Pipestone Energy Corp. — Management Reports 2020

Aug 12, 2020

MANAGEMENT’S DISCUSSION AND ANALYSIS

==> picture [612 x 580] intentionally omitted <==

HIGHLY FOCUSED ON DEVELOPING THE EXCEPTIONAL MONTNEY PLAY

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2020

Pipestone Energy Corp. – Financial and Operating Highlights

		Three months ended June 30,	Three months ended June 30,	Three months ended June 30,			Six months ended	Six months ended	June 30,
($ thousands, except per unit and per share amounts)		2020		2019			2020		2019
Financial
Sales of liquids and natural gas	$	26,380	$	5,457		$	58,397	$	5,917
Cash from (used in) operating activities		(175)		(777)			30,892		(13,562)
Adjusted funds flow from (used in) operations (1)		11,231		(2,423)			23,051		(11,086)
Per share, basic and diluted (2)		0.06		(0.01)			0.12		(0.06)
Income (loss)		(19,486)		4,869			(3,945)		567
Per share, basic and diluted(2)		(0.10)		0.03			(0.02)		0.00
Capital expenditures		19,893		46,835			49,047		96,303
Acquisitions	$	-	$	91			-		116
Working capital (deficit)(end of period)							(16,781)		(8,026)
Bank debt_(end of period)_							183,248		115,754
Shareholders’ equity_(end of period)_							367,298		383,843
Available funding_(end of period)_(3)						$	13,421	$	46,033
Annualized cash return on invested capital
(CROIC)(%)(3)		8.6%		NMN(6)			8.9%		NMN(6)
Annualized return on capital employed
(ROCE)(%)(3)		(0.5%)		NMN(6)			0.7%		NMN(6)
Shares outstanding_(end of period)_(2)							190,295		189,627
Weighted-average basic shares outstanding(2)		190,136		189,624			189,990		187,096
Weighted-average diluted shares outstanding(2)		190,253		189,625			190,229		187,116
Operations
Production
Crude oil_(bbls/d)_		104		29			95		55
Condensate_(bbls/d)_		4,781		566			4,368		285
Other natural gas liquids (NGL)(bbls/d)		2,306		88			1,786		53
Total NGL_(bbls/d)_		7,087		654			6,154		338
Natural gas_(Mcf/d)_		57,488		4,341			55,017		2,341
Total_(boe/d)_(4)		16,772		1,407			15,419		783
Condensate and crude oil_(% of total production)_		29%		43%			29%		43%
Total liquids_(% of total production)_		43%		49%			41%		50%
Benchmark prices
Crude oil – WTI_(C$/bbl)_	$	38.34	$	79.98		$	49.84	$	76.47
Condensate – Edmonton Condensate_(C$/bbl)_		31.38		73.69			45.75		71.20
Natural gas – AECO 5A_(C$/GJ)_		1.90		1.04			1.91		1.75
Average realized prices(5)
Crude oil_(per bbl)_		19.88		66.91			29.49		49.08
Condensate_(per bbl)_		29.21		72.12			39.92		72.12
Other NGL_(per bbl)_		10.92		29.24			13.42		28.57
Total NGL_(per bbl)_		23.26		66.35			32.23		65.31
Natural gas_(per Mcf)_		2.14		3.37			2.18		3.39
Netbacks
Revenue_(per boe)_		17.28		42.62			20.81		41.75
Royalties_(per boe)_		0.28		(2.15)			(0.37)		(2.11)
Operating expenses_(per boe)_		(10.64)		(13.83)			(11.00)		(15.26)
Transportation_(per boe)_		(3.32)		(5.72)			(3.47)		(9.85)
Operating netback_(per boe)_ (3)		3.60		20.92			5.97		14.53
Adjusted funds flow netback_(per boe)_(3)	$	7.37	$	(18.93)		$	8.22	$	(78.22)

(1) See “Additional subtotal – Adjusted funds flow from (used in) operations” under “Critical Accounting Judgments, Estimates and Policies”.

==> picture [216 x 37] intentionally omitted <==

• (2) The number of common shares has been adjusted retrospectively to reflect the 10:1 share consolidation, as well as the 0.5996 exchange ratio, as part of the Corporate Acquisition that closed on January 4, 2019.

