Pipestone Energy Corp. — Interim / Quarterly Report 2021

May 12, 2021

MANAGEMENT’S DISCUSSION AND ANALYSIS

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HIGHLY FOCUSED ON DEVELOPING THE EXCEPTIONAL MONTNEY PLAY

FOR THE THREE MONTHS ENDED MARCH 31, 2021

Pipestone Energy Corp. – Financial and Operating Highlights

($ thousands, except per unit and per share amounts)	Three months ended March 31, 2021 2020
Financial Sales of liquids and natural gas Cash from operating activities Adjusted funds flow from operations (1) Per share, basic Per share, diluted(4) Income (loss) Per share, basic and diluted Capital expenditures Property acquisitions Working capital deficit_(end of period) Bank debt(end of period) Net debt(end of period)(1) Shareholders’ equity(end of period) Available funding(end of period)(1) Undrawn credit facility capacity(end of period) Annualized cash return on invested capital (CROIC) (1) Annualized return on capital employed (ROCE) (1) Shares outstanding(end of period) Weighted-average number of basic shares outstanding Weighted-average number of diluted shares outstanding(4) Operations Production Condensate(bbls/d) Other natural gas liquids (NGLs)(bbls/d) Total NGLs(bbls/d) Crude oil(bbls/d) Natural gas(Mcf/d) Total(boe/d)(2) Condensate and crude oil(% of total production) Total liquids(% of total production) Benchmark prices Crude oil – WTI(C$/bbl) Condensate – Edmonton Condensate(C$/bbl) Natural gas – AECO(C$/GJ) Average realized prices(3) Condensate(per bbl) Other NGLs(per bbl) Total NGLs(per bbl) Crude oil(per bbl) Natural gas(per Mcf) Netbacks Revenue(per boe) Realized (loss) gain on commodity risk management contracts(per boe)(5) Royalties(per boe) Operating expenses(per boe) Transportation(per boe) Operating netback(per boe) (1) (5) Adjusted funds flow netback(per boe)_(1)	$ 71,485 $ 32,017 18,097 31,067 28,242 11,820 0.15 0.06 0.10 0.06 (954) 15,541 (0.00) 0.08 46,289 29,154 125 - 47,209 7,103 166,659 163,000 190,213 187,140 354,747 386,147 $ 34,552 $ 23,608 58,106 47,748 16.5% 9.5% 10.9% 1.8% 191,348 189,906 190,891 189,820 276,524 189,942 7,004 3,955 2,745 1,265
	9,749 5,220 91 88 70,527 52,546
	21,595 14,066 33% 29% 46% 38% $ 73.24 $ 61.34 74.59 60.12 3.07 1.92 65.03 52.89 26.79 17.97
	54.26 44.43 59.52 40.99 3.69 2.21 36.78 25.01 (4.32) 4.82 (1.66) (1.14) (10.64) (11.42) (2.62) (3.66) 17.54 13.61 $ 14.52 $ 9.24

(1) See “Non-GAAP measures” section of this MD&A for description.

• (2) For a description of the boe conversion ratio, see “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.

• (4) Weighted-average number of diluted shares outstanding for the purpose of calculating diluted adjusted funds flow from operations per share in the 2021 period presented includes 85,281,505 common shares that are issuable at the discretion of preferred shareholders as of March 31, 2021 for no additional proceeds to the Company. The preferred shares have a total convertible value of $72.5 million at March 31, 2021 and are convertible at $0.85 per common share.

• (5) Realized gain (loss) on commodity risk management contracts reclassified to be included under operating netback for 2021, prior period figures have been adjusted to conform with current presentation.

Management’s Discussion and Analysis

This management’s discussion and analysis (MD&A) of operating and financial results of Pipestone Energy Corp. (“Pipestone Energy” or the “Company”) is dated May 12, 2021 and is based on currently available information. It should be read in conjunction with the audited financial statements and accompanying notes for the years ended December 31, 2020 and 2019 and the unaudited condensed interim consolidated financial statements and accompanying notes for the three months ended March 31, 2021 and 2020. Unless otherwise noted, all financial information is presented in thousands of Canadian dollars and is in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB), interpretations of the International Financial Reporting Interpretations Committee (IFRIC), and with Canadian generally accepted accounting principles (GAAP) as applicable to interim financial statements, including International Accounting Standard (IAS) 34, Interim Financial Reporting . These documents, along with other statutory filings, are available on SEDAR at www.sedar.com and on the Company’s website at www.pipestonecorp.com.

Refer to the end of the MD&A for commonly used abbreviations.

Readers should also refer to “Forward-Looking Statements” at the end of the MD&A, which explains the basis for and limitations of statements throughout this report that are not historical facts and may be considered “forward-looking statements” under securities regulations. Additional risks, uncertainties and other factors are discussed in Pipestone Energy’s annual information form dated March 10, 2021, a copy of which is available electronically on SEDAR at www.sedar.com.

Description of Pipestone Energy

Pipestone Energy is engaged in the exploration for, and development and production of, oil and natural gas liquids (including condensate, butane and propane) herein collectively referenced as “liquids” as well as natural gas in Western Canada. The Company’s head office is located in Calgary, Alberta. The Company is focused on developing its liquids-rich assets in the Pipestone area of the Alberta Montney trend. Pipestone Energy is committed to building long term value for its shareholders and values the partnerships that it is developing within its operating community. Pipestone Energy is incorporated under the Business Corporations Act (Alberta) and its shares trade on the Toronto Stock Exchange under the symbol PIPE.

Outlook

Pipestone Energy’s current development program is fully funded and positions the Company to deliver significant production and cash flow growth in 2021 and 2022. The Company’s development will be optimized through a continuous drilling and completions program, and in the near term will focus on developing inventory located adjacent to existing in-field infrastructure. See the “Operations Update” below for more information on capital activity during the quarter.

At current commodity prices, Management believes that Pipestone Energy can deliver positive corporate returns on capital, and expects that, the Company can generate significant annual free cash flow beginning in 2022, and thereafter. With the cost reductions and well results achieved to date, the Company

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anticipates it can deliver on its development plan within its current $225.0 million borrowing capacity, while reducing leverage metrics over the next three years.

Updated Pipestone Capital Program Map:

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3 Year Corporate Guidance and Forecast[ (1) ]

Pipestone Energy has a robust three-year development plan that is expected to significantly grow production and generate free cash flow starting in 2022, while realizing positive returns on capital employed. The current outlook includes a small outspend of cash flow in 2021 resulting in net debt peaking in late 2021 and then significantly tapering as free cash flow is realized through 2022 and 2023.

	Base Price: 2021 Guidance	Base Price: 2022 Forecast	Base Price: 2023 Forecast	Upside Oil Price: 2023 Forecast
Price Forecast	US$55 WTI $2.50 AECO $0.785 CAD	US$55 WTI $2.50 AECO $0.785 CAD	US$55 WTI $2.50 AECO $0.785 CAD	US$65 WTI $2.50 AECO $0.785 CAD
Full Year Production(boe/d)	24,000 – 26,000(1)	33,000 – 36,000	37,000 – 40,000	37,000 – 40,000
Cash Flow(C$million)(2)(3)	$140 -$150	$235	$255	$320
Capex(C$million)(4)	$155 -$165	$195	$130	$130
Free Cash Flow(C$million) (3)	($15)	$40	$125	$190
YE Net Debt(C$million)(3)	$185	$145	$20	$0
LTM Debt/Cash Flow(x)	1.2x	0.6x	0.1x	0.0x

(1) 3-year plan as at March 2021, derived by utilizing, among other assumptions, historical Pipestone Energy production performance and current capital and operating cost assumptions held flat for illustration only. Budgets and forecasts beyond 2021 have not been finalized and are subject to a variety of factors and as a result forecast results for 2022 and 2023 may change materially. Where a range is not provided, guidance and forecast values represent the mid-point estimate. 2021 production guidance incorporates currently known midstream outages.

(2) Price assumptions: 2021+ = US$55 WTI; $2.50 AECO; $0.785 CAD, unless noted otherwise.

(3) See “non-GAAP Measures” section of this MD&A for description. Net debt excludes convertible preferred shares as there is no cash settled liability and includes adjusted working capital deficit.

(4) Capex includes all anticipated DCE&T, infrastructure, and other capital expenditures, but excludes capitalized G&A.

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The Company’s current in-field gathering system build out was completed in 2019 and is capable of handling approximately 40,000 boe/d of sales production, inclusive of de-bottlenecking modifications being implemented during 2021. As such, the Company anticipates that capital investment in infrastructure over the next three years will be minimal.

During the first quarter of 2021 West Texas Intermediate (“WTI”) oil prices have continued to improve and stabilize. Edmonton Condensate differentials have traded at a modest premium to WTI due to domestic supply and demand dynamics as many Canadian condensate focused producers have scaled back their capital programs limiting production levels. AECO 5A natural gas pricing has remained stable in the first quarter of 2021 due to an overall reduction in North American natural gas supply and increased TCPL storage capability domestically.

Operations Update

In January 2021 the Company completed the 3 wells located at its 8-15 pad for an average cost of $3.2 million per well, utilizing 2.5 tonnes per metre proppant intensity. These wells were brought on-stream in late February 2021.

During January and February 2021, the Company drilled 3 wells at its 6-13 pad-site. These wells were drilled for an average cost of $2.0 million per well with an average lateral length of 2,633 metres. These wells were completed during March and early April 2021 for an average cost of $3.3 million, utilizing 3.5 tonnes per metre proppant intensity, and are planned to be brought on-stream early in the second quarter of 2021. The 6-13 pad is a new pacesetter for Pipestone Energy at a completion cost of $358 per tonne of proppant placed.

