 |
16,797 |
| Unrealized (gain) loss on interest rate risk management contracts |
(21 ) |
(242) |
(1,498 ) |
(1,006) |
| Realized (gain) loss on interest rate risk management contracts |
(268 ) |
259 |
4 |
767 |
| D&D expense |
20,766 |
16,849 |
58,516 |
47,454 |
| E&E expense |
829 |
1,244 |
1,658 |
1,658 |
| Share-based compensation |
1,447 |
1,075 |
7,524 |
2,660 |
| Unrealized (gain) loss on commodity risk management contracts |
(13,973 ) |
(1,964) |
(5,391 ) |
28,063 |
| Adjusted EBITDA |
90,963 |
47,986 |
297,046 |
120,215 |
CROIC is determined by dividing adjusted EBITDA by the gross carrying value of the Company’s oil and gas assets at a point in time. For the purposes of the CROIC calculation, the net carrying value of the Company’s exploration and evaluation assets, property and equipment and ROU assets, is taken from the Company’s consolidated statement of financial position, and excludes accumulated depletion and depreciation as disclosed in the financial statement notes to determine the gross carrying value.
ROCE is determined by dividing adjusted EBIT by the carrying value of the Company’s net assets. For the purposes for the ROCE calculation, net assets are defined as total assets on the Company’s consolidated statement of financial position less current liabilities at a point in time.
CROIC and ROCE allow management of the Company and others to evaluate the Company’s capital spending efficiency and ability to generate profitable returns by measuring profit or loss relative to the capital employed in the business.
The Company has calculated its CROIC and ROCE using annualized results for the three and nine months ended September 30, 2022 and balances as at September 30, 2022 and 2021 as follows:
|
Three months ended September 30, |
Nine months ended September 30, |
|||
| ($ thousands) |
2022 |
2021 |
2022 |
2021 |
|
$ |
$ |
$ |
$ | |
| Adjusted EBITDA |
90,963 |
47,986 |
297,046 |
120,215 |
|
Annualized Adjusted EBITDA ( 1) |
363,852 |
191,944 |
396,061 |
160,287 |
(1) Annualized factor 4x for the three months ended September 30, 2022 and 2021. Annualized factor 1.33x for the nine months ended September 30, 2022 and 2021.
|
As at September 30, |
||
| ($ thousands) |
2022 |
2021 |
|
$ |
$ | |
| Exploration and evaluation (E&E) assets – gross carrying value |
28,212 |
32,625 |
| Property and equipment (P&E) – net carrying value |
885,001 |
693,325 |
| P&E – accumulated D&D |
174,088 |
106,454 |
| E&E assets and P&E – gross carrying value |
1,087,301 |
832,404 |
| ROU assets – net carrying value |
75,485 |
50,082 |
| ROU assets – accumulated depreciation |
22,174 |
12,732 |
| E&E, P&E and ROU assets – gross carrying value |
1,184,960 |
895,218 |
|
Annualized CROIC (three months ended September 30) |
31 % |
21% |
|
Annualized CROIC (nine months ended September 30) |
33 % |
18% |
|
Three months ended September 30, |
Nine months ended September 30, |
|||
| ($ thousands) |
2022 |
2021 |
2022 |
2021 |
|
$ |
$ |
$ |
$ | |
| Adjusted EBITDA |
90,963 |
47,986 |
297,046 |
120,215 |
| D&D expense |
(20,766 ) |
(16,849) |
(58,516 ) |
(47,454) |
| Adjusted EBIT |
70,197 |
31,137 |
238,530 |
72,761 |
|
Annualized Adjusted EBIT ( 1) |
280,788 |
124,548 |
318,040 |
97,015 |
(1) Annualized factor 4x for the three months ended September 30, 2022 and 2021. Annualized factor 1.33x for the nine months ended September 30, 2022 and 2021.
|
As at September 30, |
||
| ($ thousands) |
2022 |
2021 |
|
$ |
$ | |
| Total assets |
1,064,129 |
828,261 |
| Total current liabilities |
(208,239 ) |
(121,580) |
| Net Assets |
855,890 |
706,681 |
|
Annualized ROCE (three months ended September 30) |
33 % |
18% |
|
Annualized ROCE (nine months ended September 30) |
37 % |
14% |
Advisory Reg
arding Forward-Looking Statements
In the interest of providing shareholders of Pipestone and potential investors information regarding Pipestone, this news release contains certain information and statements (“
forward-looking statements
”) that constitute forward-looking information within the meaning of applicable Canadian securities laws. Forward-looking statements relate to future results or events, are based upon internal plans, intentions, expectations and beliefs, and are subject to risks and uncertainties that may cause actual results or events to differ materially from those indicated or suggested therein. All statements other than statements of current or historical fact constitute forward-looking statements. Forward-looking statements are typically, but not always, identified by words such as “anticipate”, “estimate”, “expect”, “intend”, “forecast”, “continue”, “propose”, “may”, “will”, “should”, “believe”, “plan”, “target”, “objective”, “project”, “potential” and similar or other expressions indicating or suggesting future results or events.