• (3) See “Non-GAAP measures” section of this MD&A.

• (4) 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 liquids include oil and natural gas liquids (including condensate, butane and propane).

• (5) Figures calculated before hedging.

• (6) NMN – not meaningful number at this time as Pipestone Energy had minimal production throughout the majority of 2019.

• (7) Prior period production and average realized price figures have been adjusted to conform with current period 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 August 12, 2020 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, 2019 and 2018 and the unaudited condensed interim consolidated financial statements and accompanying notes for the three and six months ended June 30, 2020 and 2019. 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 read “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 17, 2020, 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 trades on the TSX Venture Exchange under the symbol PIPE.

On January 4, 2019 the Company completed its reverse takeover of, and amalgamation with, Blackbird Energy Inc. (the “Corporate Acquisition”). Prior to the Corporate Acquisition, Pipestone Energy was a privately held entity, operating under the name Pipestone Oil Corp. (“Predecessor Pipestone”), incorporated under the Business Corporations Act (Alberta) and a wholly-owned subsidiary of Canadian Non-Operated Resources LP (“CNOR LP”), a privately held partnership formed under the laws of Alberta. The comparative figures presented for 2018 are that of Predecessor Pipestone.

Pipestone Energy is early in its development lifecycle. As of June 30, 2020, Pipestone Energy had accumulated over 140 net Montney sections (89,600 net acres) and had a total of 41 wells on, or available

2 | P a g e

for production, 8 of which are legacy wells acquired in the Corporate Acquisition and 33 are new wells that have been brought on production since September of 2019 north of the Wapiti River.

The Company has built an in-field gathering system to interconnect with third-party processing infrastructure and egress capacity. In mid-September 2019, tie-ins were completed to both the Tidewater Pipestone Plant and the Keyera Wapiti Plant allowing Pipestone Energy to begin producing from its well pad-sites located north of the Wapiti River. Production capability has continued to ramp-up in Q2 2020 as the Company tied-in 6 additional wells from its 6-30 pad-site during the quarter. The 6-30 pad-site was not brought on-stream during the second quarter to preserve its liquids production while prices remained depressed. The Company currently has the 15-14, 3-01, 6-24 and 6-30 pad-sites permanently tied-in and available for production north of the Wapiti River. Pipestone Energy has also secured the firm transportation required to match its near-term forecasted liquids and natural gas production.

Financing, RBL Amendment, and Letter of Credit Facility

Financing

Subsequent to June 30, 2020, Pipestone Energy entered into subscription agreements in respect of a financing transaction (the “Financing”). Pursuant to the terms of the subscription agreements, the investors have agreed to acquire convertible preferred shares (the “CP Shares”) in the Company with an initial liquidation preference of $70.0 million, equivalent to 70,000 CP Shares. The CP Shares have a conversion price of $0.85 per Common Share (the “Conversion Price”) and have a term of five years. The CP Shares were sold at a price of $970 per share, and entitle the investors to an annual dividend of 6.5% per year that is payable quarterly in-kind, or in cash after 2 years from issuance, at the sole option of Pipestone Energy. At close, the expected proceeds to Pipestone Energy are approximately $67.0 million, net of anticipated transaction costs.

The CP Shares are, subject to certain conditions, convertible into common shares of the Company at a Conversion Price of $0.85 per common share, subject to customary adjustments. After two years, if among other things, the closing price of the common shares is above 200 percent of the Conversion Price for 20 days over a 30-day trading period, the CP Shares will automatically convert into common shares at the Conversion Price. Holders of the CP Shares will be entitled to vote on all shareholder matters alongside existing holders of the common shares on an “as-converted” basis. After the five year term the CP Shares will be automatically converted into common shares based at either the Conversion Price or, otherwise, at a price based on the previous 20-day volume weighted average share price multiplied by 95%.