In late February 2021, the Company moved its drilling rig from the 6-13 pad to the 15-25 pad and contracted a second drilling rig to accelerate the drilling of 6 wells at this location. At March 31, 2021, the Company had drilled and rig released 4 wells from the 15-25 pad with the remaining 2 wells rig released subsequently in the first half of April 2021. The 6 wells were drilled for an average cost of $2.1 million per well with an average lateral length of 2,914 metres. The 15-25 pad wells were drilled for an average cost of $752 per lateral metre in-line with pad average pacesetter drilling performance for the Company. The 15-25 pad also marked a milestone for Pipestone Energy with its longest lateral drilled since inception measuring 3,772 metres at a cost of $2.3 million or $617 per lateral metre.

The drilling and completion results achieved at the 15-25 and 6-13 pads, respectively, continue to demonstrate the Company’s enhancement of value through strong execution at the well level.

In April 2021 the Company began the second phase of drilling operations at its existing 6-24 pad returning to a single rig execution strategy, where 6 additional wells will be drilled in total during the second quarter of 2021. In addition, the Company completed the 6 wells at the 15-25 pad in late April and early May.

In the first quarter of 2021 the Company also finalized construction of its 3-12 pad-site flow splitter, water handling and disposal facility. The facility was successfully commissioned and is currently handling the Company’s liquids and natural gas production and produced water which is anticipated to improve operational efficiencies and costs going forward.

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First Quarter 2021 Corporate Highlights

• Pipestone Energy achieved record corporate production in the first quarter of 2021. Production volumes averaged 21,595 boe/d (comprised of 32% condensate and 46% total liquids) for the three months ended March 31, 2021. Production has remained steady post the quarter with April 2021 averaging approximately 22,850 boe/d (comprised of 31% condensate and 44% total liquids);

• As a result of increased production and much stronger commodity pricing realized in the first quarter of 2021 compared to 2020, the Company generated record revenue and adjusted funds flow from operations of $71.5 million and $28.2 million ($0.15 per share basic and $0.10 per share fully diluted), respectively, during the three months ended March 31, 2021;

• In the first quarter of 2021 the Company settled its contingent business interruption insurance claim filed in relation to the unplanned and extended outage that occurred at the Keyera Wapiti Plant, which spanned 38 days, during the second half of 2020. Pipestone Energy recovered $1.9 million in total proceeds for its lost net profits during the insured period of eight days and has recognized this amount as a reduction to operating expenses in the interim financial statements for the three months ended March 31, 2021. No amounts were previously accrued for by the Company in 2020 as this insurance claim represented a contingent asset under IFRS and could not be recognized at that time;

• The Company commenced its 2021 capital program with 7 wells drilled and rig-released and 6 wells completed during the first quarter of 2021. Total capital expenditures, including capitalized G&A, were $46.3 million during the three months ended March 31, 2021. Pipestone Energy continued to gain drilling and completion cost efficiencies as described above in the operations update; and

• Subsequent to March 31, 2021, Pipestone Energy successfully redetermined its reserve-based loan (“RBL”) and maintained its borrowing capacity at $225.0 million. With the redetermination, the RBL became fully conforming as the Company’s previous $70.0 million Additional Facility, established in 2020, was converted back into capacity available under the Senior Facility. This reduces Pipestone Energy’s annual borrowing cost by 2.0 percent on any amounts drawn under this $70.0 million of capacity as the Company’s pricing structure under the Senior Facility is lower than the Additional Facility’s previous rates by this amount. In addition, the Senior Facility and Operating Line pricing was reduced by 0.25 percent with the redetermination which will further reduce the Company’s borrowing cost on all amounts drawn. The revolving period of the RBL was extended to May 30, 2022 with an additional one-year term out period thereafter and the next redetermination is now scheduled for November 30, 2021. The renewal of the RBL marks a critical step in Pipestone Energy’s growth path forward as it enables the Company to execute on its three-year development plan within the $225.0 million of borrowing capacity available.

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Capital Expenditures

	Three months ended
March 31,
($ thousands)	2021 2020
$ $ Drilling 16,664 11,814 Completions 21,067 7,317 Production equipment and facilities 4,114 8,332 Land and other 3,659 843 Capitalized G&A 785 848
Capital expenditures 46,289 29,154 Propertyacquisitions 125 -
Total capital expenditures and acquisitions 46,414 29,154

During the three months ended March 31, 2021, Pipestone Energy’s total capital expenditures, including capitalized G&A, were $46.3 million which was an increase of $17.1 million from the $29.2 million invested in the comparative period for 2020. The increase was primarily due to increased spending on drilling (7 wells in 2021 vs 6 wells in 2020) and completions (6 wells in 2021 vs no wells in 2020) during the current quarter. This was partially offset by reduced production equipment and facilities costs as the Company incurred fewer pad-site facility, well tie-in and pipeline expenditures in the current quarter. The majority of the Company’s capital expenditures will continue to be deployed on drilling and completion activity in the remainder of this year as the Company has the majority of the required in-field infrastructure in place to support current development plans.

For the three-month period ended March 31, 2021, Pipestone Energy commenced its 2021 development program as follows:

• Total drilling spend was $16.7 million in the quarter. The Company drilled and rig-released 3 wells at the 6-13 pad and 4 wells at the 15-25 pad, with 2 additional wells that were in progress and rigreleased just subsequent to the quarter end for 6 total wells at the 15-25 pad-site;

• Total completion costs were $21.1 million in the quarter. The Company completed the 3 wells located at the 8-15 pad and 3 wells at the 6-13 pad;

• Invested $4.1 million in production equipment and facilities which included $1.5 million on the 3- 12 pad-site flow splitter, water handling and disposal facility, which became operational during the quarter, $1.9 million on pad facilities and tie-ins and $0.7 million on pipelining and other projects; and

• Incurred $3.7 million on land and other which included various workovers and minor recompletion activity.

	Three months ended
March 31,
Montneywell activity (1)	2021 2020
Gross & Net Wells drilled (rig-released) 7.0 6.0 Wells completed 6.0 -

(1) Well counts include all horizontal Montney wells and exclude surface holes, water injection wells, and wells that were re-drilled or abandoned. Drilling counts are based on rig release date.

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Financial and Operating Results

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Production

	Three months ended
March 31,
	2021 2020
Daily average volume (1) Condensate_(bbls/d) 7,004 3,955 Other NGLs(bbls/d)_ 2,745 1,265
Total NGLs_(bbls/d) 9,749 5,220 Crude oil(bbls/d) 91 88 Naturalgas(Mcf/d)_ 70,527 52,546
Total sales_(boe/d)_ 21,595 14,066
Production weighting (1) Condensate 32% 28% Other NGLs 13% 9%
Total NGLs 45% 37% Crude oil 1% 1% Naturalgas 54% 62%
Total sales 100% 100%
(1) 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”.

The Company achieved record production for the three months ended March 31, 2021 of 21,595 boe/d (comprised of 32% condensate and 46% total liquids) compared to 14,066 boe/d for the same period in 2020. Pipestone Energy grew its sales production by 7,529 boe/d or 54% quarter over quarter.

The increase in 2021 from the comparative period was mainly a result of the Company having additional production volumes from approximately 18 wells that have since been tied-in at the 8-15, 3-12, 6-30 and 9-14 pad-sites located north of the Wapiti River and corresponding increases to available midstream and

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takeaway capacity in the current quarter. Production levels in Q1 2021 were also augmented by improved third-party facility run-times versus Q1 2020.

Sales

	Three months ended
March 31,
($ thousands, exceptper unit amounts)	2021 2020
$ $ Condensate 40,986 19,033 Other NGLs 6,619 2,068
Total NGLs 47,605 21,101 Crude oil 486 325 Naturalgas 23,394 10,591
Total 71,485 32,017
Average realized prices before hedging and transportation Condensate_($/bbl) 65.03 52.89 Other NGLs($/bbl) 26.79 17.97 Total NGLs($/bbl) 54.26 44.43 Crude oil($/bbl) 59.52 40.99 Naturalgas($/Mcf) 3.69 2.21 Combined average($/boe)_ 36.78 25.01

Sales for the three months ended March 31, 2021 were $71.5 million compared to $32.0 million for the three months ended March 31, 2020. The significant increase in 2021 sales from the comparative period was a result of the Company bringing on new production from wells drilled, completed and tied-in from pads north of the Wapiti River combined with higher average realized sales prices for its liquids and natural gas. Natural gas prices spiked across North America in February 2021 as a result of extreme cold temperatures experienced which benefited the Company’s realized gas pricing during the quarter, particularly on volumes exposed to Chicago City Gate pricing. These trends are very encouraging as returns on the Company’s high-quality asset base will benefit from any go-forward commodity prices that are above the assumptions applied in the current three-year guidance and forecasts.

Benchmark Pricing

	Three months ended
March 31,
	2021 2020
Average condensate prices $ $ Edmonton Condensate_(C$/bbl) 74.59 60.12 Average crude oil prices WTI crude oil(US$/bbl)(1) 57.8445.97 WTI crude oil(C$/bbl) 73.2461.34 Average natural gas prices AECO natural gas(C$/GJ)(2) 3.071.92 Chicago City Gate natural gas(C$/GJ)(3) 8.532.22 Average foreign exchange rate Exchange rate(US$/C$)_ 0.790.74

(1) WTI refers to the West Texas Intermediate crude oil price.

(2) AECO refers to the Alberta Energy Company natural gas price. 5A is a simple average of the daily spot prices.

(3) Chicago City Gate refers to the Chicago Index Futures natural gas price.

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Pipestone Energy’s condensate production is delivered and sold in Edmonton, Alberta, through the Pembina pipeline system. The price of WTI for crude oil sales at Cushing, Oklahoma is the primary benchmark for crude oil pricing in North America. The price that Alberta condensate producers receive for their condensate production has historically been highly correlated to the price of WTI, adjusted for Edmonton differentials, external supply and demand, changes in Canada-U.S. exchange rates, transportation costs and quality.