Forward-looking statements are not promises of future outcomes. There is no assurance that the results or events indicated or suggested by the forward-looking statements, or the plans, intentions, expectations or beliefs contained therein or upon which they are based, are correct or will in fact occur or be realized (or if they do, what benefits Pipestone may derive therefrom).
In particular, but without limiting the foregoing, this news release contains forward-looking statements pertaining to: expected dividends; the expected timing of the inaugural quarterly dividend; the expectation that the quarterly dividend will provide consistent cash return to shareholders; the expectation that the quarterly dividend can be maintained in conjunction with the forecasted long-term average commodity price; Pipestone’s intention to undertake the SIB and the terms thereof, including the maximum size of the SIB and the timing thereof; Pipestone’s capital investment program, including drilling and other development plans for the remainder of 2022 and beyond, the Company’s intention to continue growth of production, cash flow and free cash flow; the Company’s intention to direct free cash flow to deleveraging and buying back Shares; Pipestone’s intention to renew the NCIB and to continue to purchase Shares under the renewed NCIB in 2023; the number of Shares the Company expects to purchase under the renewed NCIB; the Company’s commitment to providing shareholder returns including the NCIB, future potential SIBs and future additional dividends; expectations regarding the Company’s 2022 and 2023 business plan and its ability to deleverage; expected timing to reduce net debt; expectations regarding timing of completing the 6 well 11-5 pad; Pipestone’s expectations regarding the payout periods for the 2-25 pad, the 2-35 pad and the Montney ‘B’ and Lower Montney ‘D’ wells; the Company’s intention to focus its 2023 capital program on developing the Montney ‘B’ while formulating a development strategy for Montney ‘D’; the Company’s expectation that the majority of its proved undeveloped locations will carry a modified VRGC1 type curve, with minimal remaining booked VRGC2 and VRGC3 locations; the Company’s expectation that it will earn an approximate 14% working interest in the 8-15 facility; Pipestone’s expectation that the water handling and disposal facility at the 15-25 pad will lower future operating costs; expectations regarding 2022 and 2023 annual production volumes and beyond; the Company’s access to gas processing capacity and the timing that incremental gas processing capacity will become available; expectations regarding the Company’s operating costs for 2023; forecasted average production volumes for Q4 2022; 2023, 2024 and 2025 forecasts for each of production, cash flow, capital expenditures/development plans, free cash flow, net debt/net cash and cash flow; the Company’s expectations with respect to capital management and liquidity; and the Company’s long-term strategy.
With respect to the forward-looking statements contained in this news release, Pipestone has assessed material factors and made assumptions regarding, among other things: future commodity prices and currency exchange rates, including consistency of future oil, NGLs and natural gas prices with current commodity price forecasts; interest rates; the economic impacts of the COVID-19 pandemic; Pipestone’s continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the predictability of future results based on past and current experience; the predictability and consistency of the legislative and regulatory regime governing royalties, taxes, environmental matters and oil and gas operations, both provincially and federally; Pipestone’s ability to successfully market its production of oil, NGLs and natural gas; the timing and success of drilling and completion activities (and the extent to which the results thereof meet expectations); Pipestone’s future production levels and amount of future capital investment, and their consistency with Pipestone’s current development plans and budget; future capital expenditure requirements and the sufficiency thereof to achieve Pipestone’s objectives; the successful application of drilling and completion technology and processes; the applicability of new technologies for recovery and production of Pipestone’s reserves and other resources, and their ability to improve capital and operational efficiencies in the future; the recoverability of Pipestone’s reserves and other resources; Pipestone’s ability to economically produce oil and gas from its properties and the timing and cost to do so; the performance of both new and existing wells; future cash flows from production; future sources of funding for Pipestone’s capital program and its ability to obtain external financing when required and on acceptable terms; future debt levels; geological and engineering estimates in respect of Pipestone’s reserves and other resources; the accuracy of geological and geophysical data and the interpretation thereof; the geography of the areas in which Pipestone conducts exploration and development activities; the timely receipt of required regulatory approvals, including approval of the TSX for the NCIB; the access, economic, regulatory and physical limitations to which Pipestone may be subject from time to time; and the impact of industry competition.
The forward-looking statements contained herein reflect management of the Company’s current views, but the assessments and assumptions upon which they are based may prove to be incorrect. Although Pipestone believes that its underlying assessments and assumptions are reasonable based on currently available information, undue reliance should not be placed on forward-looking statements, which are inherently uncertain, depend upon the accuracy of such assessments and assumptions, and are subject to known and unknown risks, uncertainties and other factors, both general and specific, many of which are beyond Pipestone’s control, that may cause actual results or events to differ materially from those indicated or suggested in the forward-looking statements. Such risks and uncertainties include, but are not limited to, volatility in market prices and demand for oil, NGLs and natural gas and hedging activities related thereto; the ability to successfully manage the Company’s operations; general economic, business and industry conditions; variance of Pipestone’s actual capital costs, operating costs and economic returns from those anticipated; the ability to find, develop or acquire additional reserves and the availability of the capital or financing necessary to do so on satisfactory terms; the availability of sufficient natural gas processing capacity; and risks related to the exploration, development and production of oil and natural gas reserves. Additional risks, uncertainties and other factors are discussed in the MD&A dated November 9, 2022 and in Pipestone’s annual information form dated March 9, 2022, copies of which are available electronically on Pipestone’s SEDAR profile at
www.sedar.com
.