Closing of the Financing is subject to shareholder approval, including (i) a majority of not less than 66⅔ percent of votes cast in person or by proxy and (ii) a “majority of the minority” vote to be held in accordance with Policy 5.9 of the TSX-V and Multilateral Instrument 61-101 – Protection of Minority Security Holders in Special Transactions . The shareholder vote will be held at Pipestone’s Annual General and Special Meeting on September 14, 2020.

RBL Amendment

Subject to the shareholder vote and closing of the Financing, the Company has re-confirmed and executed an amendment to its $225.0 million RBL with its corporate banking syndicate. In light of the significant equity capital injection and accelerated capital plan, the banking syndicate will forgo the normal fall borrowing base review with the next redetermination scheduled for May 2021. In addition, the previously imposed capital spending restrictions from the June 2020 re-determination will be removed, and the

3 | P a g e

Company has agreed to implement a robust hedging program with respect to expected condensate volumes through calendar 2021.

Letter of Credit Facility

To further enhance the go forward liquidity position of the Company, on July 16, 2020, Pipestone Energy closed on a $15.0 million unsecured letter of credit facility under Export Development Canada’s performance security guarantee (“PSG”) program. The Company subsequently transferred its $14.3 million of letters of credit outstanding as at June 30, 2020, from its Operating Line to the PSG facility. The result is $14.3 million of additional availability to the Company under its Operating Line.

Operations Update, Revised Guidance and Outlook

Operations Update

Throughout Q2 2020, Pipestone Energy actively managed its production in response to increased volatility in crude oil prices and condensate differentials that prevailed during the quarter. Specifically, condensate production was optimized month to month by shutting in the seven well 6-24 pad during May and gradually bringing it back on in response to improved pricing during June. Production for the quarter averaged 16,772 boe/d, which was comprised of 43% liquids (including 29% condensate) and 57% natural gas. The Company benefited from strong plant run-times at both the Keyera Wapiti Gas Plant and Tidewater Pipestone Gas Plant during the quarter of ~96% (compared to ~70% during Q1 2020). The Company has significant incremental production capability with six wells recently completed and tied-in on the 6-30 pad. The wells on this pad are being tested during July and August and are expected to be brought on-stream permanently by Q4 2020.

Revised Guidance & Outlook

Contingent on closing the Financing, Pipestone Energy will be increasing its 2020 capital guidance from $60.0 million to $110.0 million. In September 2020, the Company expects to utilize two rigs to drill six wells on its 3-12 pad, which will be completed in November and available for production by year end. On the 8-15 pad, one rig will drill four additional wells starting in November 2020, which are expected to be completed and brought on-stream during Q1 2021.

In 2021, the Company plans to undertake a continuous drilling program, utilizing up to two rigs along the North-South gathering system. The program will be designed to optimize the infrastructure capital spent to date. In 2021, Pipestone Energy aims to bring 28 - 32 new wells on production, anticipates capital spending to be ~$210.0 million (90 percent of which will be on drilling, completion and equip & tie-in costs) and expects to produce between 24,000 – 26,000 boe/d in 2021.

4 | P a g e

2020 – 2021 Development Map

==> picture [468 x 259] intentionally omitted <==

Expected Development Activity Summary

	# Wells Drilled	# Wells Completed	# of New Wells on Production
2019 Actuals	10	16	20
H1 2020 Actuals	6	6	12
H2 2020 Forecast	10	6	-
2021 Forecast	30 - 36	30 - 36	28 - 32

3 Year Corporate Growth Trajectory[ (1)]

	2020	2021	2022
Full Year Production(boe/d)	16,000 – 17,000	24,000 – 26,000	34,000 – 38,000
Cash Flow($million)(2)(3)	$40.0	$135.0	$205.0
Capex($million)(4)	$110.0	$210.0	$215.0
YE Net Debt($million)(3)	$180.0	$255.0	$265.0
LTM Debt/CF(x)	4.5x	1.8x	1.3x

1. 3-year plan 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 forecast beyond 2020 have not been finalized and are subject to a variety of factors. Maximum total draw on the Company’s RBL in the forecasts shown would be less than C$225.0 million.

2. Price assumptions: Rem. 2020 = US$40 WTI; $1.90 AECO; $0.74 CAD | 2021 = US$42 WTI; $2.25 AECO; $0.74 CAD | 2022 = US$44 WTI; $2.25 AECO; $0.74 CAD.