During the first quarter of 2021 WTI oil prices have continued to improve and stabilize from the fourth quarter of 2020. In 2020 crude oil suffered significant declines and volatility as a result of the COVID-19 virus’ unprecedented negative impact on global demand combined with the failure of OPEC and Russia to reach an agreement on meaningful production cuts at the time. Edmonton Condensate differentials have traded at a modest premium to WTI so far in 2021 due to domestic supply and demand dynamics as many Canadian condensate focused producers have scaled back their capital programs limiting production levels.

The AECO 5A price is the primary benchmark for the Company’s current natural gas sales. The AECO 5A differentials to other North American benchmarks can fluctuate significantly, primarily due to limited economic transportation and options out of western Canada, domestic production levels and limited access to local storage facilities. Pipestone Energy also utilizes its firm service contract on the Alliance Pipeline system to deliver approximately 5.0 MMcf per day of natural gas to Chicago, making City Gate pricing a secondary benchmark.

AECO 5A pricing has remained stable in the first quarter of 2021 due to an overall reduction in North American natural gas supply and increased TCPL storage capability domestically. Natural gas prices spiked across North America in February 2021 as a result of extreme cold temperatures experienced which benefited the Company’s realized pricing during the quarter, particularly on volumes exposed to Chicago City Gate pricing.

The Company has hedged certain expected future liquids volumes to WTI directly in C$ through swaps and the Company has also hedged a subset of volumes to the differential between WTI and Edmonton Condensate (“EdCon”) denominated in US$. EdCon refers to the Enbridge condensate pool price for liquids sales at Edmonton, Alberta which is the primary reference price for condensate in western Canada. The Company has hedged a portion of its forecasted natural gas production for 2021 and 2022 utilizing AECO swaps as well. See the “Commodity Price Risk Management” section below for more details.

Royalties

	Three months ended
March 31,
	2021 2020
$ $ Gross royalties_($ thousands) 3,659 1,547 Gas cost allowance(“GCA”) ($ thousands)_ (440) (79)
Net royalties_($ thousands)_ 3,219 1,468
Gross royalties Per boe_($)_ 1.88 1.21 Percentage of sales 5.1% 4.8%
Net royalties Per boe_($)_ 1.66 1.14 Percentage of sales 4.5% 4.6%

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Pipestone Energy’s royalty burden is predominately paid to the province of Alberta, with minimal gross over-riding royalties applicable on a small sub-set of the Company’s sales. The 2021 and 2020 royalty rates are indicative of royalty rates on new production in Alberta under the Modernized Royalty Framework. The Company also makes applicable GCA claims which reduce its net royalties paid.

Net royalties paid for the three months ended March 31, 2021 were $3.2 million compared to $1.5 million for the three months ended March 31, 2020. The increase in royalties paid during the first quarter of 2021 was a result of the significant production volume growth from the Company’s development activity and higher commodity pricing period over period.

Operating Expense

	Three months ended
March 31,
	2021 2020
$ $ Operating expense_($ thousands) 20,678 14,620 Per boe($)_ 10.64 11.42

The majority of Pipestone Energy’s operating costs are comprised of third-party gathering and processing fees with field site operation and supervision activities, chemicals, maintenance, fuel, equipment rentals, insurance and property taxes making up the balance.

Operating expenses for the three months ended March 31, 2021 were $20.7 million compared to $14.6 million for the three months ended March 31, 2020. The increase in operating expenses in 2021 was a result of the Company having additional production flowing from new pads north of the Wapiti River. The Company’s third-party gathering and processing commitments scaled up concurrently to accommodate the production growth. This increase was partially offset by $1.9 million ($0.98 per boe) of insurance proceeds received in the first quarter of 2021 which has been recognized as a recovery netted against operating expense. In the second half of 2020 Pipestone Energy initiated a contingent business interruption claim with its insurers in relation to an unplanned and extended outage that the Company experienced at one of its third-party processing facilities. As the insurance claim represented a contingent asset at that time, the Company did not recognize any financial impact during 2020. In the first quarter of 2021 the Company settled this insurance claim.

The operating expense per boe, excluding the insurance recovery realized during the three months ended March 31, 2021, remained relatively consistent in 2021 compared to the same quarter in 2020 due to similar cost structures in place. With Pipestone Energy’s 3-12 pad-site water handling and disposal facility now commissioned the Company expects to reduce its future water disposal costs.

Transportation Expense

	Three months ended
March 31,
	2021 2020
$ $ Transportation expense_($ thousands) 5,090 4,684 Per boe($)_ 2.62 3.66

Pipestone Energy has entered into various firm service contracts to transport its current and future expected production volumes. Transportation expense primarily consists of tolls on the Pembina Peace, NGTL and Alliance pipeline systems. Pipestone Energy incurs transportation charges on the sales volumes that it delivers to specified sales hubs that are beyond its third-party processing facilities under committed agreements.

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Transportation expenses for the three months ended March 31, 2021 were $5.1 million compared to $4.7 million for the three months ended March 31, 2020. The increase to transportation expense was a result of the Company transporting greater sales volumes produced during Q1 2021 compared to Q1 2020.

The transportation expense per boe decreased considerably in 2021 due to greater utilization of commitments and minor recovery of take-or-pay fees on previously unfilled capacity received in the quarter.

Risk Management

Pipestone Energy’s commodity price risk management program is designed to reduce cash flow volatility, enhance certainty on funding available for the Company’s capital expenditure program and service debt.

Mitigation of cash flow volatility is an integral component of the Company’s business strategy. Business conditions are monitored regularly and reviewed with the Board of Directors to establish risk management guidelines used by management in carrying out the Company’s strategic risk management program.

Pipestone Energy continues to implement an ongoing hedge program, focused on its forecast liquids and natural gas production. Pipestone Energy currently utilizes fixed price swaps and product differential hedging structures. To date, Pipestone Energy has entered hedges with respect to benchmark WTI, AECO and EdCon (Edmonton condensate). Price and volume targets for the Company’s hedge portfolio are established based on macro supply and demand fundamental analysis, Pipestone Energy’s future production expectations and target development rates.

The Company has elected not to use hedge accounting and, accordingly, the fair value of the commodity risk management contracts is recorded at each period-end. The fair value may change substantially from period to period depending on commodity forward strip prices for the contracts outstanding at the date of the statement of financial position. The change in fair value from period-end to period-end is reflected in profit or loss for that period. As such, if benchmark prices rise during the period, the Company records a loss based on the change in price multiplied by the volume hedged. If benchmark prices fall during the period, the Company records a gain. The prices used to record the actual gain or loss are subject to an adjustment for volatility. Pipestone Energy’s financial results should be viewed with the understanding that the estimated future gain or loss on risk management contracts is recorded in the current period’s profit or loss, while the estimated future value of the underlying physical sales is not.

Commodity risk management contracts

	Three months ended	Three months ended
		March 31,
	2021	2020
	$	$
Realized (loss) gain on commodity risk management contracts_($ thousands)_
Crude oil	(6,089)	7,876
Condensate	(201)	(1,733)
Naturalgas	(2,101)	22
Total	(8,391)	6,165
Per boe_($)_	(4.32)	4.82
Unrealized (loss) gain on commodity risk management contracts_($ thousands)_
Crude oil	(10,139)	18,172
Condensate	(129)	4,150
Naturalgas	(2,466)	57
Total	(12,734)	22,379
Per boe_($)_	(6.55)	17.48

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During the three months ended March 31, 2021, the Company incurred a realized loss on commodity risk management contracts of $8.4 million compared to a realized gain of $6.2 million during the three months ended March 31, 2020. The realized loss on commodity risk management contracts in the current quarter was a result of settling WTI and AECO 5A fixed price swaps and Edmonton Condensate differential hedges that were out-of-the-money due to the general strengthening of benchmark prices. In the 2020 comparative period the realized gain was primarily a result of settled WTI fixed price swaps that were inthe-money due to the steep declines in global oil prices experienced partially offset by losses on condensate differential hedges

During the three months ended March 31, 2021, the Company incurred an unrealized loss on commodity risk management contracts of $12.7 million compared to an unrealized gain of $22.4 million during the three months ended March 31, 2020. The unrealized loss on commodity risk management contracts in the current quarter was due to the general strengthening of benchmark prices. In the 2020 comparative period the Company recognized unrealized gains on the mark-to-market value of its liquids positions due to the deterioration of WTI and Edmonton Condensate prices as caused by the COVID-19 pandemic’s demand destruction and the global oversupply of oil.

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The Company had the following commodity risk management contracts at March 31, 2021:

	**C$ WTI swaps **	**C$ WTI swaps **	**EdCon basis swaps **	**EdCon basis swaps **	AECO	**5A swaps **
Term	bbls/d	C$/bbl	bbls/d	US$/bbl	GJ/d	C$/GJ
Apr. – Jun. ‘21	4,000	57.51	3,000	0.45	42,870	2.34
Jul. – Sept. ‘21	4,000	58.05	-	-	45,375	2.35
Oct. – Dec. ‘21	4,000	58.05	-	-	41,210	2.32
Jan. – Dec. ‘22	62	74.50	-	-	12,530	2.27

(1) Weighted-average volumes and prices are presented.

(2) EdCon refers to Edmonton Condensate.

Interest rate risk management contracts

	Three months ended	Three months ended
		March 31,
	2021	2020
	$	$
Realized loss on interest rate risk management contracts_($ thousands)_	(244)	(668)
Per boe_($)_	(0.13)	(0.52)
Unrealized gain (loss) on interest rate risk management contracts_($ thousands)_	345	(734)
Per boe_($)_	0.18	(0.57)

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The Company has a floating-to-fixed interest rate swap in place with one of its lenders at March 31, 2021. During the first quarter of 2020 the Company blended the interest rate and extended out the term of this swap contract until March 31, 2023 in order to defer part of the current liability and associated cash outflows beyond 2021. Due to bank debt and the swap being held with the same lending institution, the realized portion of the interest rate risk management contract is recorded as financing expense.