Certain information in this news release is a “financial outlook” within the meaning of applicable Canadian securities laws. The purpose of the financial outlook is to provide readers with disclosure of the Company’s reasonable expectations of anticipated results. The financial outlook is provided as of the date of this news release. Certain assumptions made underlying the financial outlook are disclosed herein under “3-Year Plan Update & Corporate Guidance”. Readers are cautioned that the financial outlook may not be appropriate for other purposes.
The forward-looking statements contained in this news release are made as of the date hereof and Pipestone assumes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, unless required by applicable securities laws. All forward-looking statements herein are expressly qualified by this advisory.
Oil and Gas Measures
Basis of barrel of oil equivalent
Petroleum and natural gas reserves and production volumes are stated as a “barrel of oil equivalent” (boe), derived by converting natural gas to oil equivalency in the ratio of 6,000 cubic feet of gas to one barrel of oil. Readers are cautioned that boe figures may be misleading, particularly if used in isolation. A boe conversion ratio of 6,000 cubic feet of gas to one barrel of oil is based on energy equivalency, which is primarily applicable at the burner tip, and does not represent a value equivalency at the wellhead.
Initial Production Rates and Short-Term Test Rates
This news release may disclose test rates of production for certain wells over short periods of time (i.e. IP30, IP60, IP90, etc.), which are preliminary and not determinative of the rates at which those or any other wells will commence production and thereafter decline. Short-term test rates are not necessarily indicative of long-term well or reservoir performance or of ultimate recovery. Although such rates are useful in confirming the presence of hydrocarbons, they are preliminary in nature, are subject to a high degree of predictive uncertainty as a result of limited data availability and may not be representative of stabilized on-stream production rates.
Production over a longer period will also experience natural decline rates, which can be high in the Montney play and may not be consistent over the longer term with the decline experienced over an initial production period. Initial production or test rates may also include recovered “load” fluids used in well completion stimulation operations. Actual results will differ from those realized during an initial production period or short-term test period, and the difference may be material.
Production
References to natural gas and condensate production in this news release refer to the shale gas and natural gas liquids (which includes condensate), respectively, product types as defined in National Instrument 51-101 –
Standards of Disclosure for Oil and Gas Activities
. References to liquids include tight oil and NGLs (including condensate, butane and propane).
Abbreviations
The following summarizes the abbreviations used in this document:
|
Crude Oil, Condensate and other Natural Gas Liquids and Natural Gas |
||||
| bbl | barrel | Mcf | thousand cubic feet | |
| bbls/d | barrels per day | MMcf | million cubic feet | |
| boe | barrel of oil equivalent | Mcf/d | thousand cubic feet per day | |
| boe/d | barrel of oil equivalent per day | GJ | Gigajoule; 1 Mcf of natural gas is about 1.05 GJ | |
| Mboe/d | thousand barrels of oil equivalent per day | MMcf/d | million cubic feet per day | |
| NGL |
natural gas liquids, consisting of ethane (C 2 ), propane (C 3 ) and butane (C 4 ) |
|||
| condensate |
Pentanes plus (C 5 +) separated at the field level and C 5 + separated from the NGL mix at the facility level |
|||
|
Other Abbreviations |
|
| adjusted working capital | working capital (current assets less current liabilities), excluding financial derivative instruments and lease liabilities |
| AECO | the AECO Hub, a natural gas storage facility located in Suffield and Countess, Alberta, part of the NOVA Pipeline System |
| C$ | Canadian dollars |
| COVID-19 | Novel Coronavirus and its variants |
| CROIC | cash return on invested capital |
| D&D | depletion and depreciation |
| E&E | exploration and evaluation |
| EBIT | earnings before interest and taxes |
| EBITDA | earnings before interest, taxes, depreciation and amortization |
| G&A | general and administrative |
| GAAP | generally accepted accounting principles |
|
H 2 S |
hydrogen sulfide |
| IFRS | International Financial Reporting Standards |
| NCIB | normal course issuer bid |
| Q1 |
first quarter ended March 31 st |
| Q2 |
second quarter ended June 30 th |
| Q3 |
third quarter ended September 30 th |
| Q4 |
fourth quarter ended December 31 st |
| ROCE | return on capital employed |
| ROU | right-of-use |
| sour gas | natural gas containing H₂S in quantities greater than 100 ppm |
| TSX | Toronto Stock Exchange |
| US$ | United States dollars |
| WTI | West Texas Intermediate |
A photo accompanying this announcement is available at
https://www.globenewswire.com/NewsRoom/AttachmentNg/5ae19efd-ab6e-46db-8975-f2fd027831b7
Featured image: Megapixl © alek0505