3. See “non-GAAP Measures”. Forecast represents the mid-points of the anticipated production ranges. Net Debt excludes Convertible Preferred Shares as no cash liability and includes Working Capital Deficit.

4. Capex includes all anticipated DCE&T, infrastructure and other capital expenditures, but excludes capitalized G&A. 2020 CAPEX increased from $60.0 million previously.

5 | P a g e

The Company anticipates that the accelerated H2 2020 and 2021E development activity that will be undertaken as a direct result of the Financing will position Pipestone Energy to fill in-field infrastructure and generate significant free cash flow above maintenance requirements by year-end 2022 at US$44 WTI, while maintaining significant liquidity and a strong leverage profile.

Second Quarter 2020 Corporate Highlights

• During the quarter the Company actively managed its production to meet third-party gathering and processing commitments by primarily flowing its leaner, higher rate gas wells located at the 15-14 and 3-01 pad-sites, limiting production from the higher condensate wells on the 6-24 pad and deferring the on-stream date of the 6-30 pad until later this fall;

• Production averaged 16,772 boe/d (comprised of 29% condensate and 43% total liquids) for the three months ended June 30, 2020;

• With a robust hedging program in place the Company realized commodity hedge gains of $10.4 million during the three months ended June 30, 2020, which protected cash flows in the period;

• The Company generated revenues and adjusted funds flow of $26.4 million and $11.2 million, respectively, during the three months ended June 30, 2020, despite the low commodity prices received; and

• During the quarter the Company concluded its successful H1 2020 completions program as planned with 6 wells frac’d at the 6-30 pad-site in April 2020 under its original budget by 20%.

Capital Expenditures

	Three months ended	Six months ended
	June 30, June 30,
($ thousands)	2020 2019	2020 2019
Drilling Completions Production equipment and facilities Land and other Capitalized G&A Capital expenditures, per cash flow statement Property acquisitions Exploration and evaluation from Corporate Acquisition Property and equipment from Corporate Acquisition Capital expenditures and acquisitions Right-of-use lease assets from Corporate Acquisition Right-of-use lease additions	$ $ $ $ 5 5 11,819 9,114 14,876 21,684 22,193 21,806 3,911 22,230 12,243 59,965 622 1,988 1,465 3,633 479 928 1,327 1,785
	19,893 46,835 49,047 96,303
	- 91 - 116 - - - 36,942 - - - 197,755
	19,893 46,926 49,047 331,116 - - - 1,630 43 1,504 43 1,548
Capital expenditures, acquisitions and right-of-use lease asset additions(1)	19,936 48,430 49,090 334,294

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

6 | P a g e

During the six months ended June 30, 2020, Pipestone Energy invested total capital expenditures of $49.0 million compared to $96.3 million in the comparative period for 2019. The decrease was primarily due to reduced spending on infield gathering, production equipment and facilities, as the Company completed its major in-field gathering system build out in 2019. This was partially offset by increased drilling activity in 2020 (6 wells in 2020 vs. 4 wells in 2019).

For the three-month period ended June 30, 2020, Pipestone Energy continued to execute on its Montney focused development program as follows:

• Investing $14.9 million in the 6 well completion program at the 6-30 pad-site which wrapped up operations in April 2020 (the Company achieved new DCE&T pacesetter performance on this pad with an average cost of $5.3 million / well); and

• Incurring $3.9 million in production equipment and facilities costs which included $2.4 million for the design and construction of the 6-30 pad-site facilities, which accommodated the tie-in of the 6 new wells from this location, $0.5 million on the two well tie-in from Pipestone Energy’s 9-14 pad-site and $1.0 million on pipelines and other minor projects.

Three months ended	Six months ended
June 30, June 30,
Montneywell activity (1) 2020 2019	2020 2019
Gross & Net Wells drilled(rig-released) - - 6.0 4.0 Wells completed 6.0 7.0 6.0 7.0

(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.