During the three months ended March 31, 2021, the Company incurred a realized loss on interest rate risk management contracts of $0.2 million compared to $0.7 million during the three months ended March 31, 2020. The realized loss in the current quarter was lower than the comparative period in 2020 primarily due to the extension of the term of this contract and related reduction in settlements.

During the three months ended March 31, 2021, the Company recognized an unrealized gain on interest rate risk management contracts of $0.3 million compared to an unrealized loss of $0.7 million during the three months ended March 31, 2020. The unrealized gain during the three months ended March 31, 2021 was a result of settlements and interest rate curves rising slightly. In the 2020 comparative period the unrealized loss recognized was a result of interest rate curves dropping during the quarter which increased the Company’s interest rate risk management liability position, partially offset by settlements.

General and Administrative (“G&A”) Expense

	Three months ended
	March 31,
($ thousands, exceptper boe amounts)	2021 2020
Gross G&A expense Capitalized G&A Overhead recoveries G&A expense Per boe	$ $ 2,583 2,924 (785) (848) (198) (299)
	1,600 1,777 0.82 1.39

G&A expenses primarily consist of the Company’s overhead costs incurred to support its ongoing operations and planned future operations. Capitalized G&A is directly attributable to the development of the Pipestone assets. Overhead recoveries relate to recovered amounts from partners for operating administration costs as well as capital programs. Capitalized G&A and overhead recoveries are consistent with industry practice. In the current quarter Pipestone Energy capitalized 30% of gross G&A expenses compared to 29% in the 2020 comparative period.

During the three months ended March 31, 2021, the Company’s gross G&A expenses were $2.6 million compared to $2.9 million for the three months ended March 31, 2020. Gross G&A expenses in the current quarter decreased from the 2020 comparative period. While the current conditions and outlook for the Canadian energy industry have improved considerably from a challenging year in 2020, Pipestone Energy has continued to maintain many of its previously implemented G&A cost saving efforts. G&A expense per boe has decreased significantly in the current quarter due to these cost savings realized combined with expanded production. The Company has positioned itself with its current G&A structure to facilitate its significant growth plans with only minor incremental costs expected in the future.

Pipestone Energy’s 2021 full year gross G&A budget, before capitalization and overhead recoveries, is $12.0 million. Due to increased production and improved commodity prices received, resulting in increased revenues, thus far in 2021 the Company has not qualified for any of the Government of Canada COVID-19 subsidy program benefits that it received throughout 2020 and does not anticipate qualifying for the remainder of 2021. As such, the relief payments that were received and directly netted off gross G&A expense in 2020 will no longer apply in 2021 resulting in higher gross G&A expense by this amount. In 2020 the Company qualified for and received a total of $0.5 million in government subsidies.

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Share-Based Compensation

	Three months ended	Three months ended
		March 31,
	2021	2020
	$	$
Share-based compensation_($ thousands)_	574	453
Per boe_($)_	0.30	0.36

Share-based compensation relates to stock options, performance share units (“PSU”) and restricted share units (“RSU”) granted to employees, officers and directors. Share-based compensation also includes the employer matching portion of contributions made to the employee share purchase plan (“ESPP”) for common shares that are issued out of treasury.

During the three months ended March 31, 2021, the Company incurred share-based compensation of $0.6 million compared to $0.5 million for the comparative period in 2020. The increase in the current quarter from the 2020 comparative period was due to the Company having a greater number of equity awards outstanding and those awards issued having greater fair values to be expensed over their lives due to the appreciation of the Company’s common share price in the first quarter of 2021 and new grants made. This increased share-based compensation expense is expected to continue throughout quarters in 2021.

Depletion and Depreciation (“D&D”) Expense

	Three months ended	Three months ended
		March 31,
	2021	2020
	$	$
Depletion_($ thousands)_	12,958	11,247
Per boe_($)_	6.67	8.79
Depreciation – ROU lease assets_($ thousands)_	1,727	1,516
Per boe_($)_	0.89	1.18
Depreciation – Corporate assets_($ thousands)_	21	22
Per boe_($)_	0.01	0.02
Total D&D expense_($ thousands)_	14,706	12,785
Per boe_($)_	7.57	9.99

D&D expenses primarily consist of depletion of Company liquids and natural gas properties on a unit-ofproduction basis over total proved plus probable reserves before royalties. The unit-of-production rate takes into account expenditures incurred to date, together with estimated future development expenditures required to develop those proved plus probable reserves. This rate, calculated at a component level, is then applied to Pipestone Energy’s production volume to determine D&D in a given period. Management believes that this method of calculating D&D expenses over each boe is equivalent with its proportionate share of the cost of capital invested over the total estimated life of the related asset as represented by proved plus probable reserves.

Future development costs included in the depletion rate calculation at March 31, 2021 were $935.4 million (March 31, 2020 - $1,114.0 million). As a result of the Company’s continued success and efficiency in its development activities, the finding and development costs associated with its proved plus probable reserves have improved significantly from a combination of reduced development costs per well and better recoveries. The depletion rate of $6.67 per boe in the first quarter of 2021 is a reduction of $2.12 per boe or 24% from the depletion rate in the first quarter of 2020 which was $8.79 per boe.

D&D expense also includes depreciation of the Company’s ROU lease assets, on a straight-line basis over the shorter of the estimated useful life or the lease term, and corporate assets.

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During the three months ended March 31, 2021, the Company incurred D&D expenses of $14.7 million compared to $12.8 million for the comparative period in 2020. The increase in D&D expense for the three months ended March 31, 2021 was due to the Company’s production growth over the comparative period in 2020 from its continued Montney asset development partially offset by the lower depletion rate per boe recognized in the current period. The Company’s depreciation on ROU lease assets also increased slightly in 2021 from the comparative period as a result of a ROU lease asset addition which was recognized in late 2020 for the expansion of a compressor lease the Company has with a third-party midstream partner.

Financing Expense

	Three months ended
	March 31,
($ thousands, except per boe amounts)	2021 2020
Lease liabilities interest expense Interest on bank debt Letter of credit fees Bank charges Foreign exchange loss on U.S. denominated debt Realized gain on cross-currency swaps Cash financing expense Preferred share dividends paid in-kind Accretion of preferred share discount Amortization of preferred share issuance costs Amortization of bank debt issuance costs Accretion on decommissioning provisions Non-cash financing expense Total financing expense Cash financing expense, per boe Non-cash financingexpense, per boe	$ $ 1,733 1,609 1,857 1,597 181 110 250 2 - 5,806 - (5,806)
	4,021 3,318
	1,159 - 62 - 42 - 351 - 27 29
	1,641 29
	5,662 3,347 2.07 2.59 0.84 0.02

Interest on bank debt is the amount charged by Pipestone Energy’s lending institutions.

Lease liabilities interest expense pertains to the interest rate implicit in the Company’s leases, or, if that rate cannot be determined, the Company’s incremental borrowing rate. The interest rate applicable to each lease is applied to the lease liability and applied to each lease payment.

Accretion expense is recognized on the Company’s decommissioning provision balance.

Amortization of bank debt issuance costs relates to the fees paid on Pipestone Energy’s bank debt, amendments and renewals.

All other non-cash financing expenses relate to the Company’s convertible preferred share accretion of discount, amortization of issuance costs and dividends that are paid in-kind.

During the three months ended March 31, 2021, the Company incurred total financing expenses of $5.7 million compared to $3.3 million for the comparative period in 2020. The increase to financing expense in 2021 was primarily due to higher borrowing rates on bank debt, the balance of bank debt drawn was relatively consistent quarter over quarter, greater amortization of bank debt issuance costs, extra lease

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liability interest expense under IFRS 16 due to an ROU lease asset addition that took place in late 2020 and non-cash financing expenses related to the Company’s convertible preferred shares, that were issued in September 2020, recorded in the current period.

Financing Income

Three months ended March 31,	Three months ended
	2021 2020
$ $ Financing income_($ thousands) - 173 Per boe($)_ - 0.13

Financing income relates to the interest earned on cash held in the Company’s bank accounts.

During the three months ended March 31, 2021, the Company earned no financing income compared to $0.2 million for the comparative period in 2020. Financing income was lower in 2021 than in 2020 due to no bank balances being maintained throughout the current period. In 2021 the Company swept its available cash balances against the outstanding amounts drawn under its bank debt operating facility to reduce interest expense incurred.

Income Tax

The deferred income tax recovery was $0.1 million in the three months ended March 31, 2021 compared to a deferred income tax expense of $4.7 million for the comparative period in 2020. The recovery in the current quarter is a result of the Company’s net loss for the period.

Liability Management Rating (“LMR”) and Decommissioning Provisions

At March 31, 2021, Pipestone Energy’s Alberta LMR rating was positive 35.7. This LMR ranks Pipestone Energy as an industry leader and continues to demonstrate the Company’s commitment to responsible development of its asset and the surrounding environment. The Government of Alberta is in the process of replacing its existing LMR with a new Liability Management Framework (“LMF”) to address certain shortcomings identified in the current system and further improve the province’s reclamation efforts to become more proactive and wholistic. The LMF is expected to be implemented in mid-2021.

At March 31, 2021, the Company’s total decommissioning provision was $9.1 million or 1.5% of its total property and equipment balance. Pipestone Energy believes it is well positioned with respect to funding its long-term abandonment and reclamation obligations, the majority of which are expected to be incurred between the years 2045 and 2055. The Company has applied for the government programs currently being offered to assist oil and gas operators with the costs of abandoning and reclaiming wells. Pipestone Energy only has minor decommissioning provisions that are eligible for these programs. At March 31, 2021, no relief has been received to date.

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Supplemental Information

The following table and charts summarize key financial and operating information for the periods indicated.

