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 25th, 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):
|Price Forecast||US$95 WTI
|US$85 WTI $0.75 CAD||US$90 WTI
|US$85 WTI | $0.75 CAD
|$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)
|($115) – ($95)
|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.
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 H2S 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 H2S blending and testing skid. This well was originally tested in July and demonstrated strong deliverability. However, this well had elevated H2S 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 H2S 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.
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 3rd 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|
|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|
|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|
|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|
|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.