Financial and Operating Results

Production

Three months ended	Six months ended
June 30, June 30,
2020 2019(1)	2020 2019(1)
Daily average volume(2) Crude oil_(bbls/d) 104 29 95 55 Condensate(bbls/d) 4,781 566 4,368 285 Other NGL(bbls/d)_ 2,306 88 1,786 53
Total NGL_(bbls/d) 7,087 654 6,154 338 Naturalgas(Mcf/d)_ 57,488 4,341 55,017 2,341
Total sales_(boe/d)_ 16,772 1,407 15,419 783
Production weighting(2) Crude oil -% 2% 1% 7% Condensate 29% 40% 28% 36% Other NGL 14% 6% % 12% 7%
Total NGL 43% 46% 40% 43% Naturalgas 57% 52% 59% 50%
100% 100% 100% 100%

(1) Prior period production figures have been adjusted to conform with current period presentation.

(2) 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”.

7 | P a g e

Production for the three and six months ended June 30, 2020 was 16,772 boe per day (comprised of 29 percent condensate and 43 percent total liquids) and 15,419 boe per day (comprised of 28 percent condensate and 41 percent total liquids), respectively, compared to 1,407 boe per day and 783 boe per day, respectively, for the same periods in 2019.

The increase in 2020 from the comparative periods was a result of the Company having available production from the 15-14, 3-01, 6-24 and 6-30 pad-sites that are permanently tied-in and available for production north of the Wapiti River. Throughout the current quarter the Company actively managed production from these various pads to limit its liquids production due to unfavourable commodity pricing, while meeting its third-party gathering and processing commitments. The 6-24 pad was significantly curtailed in Q2 as it was gradually brought on in June and the 6-30 pad was held back entirely with no production other than immaterial test volumes during the quarter. In the comparative periods for 2019 the Company only had minor production volumes from its southern wells acquired in the Corporate Acquisition.

Sales

Three months ended	Six months ended
June 30, June 30,
($ thousands, exceptper unit amounts) 2020 2019(1)	2020 2019(1)
$ $ $ $ Crude oil 188 177 513 492 Condensate 12,707 3,715 31,740 3,715 Other NGL 2,292 234 4,360 273
Total NGL 14,999 3,949 36,100 3,988 Naturalgas 11,193 1,331 21,784 1,437
Total 26,380 5,457 58,397 5,917
Average realized prices before hedging and transportation Crude oil_($/bbl) 19.88 66.91 29.49 49.08 Condensate($/bbl) 29.21 72.12 39.92 72.12 Other NGL($/bbl)_ 10.92 29.24 13.42 28.57
Total NGL_($/bbl) 23.26 66.35 32.23 65.31 Naturalgas($/Mcf)_ 2.14 3.37 2.18 3.39
Combined average_($/boe)_ 17.28 42.62 20.81 41.75
(1) Prior period sales and average realized price figures have been adjusted to conform with current period presentation.

Sales for the three and six months ended June 30, 2020 were $26.4 million and $58.4 million, respectively, compared to $5.5 million and $5.9 million, respectively, for the same periods in 2019. The increase in 2020 from the comparative periods was a result of the Company selling production from its operations north of the Wapiti River which became available for production in fall 2019. North of the Wapiti River production accounts for the vast majority of current corporate production. In the 2019 comparative periods the Company only had minor sales from its southern wells acquired in the Corporate Acquisition.

The Company’s average realized sales prices for its condensate and crude oil during 2020 was adversely affected by the steep decline in global crude oil prices that began in March resulting from the simultaneous supply-demand shock of increased Russia-Saudi Arabia production output and the COVID-19 outbreak. The Company also realized a lower average sales price on its natural gas than the comparative periods in 2019.

8 | P a g e

Benchmark Pricing

Three months ended June 30, Six months ended June 30,	Six months ended
2020 2019	2020 2019
$ $ $ $ Average crude oil prices WTI crude oil_(US$/bbl) (1) 27.79 59.80 36.88 57.34 WTI crude oil(C$/bbl) 38.34 79.98 49.84 76.47 Average condensate prices Edmonton Condensate(C$/bbl) 31.38 73.69 45.75 71.20 Average natural gas prices AECO 5A natural gas(C$/GJ)(2) 1.90 1.04 1.91 1.75 Chicago City Gate natural gas (C$/GJ)(3) 2.16 2.93 2.19 3.38 Average foreign exchange rate Exchange rate(US$/C$)_ 0.72 0.75 0.74 0.75

(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.