Netback Analysis

Three months ended March 31,	Three months ended
	2021 2020
$ $ Average sales price of liquids and natural gas 36.78 25.01 Realized (loss) gain on commodity risk management contracts(2) (4.32) 4.82 Royalties (1.66) (1.14) Operating expense (10.64) (11.42) Transportation expense (2.62) (3.66)
Operating netback per boe(1) (2) 17.54 13.61 G&A expense (0.82) (1.39) Realized loss on interest rate risk management contracts (0.13) (0.52) Financing income - 0.13 Financing expense – cash (2.07) (2.59)
Adjusted funds flow netback per boe(1) 14.52 9.24 Financing expense – non-cash (0.84) (0.02) D&D expense (7.57) (9.99) Share-based compensation (0.30) (0.36) Unrealized (loss) gain on commodity risk management contracts (6.55) 17.48 Unrealized gain (loss) on interest rate risk management contracts 0.18 (0.57) Deferred income tax recovery (expense) 0.07 (3.64)
Income (loss) per boe (0.49) 12.14

(1) See “Non-GAAP measures”.

(2) Realized gain (loss) on commodity risk management contracts reclassified to be included under operating netback for 2021, prior period figures have been adjusted to confirm with current presentation.

==> picture [468 x 153] intentionally omitted <==

• See “Non-GAAP measures” section of this MD&A for description of “operating netback”.

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==> picture [468 x 173] intentionally omitted <==

• See “Non-GAAP measures” section of this MD&A for description of “adjusted funds flow netback”.

The operating netback per boe increased in the current quarter due to stronger commodity pricing realized across all product types partially offset by realized commodity hedging losses. The change in operating netback per boe was also positively impacted by decreased operating and transportation expense per boe incurred in 2021 while royalties per boe paid increased compared to 2020 due to the recovery in commodity pricing.

The adjusted funds flow netback per boe increased in the current quarter as a result of reduced G&A and cash financing expense on a per boe basis due to the increased production base in 2021 as well as lower realized interest rate hedging losses incurred on both an absolute dollar and per boe basis. The improvement in adjusted funds flow netback per boe in 2021 was partially offset by no financing income earned in the current quarter.

The loss per boe in 2021 was mainly due to the unrealized loss on commodity risk management contracts and increase to non-cash financing expenses partially offset by lower D&D expense on a per boe basis and the income tax recovery.

Please refer to the “Financial and Operating Results” section above for more detailed explanations of these variances.

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Selected Quarterly Information

Three months ended	March 31,	Dec. 31,	Sept. 30,	June 30,	March 31,	Dec. 31,	Sept. 30,	June 30,
	2021	2020	2020	2020	2020	2019	2019	2019
Financial
($ thousands, except per share amounts
and share numbers)
Sales of liquids and natural gas	71,485	45,853	31,700	26,380	32,017	48,796	7,808	5,917
Cash from (used in) operating
activities	18,097	10,086	660	(175)	31,067	30,750	(6,626)	(777)
Adjusted funds flow from (used
in) operations(1)	28,242	11,088	6,359	11,231	11,820	16,608	(2,734)	(2,423)
Per share,
basic_($)_	0.15	0.06	0.03	0.06	0.06	0.09	(0.01)	(0.01)
diluted_($)_(2)	0.10	0.04	0.02	0.06	0.06	0.09	(0.01)	(0.01)
Income (loss)	(954)	(1,846)	(11,486)	(19,486)	15,541	(13,143)	(1,409)	4,869
Per share,
basic and diluted_($)_	(0.00)	(0.01)	(0.06)	(0.10)	0.08	(0.07)	(0.01)	0.03
Capital expenditures	46,289	43,742	11,806	19,893	29,154	36,457	29,434	46,835
Total assets_(end of quarter)_	742,147	694,471	645,020	652,798	663,140	663,816	607,287	579,297
Working capital (deficit)(end of
quarter)	(47,209)	(48,603)	(25,478)	(16,781)	(7,103)	(12,015)	20,893	(8,026)
Bank debt_(end of quarter)_	166,659	133,466	120,477	183,248	163,000	163,048	156,983	115,754
Shareholders’ equity_(end of_
quarter)	354,747	355,058	356,355	367,298	386,147	370,075	382,867	383,843
Weighted-average basic shares
outstanding_(000s)_	190,891	190,698	190,468	190,136	189,820	189,743	189,627	187,096
Weighted-average diluted shares
outstanding_(000s)_(2)	276,524	274,758	273,172	190,253	189,942	189,777	189,627	187,116
Operations
Total production_(boe/d)_	21,595	17,734	13,701	16,772	14,066	14,885	2,467	1,407
Condensate and crude oil_(% of_
total production)	33	31	32	29	29	36	45	42
Total liquids_(% of total production)_	46	44	48	43	38	43	51	49
Average realized price_(per boe)_	36.78	28.10	25.15	17.28	25.01	35.63	34.40	42.62
Operating netback_(per boe)_(1)(3)	17.54	10.12	9.91	10.45	13.61	16.75	11.61	19.96
Adjusted funds flow netback_(per_
boe) (1)	14.52	6.80	5.05	7.37	9.24	12.13	(12.04)	(18.93)

(1) See “Non-GAAP measures”.

(2) Weighted-average diluted shares outstanding for the purposes of calculating diluted per share amounts incorporates the common shares that are issuable at the discretion of convertible preferred shareholders in each respective period presented.

(3) Realized gain (loss) on commodity risk management contracts reclassified to be included under operating netback for 2021, prior period figures have been adjusted to conform with current presentation.

Inherent to the nature of the oil and gas industry, fluctuations in Pipestone Energy’s quarterly sales of liquids and natural gas, adjusted funds flow from or used in operations, and income or loss are primarily caused by variations in production volumes, realized commodity prices and the related impact on royalties, realized and unrealized gains or losses on risk management contracts, changes in expenses, and deferred income taxes. Please refer to “Financial and Operating Results” above for more information.

Share Capital

As at the date of this MD&A, the Company had 191.5 million common shares, 17.5 million warrants, 2.3 million stock options, 2.9 million PSUs and 2.8 million RSUs outstanding. The quantities and exercise prices of warrants and any stock options that were continued as part of a historical corporate acquisition are shown post conversion on a 10:1 basis to reflect the share consolidation that took place on January 4, 2019. The Company also has 70.0 thousand convertible preferred shares outstanding which were convertible into 85,281,505 common shares at a price of $0.85 per share as of March 31, 2021. At March 31, 2021, Pipestone Energy’s common shares were trading at a price in excess of $0.85 per share.

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Liquidity and Capital Resources

At March 31, 2021, the Company had an adjusted working capital deficit of $23.6 million (March 31, 2020 – adjusted working capital deficit of $24.1 million), excluding risk management contract assets and liabilities, as well as lease liabilities. Adjusted funds flow from operations for the three months ended March 31, 2021 was $28.2 million (three months ended March 31, 2020 - $11.8 million).

Adjusted Working Capital and Available Funding

	As at March 31,
($ thousands)	2021 2020
Current assets Current liabilities Working capital deficit Less: current asset risk management contracts Plus: current liability risk management contracts Plus: current lease liabilities Adjusted working capital deficit_(1) Plus: credit facility capacity(2)_	$ $ 38,687 36,550 (85,896) (43,653)
	(47,209) (7,103)
	- (21,849) 18,903 1,030 4,752 3,782
	(23,554) (24,140) 58,106 47,748
Available funding_(1)_	34,552 23,608

(1) See “Non-GAAP measures”.

(2) As at March 31, 2021, Pipestone Energy has a $125.0 million Senior Facility, which is fully drawn, and a $70.0 million Additional Facility, with $13.0 million drawn against it. At March 31, 2021, the Company also has a $30.0 million Operating Line, which is reduced by $28.9 million of principal drawn.

==> picture [468 x 148] intentionally omitted <==

• See “Non-GAAP measures” section of this MD&A for description of “adjusted funds flow from operations”. Changes in other categories includes the movements in realized loss on interest rate risk management contracts and financing income.

Net Debt

	As at March 31,
($ thousands)	2021 2020
$ $ Adjusted working capital deficit 23,554 24,140 Bank debt 166,659 163,000
Net debt 190,213 187,140

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At March 31, 2021, Pipestone Energy’s aggregate draw on its $225.0 million RBL was $166.9 million and its available funding including the adjusted working capital deficit was $34.6 million, accordingly, the Company has sufficient sources of liquidity to supplement the net working capital deficiency as at March 31, 2021.

==> picture [468 x 164] intentionally omitted <==

• See “Non-GAAP measures” section of this MD&A for description of “net debt”. Changes in other categories includes the principal portion of lease payments, proceeds from the issuance of common shares, proceeds from the exercise of stock options and amortization of bank debt issuance costs.

Bank Debt

Reserve-based loan

On July 20, 2020, Pipestone Energy reconfirmed and executed an amendment to its $225.0 million reserve-based loan (the “RBL”) comprised of a $125.0 million senior facility (the “Senior Facility”), a $70.0 million additional facility (the “Additional Facility”) and a $30.0 million operating facility (the “Operating Line”). As part of the amendment to the RBL, the Company’s banking syndicate did not undertake a fall 2020 borrowing base review, and the next redetermination was scheduled for May 2021. See below for an update on the RBL redetermination that was completed subsequent to the quarter. In addition, previously imposed capital spending restrictions from the June 2020 re-determination were removed, and the Company agreed to implement a hedging program with respect to expected condensate volumes through calendar 2021.

At March 31, 2021, the Company had $125.0 million drawn against the Senior Facility (December 31, 2020 - $125.0 million), $13.0 million drawn against the Additional Facility (December 31, 2020 – $Nil) and $28.9 million drawn on the Operating Line (December 31, 2020 - $9.1 million), for an aggregate draw on the RBL of $166.9 million (December 31, 2020 - $134.1 million). At March 31, 2021, the Company had no letters of credit issued against its Operating Line (December 31, 2020 – no letters of credit issued on Operating Line).

As at March 31, RBL – portion drawn Unamortized debt issuance costs Balance, end of period	2021
	$ 166,894 (235)
	166,659

The indebtedness under the credit agreement is secured by floating charges and a security interest against all of the Company’s current and future real and personal property.

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The revolving period of the RBL previously ended on May 31, 2021 with an additional one-year term out period thereafter for any amounts owing under the RBL to be repaid if the revolving period was not extended. An extension of the revolving period is subject to majority lender consent. In the event the borrowing base is reduced below amounts outstanding, any excess will become due and payable 60 days subsequently.

Subsequent to March 31, 2021, the Company successfully redetermined its RBL and maintained its borrowing capacity at $225.0 million. With the redetermination, the RBL became fully conforming as the Company’s previous $70.0 million Additional Facility, established in 2020, was converted back into capacity available under the Senior Facility. This reduces Pipestone Energy’s annual borrowing cost by 2.0% on any amounts drawn under this $70.0 million of capacity as the Company’s pricing structure under the Senior Facility is lower than the Additional Facility’s previous rates by this amount. In addition, the Senior Facility and Operating Line pricing was reduced by 0.25% with the redetermination which will further reduce the Company’s borrowing cost on all amounts drawn. The revolving period of the RBL was extended to May 30, 2022 with an additional one-year term out period thereafter and the next redetermination is now scheduled for November 30, 2021.

Letter of credit facility

Pipestone Energy has a $15.0 million unsecured letter of credit facility (the “EDC Letter of Credit Facility”) under Export Development Canada’s performance security guarantee program. At March 31, 2021, the Company has $15.0 million of letters of credit issued and outstanding against the EDC Letter of Credit Facility (December 31, 2020 - $14.3 million). Letters of credit issued under the EDC Letter of Credit Facility do not impact Pipestone Energy’s borrowing capacity under the RBL, and as such provides the Company with additional liquidity. Subsequent to March 31, 2021, the capacity of the EDC Letter of Credit Facility was increased from $15.0 million to $22.5 million.

Capital Management

The Company’s objective for managing capital is to maintain a strong balance sheet and available funding while providing financial flexibility to fund sustaining capital and to fund high-return development growth. Future expenditures are anticipated to be funded by the Company's adjusted funds flow from operations and draws under the credit facility.

Pipestone Energy manages its liquidity risk through its capital structure, cash flow forecasting and available credit. The Company believes that it has sufficient available funding and will generate enough future cash flow to meet its foreseeable liquidity requirements.

While the Company believes it will be successful in meeting its liquidity requirements, significant uncertainty exists due to the continued adverse impacts that the COVID-19 pandemic has had on the state of the global economy and commodity prices; future reserve and production risks; and the ability of the Company, if required, to raise additional debt or equity financing.

The Company strives for a proportion of debt to future cashflow which appropriately balances the level of risk being incurred by its capital investments.

Commitments and Contingencies

In addition to those recorded on the Company’s statement of financial position, the following is a summary of Pipestone Energy’s contractual obligations and commitments that it has entered as part of its normal operations at March 31, 2021:

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($Thousands)	2021 2022 2023 2024 2025 Thereafter
Gathering commitments Processing commitments Transportation commitments Total payments	$ $ $ $ $ $ 10,899 18,150 18,245 18,348 18,442 90,400 20,502 33,512 39,381 39,629 39,669 181,354 14,280 20,167 18,363 18,425 18,386 100,904
	45,681 71,829 75,989 76,402 76,497 372,658

Lease liabilities are recognized on the Company’s consolidated statement of financial position at their net present value. The gathering commitments, processing commitments, transportation commitments and interest on the lease liabilities are off-balance sheet arrangements in accordance with IAS 1, Presentation of Financial Statements .

The following table details the undiscounted cash flows and contractual maturities of Pipestone Energy’s lease liabilities, as at March 31, 2021:

Within 1 year Year 2 Year 3 Year 4 Year 5 Thereafter Total undiscounted future lease payments Amounts representing lease interest expense over the term of the lease Present value of net lease payments	$ 11,317 10,752 10,752 10,683 10,342 37,059
	90,905 (33,810)
	57,095

The Company is involved in legal claims arising in the normal course of business. The outcome of such claims cannot be predicted with certainty and management believes that it has appropriately assessed any impact to the financial statements.

Critical Accounting Judgments, Estimates and Policies

The Company’s critical accounting judgements, estimates and policies are described in notes 2 and 3 to the December 31, 2020 annual consolidated financial statements and in notes 2 and 3 to the March 31, 2021 condensed interim consolidated financial statements. Certain accounting policies are identified as critical because they require management to make judgments and estimates based on conditions and assumptions that are inherently uncertain, and because the estimates are of material magnitude to revenue, expenses, adjusted funds flow from operations, income or loss and/or other important financial results. These accounting policies could result in materially different results should the underlying conditions change, or the assumptions prove incorrect.

Critical accounting estimates are those requiring management to make particularly subjective or complex judgments about inherently uncertain matters. Estimates and underlying assumptions are reviewed on an ongoing basis and any revisions to accounting estimates are recognized in the same period. Management’s assumptions are based on factors that, in management’s opinion, are relevant and appropriate, and may change over time as operating conditions change.

Disclosure Controls and Procedures (“DC&P”)

DC&P have been designed to provide reasonable assurance that information required to be reported by Pipestone Energy is gathered, recorded, processed, summarized and reported to senior management, including the President and Chief Executive Officer and Chief Financial Officer of Pipestone Energy, to

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allow timely decisions regarding required public disclosure by Pipestone Energy in its annual filings, interim filings, or other reports filed or submitted in accordance with Canadian securities legislation.

Internal Controls over Financial Reporting (“ICFR”)

Management of Pipestone Energy is responsible for establishing and maintaining ICFR for Pipestone Energy to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. There have been no changes to the Company’s ICFR during the three months ended March 31, 2021 that have materially affected, or are reasonably likely to materially affect, its ICFR.

While the President and Chief Executive Officer and Chief Financial Officer believe that Pipestone Energy’s DC&P and ICFR provide a reasonable level of assurance that they are effective, they do not expect that the DC&P or ICFR will prevent all errors and fraud. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.

Non-GAAP measures

This MD&A includes references to financial measures commonly used in the oil and natural gas industry. The terms “adjusted funds flow from operations”, “operating netback”, “adjusted funds flow netback”, “available funding”, “adjusted working capital”, “cash flow”, “free cash flow”, “net debt”, “CROIC” and “ROCE” 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.

Management believes the presentation of the non-GAAP measures provide 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 Energy uses “adjusted funds flow from operations” (cash from operating activities before changes in non-cash working capital and decommissioning provision costs incurred), 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 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 Energy’s principal business activities prior to consideration of changes in working capital.

The following table reconciles cash from operating activities to adjusted funds flow from operations:

	Three months ended
March 31,
($ thousands) 2021 2020
$ $ Cash from operating activities 18,097 31,067 Changes in non-cash working capital 10,145 (19,263) Decommissioning provision costs incurred - 16
Adjusted funds flow from operations 28,242 11,820

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Operating netback and adjusted funds flow netback

Operating netback is calculated on either a total dollar or per-unit-of-production basis, using boes, and is determined by deducting royalties, operating and transportation expenses from liquids and natural gas sales adjusted for realized gains/losses on commodity risk management contracts.

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 expenses, 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. Refer to “Financial and Operating Results” section above for further details.

Operating netback and adjusted funds flow netback are common metrics used in the oil and natural gas industry and are used by Company 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.

Adjusted working capital and available funding

Available funding is comprised of adjusted working capital and undrawn portions of the Company’s credit facility. Adjusted working capital 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. The available funding measure allows management and others to evaluate the Company’s short-term liquidity. Also refer to “Liquidity and Capital Resources” above for additional information.

Cash flow

“Cash flow” is a non-GAAP measure that is calculated as cash from operating activities plus changes in non-cash working capital 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 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 Energy’s principal business activities prior to consideration of changes in working capital.

Free Cash Flow

“Free cash flow” should not be considered an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with IFRS as an indicator of financial performance. Free cash flow is presented to assist management and investors in analyzing operating performance by the business in the stated period. Free cash flow equals cash flow from operating activities plus change in non-cash working capital less capital expenditures.

Net debt

Net debt is a non-GAAP measure that equals bank debt outstanding and adjusted working capital. The Company does not consider its convertible preferred share obligation to be part of net debt as this represents a non-cash obligation that will ultimately be settled by conversion into Pipestone Energy common shares and 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 and investors to evaluate Pipestone Energy’s financial strength. Also refer to “Liquidity and Capital Resources” above for additional information.

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CROIC and ROCE

Adjusted EBITDA is calculated as profit or loss before interest, income taxes, depletion and depreciation, adjusted for certain non-cash and extraordinary items primarily relating to unrealized gains and losses on risk management contracts. Adjusted EBITDA is used to calculate CROIC. Adjusted EBIT is calculated as adjusted EBITDA less depletion and depreciation. Adjusted EBIT is used to calculate ROCE.

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 of 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 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. Also refer to “Liquidity and Capital Resources” above for additional information.

The Company has calculated its CROIC and ROCE using annualized results from the three months ended March 31, 2021 and balances as at March 31, 2021 as follows:

($ thousands)	Three months ended March 31, 2021
Net loss and comprehensive loss	(954)
Deferred income tax recovery	(114)
Financing expense	5,662
Unrealized gain on interest rate risk management	(345)
Realized loss on interest rate risk management	244
D&D expense	14,706
Share-based compensation	574
Unrealized loss on commodityrisk management	12,734
Adjusted EBITDA	32,507
Annualized Adjusted EBITDA(annualized factor 4x)	130,028

($ thousands)	As at March 31, 2021
Exploration and evaluation (E&E) assets – gross carrying value	34,260
Property and equipment (P&E) – net carrying value	615,665
P&E – accumulated D&D	77,105
E&E assets and P&E – gross carrying value	727,030
ROU assets – net carrying value	53,437
ROU assets – accumulated depreciation	9,333
E&E, P&E and ROU assets – gross carrying value	789,800
CROIC	16.5%

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($ thousands)	Three months ended March 31, 2021
Adjusted EBITDA	32,507
D&D expense	(14,706)
Adjusted EBIT	17,801
Annualized Adjusted EBIT(annualized factor 4x)	71,204

($ thousands)	As at March 31, 2021
Total assets	742,147
Total current liabilities	85,896
Net assets	656,251
ROCE	10.9%

Oil and Gas Measures

DCE&T

This document may contain certain other oil and gas metrics, including DCE&T (drilling, completion, equip and tie-in costs), which 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 and future performance may not compare to the performance in previous periods and therefore such metrics should not be unduly relied upon. DCE&T includes all capital spent to drill, complete, equip and tie-in a well.