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.

In March and April of 2020 crude oil pricing and futures suffered a significant decline 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. These events also negatively impacted the market outlook for Edmonton condensate pricing due to expected heavy oil production curtailments and/or shut-ins throughout Alberta. Subsequently there has been slow and minor recoveries experienced in the price of crude oil with the rebalancing of global supply and demand.

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, increasing domestic production and limited access to local storage facilities. During the current quarter AECO 5A pricing and futures improved from the first quarter of 2020. 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.

The Company hedged certain expected future liquids volumes to WTI directly in C$ and the Company also hedged a subset of volumes to the differential between WTI and Edmonton Condensate (“EdCon”). 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 significant portion of its forecasted natural gas production as well for 2020 and 2021 utilizing AECO swaps. See the “Commodity Price Risk Management” section below for more details.

9 | P a g e

Royalties

Three months ended	Six months ended
June 30, June 30,
2020 2019(1)	2020 2019(1)
$ $ $ $ Gross royalties_($ thousands) 1,423 295 2,970 323 Gas cost allowance(“GCA”) ($ thousands)_ (1,845) (20) (1,924) (25)
Net royalties(recovery) (422) 275 1,046 298
Gross royalties Per boe_($)_ 0.93 2.31 1.06 2.28 Percentage of sales 5.4% 5.4% 5.1% 5.5%
Net royalties Per boe_($)_ (0.28) 2.15 0.37 2.11 Percentage of sales (1.6%) 5.0% 1.8% 5.0%

(1) Prior period royalty figures have been adjusted to conform with current period presentation.

Pipestone Energy’s royalty burden is predominately paid to the province of Alberta, with minimal gross over-riding royalties applicable on a portion of the Company’s production sales. The 2020 and 2019 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 for the three and six months ended June 30, 2020 were a recovery of $0.4 million and an expense of $1.0 million, respectively, compared to an expense of $0.3 million for the three and six months ended June 30, 2019.

The increase in gross royalties paid during 2020 was a result of the significantly increased production volumes generated from six months of operating the Company’s northern wells partially offset by the Company’s initial GCA claim made on its new facilities and third-party gathering and processing arrangements.

Operating Expense

Three months ended	Six months ended
June 30, June 30,
2020 2019	2020 2019
$ $ $ $ Operating expense_($ thousands) 16,237 1,770 30,857 2,163 Per boe($)_ 10.64 13.83 11.00 15.26

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, lease rentals, insurance and property taxes making up the balance.

Operating expenses for the three and six months ended June 30, 2020 were $16.2 million and $30.9 million, respectively, compared to $1.8 million and $2.2 million, respectively, for the same periods in 2019. The increase in operating expenses in 2020 was a result of the Company bringing on production from its north of the Wapiti River wells for the entire three and six month periods. The Company’s third-party gathering and processing commitments began concurrent with production start-up north of the Wapiti River in September 2019.

The operating expenses per boe decreased in 2020 as a result of fixed operating costs being spread over a larger production base and improved third-party gathering and processing fee structures in place. In response to the challenging commodity price environment the Company renegotiated certain third-party gathering and processing agreements and fees to further improve its profitability at the field-level.

10 | P a g e

Transportation Expense

Three months ended	Six months ended
June 30, June 30,
2020 2019	2020 2019
$ $ $ $ Transportation expense_($ thousands) 5,063 733 9,747 1,396 Per boe($)_ 3.32 5.72 3.47 9.85

Pipestone Energy has entered into various firm service contracts to transport its current and future expected production volumes. Transportation expense primarily consist 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.

Transportation expenses for the three months ended June 30, 2020 were $5.1 million compared to $0.7 million for the three months ended June 30, 2019.

Transportation expenses for the six months ended June 30, 2020 were $9.7 million compared to $1.4 million for the six months ended June 30, 2019.

The increase to transportation expense was a result of the Company transporting greater sales volumes produced during the 2020 periods compared to 2019.