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.

CGR

Any references herein to “CGR” mean condensate/gas ratio and is expressed as a volume of condensate and NGLs (expressed in barrels) per million cubic feet (mmcf) of natural gas.

Initial Production Rates and Short-Term Test Rates

This document 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

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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 MD&A 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 natural gas liquids (including condensate, butane and propane).

Disclosure of production on a per boe basis in this MD&A consists of the constituent product types and their respective quantities as disclosed in the following table:

	Condensate (bbls/d)	Other NGLs (bbls/d)	Total NGLs (bbls/d)	Crude Oil(1) (bbls/d)	Natural Gas(2) (Mcf/d)	Total (boe/d)
April 2021 (Field Estimate)	7,085	2,970	10,055	NMN(3)	76,775	22,850

(1) References to crude oil in production amounts are to the product type “tight oil”.

(2) References to natural gas in production amounts are to the product type “shale gas”.

(3) NMN – not meaningful number.

See Financial and Operating Results for production by product type in the periods disclosed.

Risk Factors

In March 2020, the World Health Organization declared a global pandemic following the emergence and rapid spread of a novel strain of the coronavirus. The outbreak and subsequent measures intended to limit the pandemic contributed to significant declines and volatility in financial markets. The pandemic has adversely impacted global commercial activity, including significantly reducing worldwide demand for crude oil.

The full extent of the impact of COVID-19 on the Company’s operations and future financial performance is currently unknown. It will depend on future developments that are uncertain and unpredictable, including the duration and spread of COVID-19, its continued impact on capital and financial markets on a macro-scale and any new information that may emerge concerning the severity of the virus. While vaccination programs are being implemented around the world which may mitigate these impacts, uncertainties may persist while vaccination programs are in progress or as a result of the potential spread of variants or other factors. The outbreak presents uncertainty and risk with respect to the Company, its performance, and estimates and assumptions used by management in the preparation of its financial results.

In addition to the risks of COVID-19, the acquisition, exploration and development of crude oil, condensate, other NGLs and natural gas properties and the production, transportation and marketing of crude oil, condensate, other NGLs and natural gas involves many other risks, which may influence the

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ultimate success of the Company. While the management team of Pipestone Energy realizes these risks cannot be eliminated entirely, it is committed to monitoring and mitigating these risks. These risks include, but are not limited to the following:

• Oil, condensate, other NGLs and natural gas prices are volatile. A sustained decline in oil, condensate, other NGLs and natural gas prices may adversely affect the Company's profitability;

• Declining general economic, business or industry conditions may have a material adverse effect on the Company's results of operations, liquidity and financial condition;

• The Company's actual capital costs, operating costs and economic returns may differ significantly from those it has anticipated;

• The Company's success depends on finding, developing or acquiring additional reserves, which requires significant capital investment. The Company may not be able to obtain needed capital or financing on satisfactory terms or at all;

• The Company’s access to capital may become constrained as large sovereign wealth funds and other large institutional investors move towards net zero carbon investment strategies which the Company may not be able to achieve;

• Negative public perception of oil and natural gas development and transportation, hydraulic fracturing and fossil fuels, may harm the Company's profitability and corporate reputation;

• Federal and provincial legislative and regulatory initiatives regarding oil and natural gas development and fossil fuel activity could result in increased costs and additional operating restrictions or delays;

• Federal and provincial legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays;

• The Company relies on surface and groundwater licenses, which if rescinded or the conditions of which are amended, could disrupt its business and have a material adverse effect on its business;

• The Company may be unable to effectively manage growth;

• The Company's failure to successfully identify and make attractive acquisitions, joint ventures or investments, or successfully integrate future acquisitions of properties or businesses could disrupt its business, reduce its earnings and slow its growth;

• The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or qualified personnel may restrict the Company's operations;

• The direct and indirect costs of various GHG regulations, existing and proposed, may adversely affect the Company's business, operations and financial results, including demand for the Company's products;

• The Company may be unable to satisfy its obligations under its firm commitment transportation and processing arrangements;

• The Company relies on a few key employees whose absence or loss could disrupt its operations and have a material adverse effect on its business;

• The marketability of the Company's production is dependent upon compressors, gathering lines, pipelines, gas processing facilities and other facilities, certain of which the Company does not own nor control and which may fail or not perform as predicted. When these facilities are unavailable, the Company's operations can be interrupted and its revenues reduced;

• The Company's identified drilling locations, which are part of the Company's anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling;

• Drilling for oil, condensate and other NGLs and natural gas, successfully stimulating well productivity and producing oil, condensate and other NGLs and natural gas are high-risk activities with many uncertainties that may result in a total loss of investment and adversely affect the Company's business, financial condition or results of operations;

• Operating hazards and uninsured risks may result in substantial losses and could prevent the Company from realizing profits;

• The Company's drilling activities will encounter Sour Gas;

• The Company is exposed to project risks in the execution of its business plan;

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• Unless the Company replaces the reserves that it produces through exploration and development, its existing reserves and production will decline, which would adversely affect the Company's business financial condition and results of operations;

• All of the Company's properties are located in the Pipestone Montney region, making the Company vulnerable to risks associated with having its production concentrated in that area;

• Unforeseen title defects may result in a loss of entitlement to production and reserves;

• The Company's permits, licenses and mineral rights may be subject to challenges by Indigenous groups;

• Abandonment and reclamation costs are difficult to estimate reliably and the accrued liabilities in respect of such costs may not be sufficient;

• The Company's development and exploratory drilling efforts and its well operations may not be profitable or achieve the Company's targeted returns;

• Part of the Company's strategy involves exploratory drilling using the latest available horizontal drilling and completion techniques; therefore, the results of the Company's planned exploratory drilling activities are subject to drilling and completion technique risks and drilling results may not meet the Company's expectations for reserves or production;

• The Company has limited intellectual property protection for its operating practices and depends on the expertise of its employees and contractors;

• Third parties may make claims regarding the Company's rights to use the techniques and equipment the Company employs;

• Certain of the Company's undeveloped leasehold acreage is subject to agreements that may expire in the near future;

• Properties the Company has acquired and may acquire in the future may not produce as projected, and the Company may be unable to determine reserve potential, identify liabilities associated with the properties that the Company acquires or obtain protection from sellers against such liabilities;

• The Company's operations are subject to various governmental regulations which require compliance that can be burdensome and expensive;

• Provincial laws and regulations are a significant factor in the profitability of oil, condensate and other NGLs and natural gas production in Canada and changes to these regimes and/or in their interpretation and enforcement could adversely affect the Company's profitability;

• The Company's operations may be exposed to significant delays, costs and liabilities as a result of environmental, health and safety concerns and requirements that are applicable to the Company's business activities;

• Restrictions on operational activities intended to protect certain species of wildlife may adversely affect the Company's ability to conduct drilling and other operational activities in some of the areas where it operates;

• Some of the Company's directors and officers have conflicts of interest as a result of their involvement with other firms or companies;

• Actual results may differ materially from management estimates and assumptions;

• The Company's activities are affected by seasonality;

• The Company may be affected by alternatives to and changing demand for petroleum products;

• The Company faces extensive competition in its industry;

• The Company may be exposed to third-party credit risk;

• The Company depends upon a limited number of customers for the sale of most of its oil, condensate and other NGLs and natural gas production. The loss of one or more of these purchasers or the security of such purchase contracts could have a material adverse effect on the Company's business and financial condition;

• Lower oil, condensate and other NGLs and natural gas prices and higher costs increase the risk of write-downs of the Company's oil and natural gas property assets;

• The Company's use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of the Company's drilling operations;

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• The Company has entered into commodity price hedging instruments and may in the future enter into additional contracts for a portion of its production, which may result in the Company making cash payments or prevent the Company from receiving the full benefit of increases in prices for oil, condensate and other NGLs and natural gas;

• A terrorist attack or armed conflict could harm the Company's business;

• The Company's information assets and critical infrastructure may be subject to cyber security risks;

• Loss of the Company's information and computer systems could adversely affect the Company's business;

• The Company may be unable to dispose of non-strategic assets on attractive terms and may be required to retain liabilities for certain matters;

• The Company may be required to make a security deposit under provincial liability management programs;

• Reassessment of the Company's prior transactions and tax filings could subject the Company to higher than expected past or future tax liability, interest or penalties. Changes to tax laws, or the interpretation thereof, may have a detrimental effect on the Company;

• Variations in foreign exchange rates and interest rates could negatively impact the Company's production revenues, the value of the Company's reserves and the Company's cost of debt;

• The Company's insurance policies may not be sufficient to cover the full extent of the risks to which the Company is exposed;

• The Company may encounter challenges in accessing insurance for its operations in the future and, if available, it may be offered at punitive rates as major insurers begin to implement their ESG policies, goals and targets which the Company may not be able to satisfy or conform with;

• The Company may become involved in litigation which could have a material adverse effect on the Company's business and financial condition;

• Non-IFRS measures are based upon variable components and future calculations may vary;

• Breach by a third-party of its obligations to the Company could have a material adverse effect on the Company's business and financial condition;

• Future expansion by the Company into new activities may change the Company's risk exposure;

• The Company may not be able to respond quickly to competitive pressures to adopt new technologies which could have a materially adverse effect on the Company's business and financial condition;

• Estimates of oil, NGLs and natural gas reserves and production therefrom are uncertain and may vary substantially from actual production;

• Significant Shareholder Control of the Company;

• The price of the Common Shares could be volatile;

• There may be no return on investment in the Common Shares;

• The Common Shares may be subject to further dilution and a significant number of Common Shares may be sold by shareholders;

• The Company has no near-term plans to pay dividends;

• The Company may be unable to comply with its covenants under the credit agreement or otherwise default on its obligations under the credit agreement;

• The Company may incur substantially more indebtedness, which could exacerbate the risks that the Company faces; and

• Restrictive covenants in the credit agreement, and in future debt instruments may restrict the Company's ability to pursue its business strategies.

Forward-Looking Statements

This document contains certain forward-looking statements. Forward-looking statements are subject to known and unknown risks, uncertainties and other factors that could influence actual results or events and cause them to differ materially from those stated, anticipated or implied. Forward-looking statements necessarily involve risks including, without limitation, those associated with liquids and natural gas

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exploration, development, production, marketing and transportation, such as dry holes and noncommercial wells, loss of markets, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, production declines, health, safety and environmental risks, competition from other producers and the ability to access sufficient capital from internal and external sources. Forward‐looking information may include statements with words such as “anticipate”, “believe”, “expect”, “plan”, “intend”, “estimate”, “propose”, “project”, “scheduled”, or similar words suggesting future outcomes. Readers and prospective investors in the Company’s securities are cautioned not to place undue reliance on forward‐looking information as, by its nature, it is based on current expectations regarding future events that involve a number of assumptions, inherent risks and uncertainties, which could cause actual results to differ materially from those anticipated by the Company.

In particular, but without limiting the foregoing, this document contains forward-looking statements pertaining to: strategic plans and growth strategies; a 2021 development program to be optimized by continuous drilling and completions, and focusing on developing inventory adjacent to existing in-field infrastructure; estimated production and cash flow growth; plans for positive corporate returns on capital; plans to generate significant annual free cash flow; plans to deliver on development plans within current borrowing capacity while reducing leverage metrics; realizing positive returns on capital; proposed development plans; three year corporate guidance and forecasts; further optimization of in-field infrastructure leading to increased sales production capacity; reduction in capital investment in infrastructure; timing of abandonment and reclamation obligations; reducing operating expenses in the future as a result of the Company’s 3-12 pad-site water handling facility commissioned; maintaining G&A expense through the Company’s growth; the Company not qualifying for COVID-19 government subsidy programs; bringing the 6-13 pad wells on-stream early in the second quarter of 2021; the drilling of 6 additional wells at the existing 6-24 pad during the second quarter of 2021; and the timing of the Alberta LMF being implemented in mid-2021.

With respect to the forward-looking statements contained in this document, Pipestone Energy has assessed material factors and made assumptions regarding, among other things: future commodity prices and currency exchange rates, including consistency of future oil, natural gas liquids (NGLs) and natural gas prices with current commodity price forecasts; the economic impacts of the COVID-19 pandemic; Pipestone Energy’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 Energy’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 Energy’s future production levels and amount of future capital investment, and their consistency with Pipestone Energy’s current development plans and budget; future capital expenditure requirements and the sufficiency thereof to achieve Pipestone Energy’s objectives; the successful application of drilling and completion technology and processes; the applicability of new technologies for recovery and production of Pipestone Energy’s reserves and other resources, and their ability to improve capital and operational efficiencies in the future; the recoverability of Pipestone Energy's reserves and other resources; Pipestone Energy’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 Energy’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 Energy’s reserves and other resources; the accuracy of geological and geophysical data and the interpretation thereof; the geography of the areas in which Pipestone Energy conducts exploration and development activities; the timely receipt of required regulatory approvals; the access, economic, regulatory and physical limitations

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to which Pipestone Energy may be subject from time to time; and the impact of industry competition.

The forward-looking statements contained herein reflect management's current views, but the assessments and assumptions upon which they are based may prove to be incorrect. Although Pipestone Energy 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 Energy’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; general economic, business and industry conditions; variance of Pipestone Energy’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; and risks related to the exploration, development and production of oil and natural gas reserves and resources. Additional risks, uncertainties and other factors are discussed under the heading “Risk Factors” and in Pipestone Energy’s annual information form dated March 10, 2021, a copy of which is available electronically on SEDAR at www.sedar.com.

Certain information in this MD&A is “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure of the Company’s reasonable expectations of its anticipated results. The financial outlook is provided as of the date of this MD&A. Readers are cautioned that this financial outlook may not be appropriate for other purposes.

The forward-looking statements contained in this document are made as of the date hereof and Pipestone Energy 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.

Abbreviations

The following summarizes the abbreviations used in this document:

Crude Oil, Condensate and other Natural Gas Liquids	Crude Oil, Condensate and other Natural Gas Liquids	Natural	Gas
bbl	barrel	Mcf	thousand cubic feet
Mbbl	thousand barrels	MMcf	million cubic feet
bbls/d	barrelsper day	Mcf/d	thousand cubic feetper day
boe	barrel of oil equivalent	GJ	Gigajoule;1 Mcf of naturalgas is about 1.05 GJ
Mboe	thousand barrels of oil equivalent	MMBtu	million British thermal units;1 GJ is about 0.95 MMBtu
boe/d	barrel of oil equivalentper day
NGL	natural gas liquids, consisting of ethane (C2),
	propane(C3)and butane(C4)
Bbls/MMcf	barrelsper million cubic feet
CGR	Condensate-gas ratio. Measures the liquid
	content of the hydrocarbon mixture
condensate	Pentanes plus (C5+) separated at the field level
	and C5+ separated from the NGL mix at the
	facilitylevel

Other Abbreviations $000s thousands of dollars Adjusted working capital (current assets less current liabilities), excluding financial derivative instruments and lease working capital liabilities AECO the AECO Hub, a natural gas storage facility located in Suffield and Countess, Alberta, part of the NOVA Pipeline

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Other Abbreviations

	System
Alliance Chicago	a market hub for natural gas transported on the Alliance Pipeline to be purchased and sold between entities
Exchange Hub
Alliance Pipeline	a naturalgaspipeline runningfrom northeastern British Columbia to Illinois,in the United States
C$	Canadian dollars
Chicago City	Chicago Index Futures natural gas price
Gate
collar	a risk-management strategy employed by the Company in which an out-of-the-money put option is purchased,
	while simultaneously writing an out-of-the-money call option. Collars are entered into at no cost (the cost of the
	put is offset by the proceeds of the call). Collars allow the Company to receive the price of the commodity between
	the collar range. The downsidepriceprotection is at the cost of limitingthepotential upsideprice
COVID-19	Novel Coronavirus
CROIC	cash return on invested capital
D&D	depletion and depreciation
EBIT	earnings before interest and taxes
EBITDA	earnings before interest,taxes,depreciation and amortization
EdCon	Edmonton Condensate
Enbridge	Enbridge Inc. and its affiliates
G&A	general and administrative
GAAP	Generallyaccepted accounting principles
IAS	International AccountingStandard
IASB	International AccountingStandards Board
IFRIC	International Financial ReportingInterpretations Committee
IFRS	International Financial ReportingStandards
IFRS 16	International Financial ReportingStandards 16, Leases
Keyera	Keyera Corp. and its affiliates
NE	Northeast
NGTL	Nova Gas Transmission Ltd. refers to a naturalgasgatheringsystem for the Western Canadian SedimentaryBasin
NMN	Not meaningful number
NW	Northwest
NYMEX	New York Mercantile Exchange
OPEC	Organization of Petroleum ExportingCountries
Pembina	Pembina Pipeline Corporation and its affiliates
PSU	performance share unit
Q1	firstquarter ended March 31st
Q2	secondquarter ended June 30th
Q3	thirdquarter ended September 30th
Q4	fourthquarter ended December 31st
ROCE	return on capital employed
ROU	right-of-use
RSU	restricted share unit
SE	Southeast
SW	Southwest
swap	over-the-counter contracts relating to interest rates, foreign exchange or commodities. Entered into by the
	Companyto reduce variabilityand manage risk via fixingthat variable
TCPL	TC Pipelines Limited
Tidewater	Tidewater Midstream and Infrastructure Ltd. and its affiliates
TSX	Toronto Stock Exchange
US$	United States dollars
WTI	West Texas Intermediate
YTD	year-to-date

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Corporate Information BOARD OF DIRECTORS

GORDON RITCHIE, CHAIR[(1)(2)] GARTH BRAUN[(2)]

WILLIAM LANCASTER[(1)(3)] JOHN ROSSALL[(1)(2)(3)]

GEETA SANKAPPANAVAR[(3)] ROBERT TICHIO[(2)]

PAUL WANKLYN

Notes:

MANAGEMENT

PAUL WANKLYN President & Chief Executive Officer

DUSTIN HOFFMAN Chief Operating Officer

CRAIG NIEBOER Chief Financial Officer

DARCY ERICKSON Vice President, Operations & Production

DAN VAN KESSEL Vice President, Corporate Development

NEAL ROSS Corporate Secretary

(1) Audit Committee

(2) Compensation and Governance Committee

(3) Reserves and HSE Committee

HEAD OFFICE

Suite 3700, 888 – 3[rd] Street S.W. Calgary, Alberta T2P 5C5

EVALUATION ENGINEERS

McDaniel & Associates Consultants Ltd. Calgary, Alberta

LEGAL COUNSEL

Telephone: 587.392.8411

Osler, Hoskin & Harcourt LLP Calgary, Alberta

AUDITORS

Ernst & Young LLP Calgary, Alberta

TRANSFER AGENT

Odyssey Trust Company Calgary, Alberta

BANKERS

National Bank of Canada Bank of Montreal ATB Financial Canadian Western Bank

STOCK EXCHANGE LISTING

Toronto Stock Exchange Symbol: PIPE

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