The transportation expense per boe decreased in 2020 due to better utilization of commitments and mitigating take-or-pay fee exposure on unfilled capacities.

Commodity Price Risk Management

Pipestone Energy’s commodity price risk management program is primarily 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’s ongoing hedge program is focused on its exposure to forecast liquids and naturals gas production. Pipestone Energy utilizes a variety of hedging structures, including fixed price swaps, product differential hedges and collars. To date, Pipestone Energy has entered into hedges with respect to benchmark WTI, AECO and EdCon (Edmonton condensate) directly. 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 entered into forward swaps on the differential between the Net Canadian Energy Monthly Index Edmonton C5+ price and WTI, traded in US$ per barrel on the Chicago Mercantile Exchange. A fixed-price Edmonton C5+ swap can be generated through the combination of a WTI swap and an Edmonton C5+ differential swap.

The Company has elected not to use hedge accounting and, accordingly, the fair value of the commodity financial derivative instruments 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 balance sheet date. 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

11 | P a g e

gain or loss on financial derivative instruments is recorded in the current period’s profit or loss, while the estimated future value of the underlying physical sales is not.

Commodity financial derivative instruments

Three months ended	Six months ended
June 30, June 30,
2020 2019	2020 2019
$ $ $ $ Realized gain (loss) on commodity financial derivative instruments_($ _thousands) Condensate (85) - (1,818) - Crude Oil 11,723 (122) 19,599 (122) Naturalgas (1,189) - (1,167) -
Total 10,449 (122) 16,614 (122) Per boe_($)_ 6.85 (0.96) 5.92 (0.86)
Unrealized gain (loss) on commodity financial derivative instruments_($ _thousands) Condensate (1,913) 706 2,237 706 Crude oil (17,881) 7,526 291 6,851 Naturalgas (37) - 20 -
Total (19,831) 8,232 2,548 7,557 Per boe_($)_ (12.99) 64.29 0.91 53.32

During March and April 2020 crude oil pricing and futures suffered a significant decline as a result of the COVID-19 virus’ negative impact on global demand combined with the failure of OPEC and Russia to reach an agreement on meaningful production cuts. Subsequently there has been some recovery experienced in the price of crude oil with the rebalancing of global supply and demand. Pipestone Energy’s commodity price risk management program has mitigated a considerable portion of the Company’s exposure to the global oil market fluctuations experienced in the first half of 2020 and will continue to play a vital role as the Company continues to actively manage this program to protect its cash flows and liquidity.

During the three months ended June 30, 2020, the Company had a realized gain on commodity financial derivative instruments of $10.4 million compared to a realized loss of $0.1 million during the three months ended June 30, 2019. The realized gain on commodity financial derivative instruments was due primarily to the settlement of WTI swaps that were in-the-money partially offset by realized losses on AECO swaps. The Company had minimal realized commodity financial derivative instruments during the comparative period in 2019.

During the three months ended June 30, 2020, the Company incurred an unrealized loss on commodity financial derivative instruments of $19.8 million compared to an unrealized gain of $8.2 million during the three months ended June 30, 2019. The unrealized loss on commodity financial derivative contracts in the current period was due primarily to the rolling off of the in-the-money settlement of crude oil positions during the quarter, combined with the strengthening of WTI prices that occurred near the end of the quarter, resulting in a decline in the value of crude oil contracts outstanding compared to the prior quarter. In the comparative period for 2019 the Company had an unrealized gain on the mark-to-market value of its crude oil and condensate financial derivative instruments.

During the six months ended June 30, 2020, the Company incurred a realized gain on commodity financial derivative instruments of $16.6 million compared to a realized loss of $0.1 million during the six months

12 | P a g e

ended June 30, 2019. The realized gain on commodity financial derivative instruments was due primarily to the settlement of WTI swaps that were in-the-money partially offset by realized losses on AECO swaps and Edmonton condensate differential hedges. The Company had minimal realized commodity financial derivative instruments during the comparative period in 2019.

During the six months ended June 30, 2020, the Company incurred an unrealized gain on commodity financial derivative instruments of $2.5 million compared to an unrealized gain of $7.6 million during the six months ended June 30, 2019. The unrealized gain on commodity financial derivative contracts in the current period was due primarily to the settlement of Edmonton condensate differentials positions. In the comparative period for 2019 the Company had an unrealized gain on the mark-to-market value of its crude oil and condensate financial derivative instruments.

The Company had the following weighted-average condensate, crude oil and natural gas commodity financial derivative instruments at June 30, 2020:

	C$ WTI	**swaps **	**EdCon basis swaps **	**EdCon basis swaps **	**AECO 5A swaps **	**AECO 5A swaps **
Term	bbls/d	C$/bbl	bbls/d	US$/bbl	GJ/d	C$/GJ
Jul. – Sept. ‘20	3,818	59.39	1,000	(5.75)	40,090	1.60
Oct. – Dec. ‘20	2,000	58.25	1,000	(5.75)	28,460	1.65
Jan. – Dec. ‘21	1,062	54.53	-	-	27,836	2.27
Jan. – Dec. ‘22	-	-	-	-	2,500	1.95

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

(2) EdCon refers to Edmonton Condensate.

Subsequent to June 30, 2020, the Company entered additional commodity hedges with the following weighted-average volumes and prices:

	**C$ **	**WTI swaps **
Term	bbls/d	C$/bbl
Jan. – Dec. ‘21	500	57.43
	**AECO 5A swaps **
Term	GJ/d	C$/GJ
Jan. – Dec. ‘21	7,500	2.39

Interest rate financial derivative instruments

Three months ended June 30, Six months ended June 30,	Six months ended
2020 2019	2020 2019
$ $ $ $ Realized loss on interest rate financial derivative instruments_($ thousands) (188) - (856) - Per boe($)_ (0.12) - (0.31) -
Unrealized gain (loss) on interest rate financial derivative instruments_($ _thousands) (273)185 (1,007) (205) Per boe_($)_ (0.18) 1.45 (0.36) (1.45)

The Company has a floating-to-fixed interest rate swap in place with one of its lenders at June 30, 2020. During Q1 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

13 | P a g e

1. Due to bank debt and the swap being held with the same lending institution, the realized portion of the interest rate financial derivative instrument is recorded as financing expense.

During the three months ended June 30, 2020, the Company incurred a realized loss on interest rate financial derivative instruments of $0.2 million compared to $nil during the three months ended June 30, 2019.

During the six months ended June 30, 2020, the Company incurred a realized loss on interest rate financial derivative instruments of $0.9 million compared to $nil during the six months ended June 30, 2019.

The realized losses in the current periods was due to settlements of the interest rate swap contract while there were no realized portions in the comparative periods for 2019.

During the three months ended June 30, 2020, the Company incurred an unrealized loss on interest rate financial derivative instruments of $0.3 million compared to an unrealized gain of $0.2 million during the three months ended June 30, 2019.

During the six months ended June 30, 2020, the Company incurred an unrealized loss on interest rate financial derivative instruments of $1.0 million compared to an unrealized loss of $0.2 million during the six months ended June 30, 2019.

The unrealized losses during the three and six months ended June 30, 2020 was due to interest rate curves dropping partially offset by settlements. In the comparative periods for 2019 there were relatively minor movements in the mark-to-market value of this contract.

General and Administrative (“G&A”) Expenses

	Three months ended	Six months ended
	June 30, June 30,
($ thousands, exceptper boe amounts)	2020 2019	2020 2019
Gross G&A expenses Capitalized G&A Overhead recoveries G&A expenses Per boe	$ $ $ $ 2,090 3,420 5,014 6,590 (479) (928) (1,327) (1,785) (185) (5) (484) (32)
	1,426 2,487 3,203 4,773 0.93 19.42 1.14 33.67

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 three and six months ended June 30, 2020, Pipestone Energy capitalized 23 percent and 26 percent of gross G&A expenses, respectively, compared to 27 percent in the prior periods for 2019. The Company capitalized less G&A in the current quarter due to its reduced capital program.

In light of the low commodity price environment caused by COVID-19 demand shock and global production supply issues the Company implemented G&A cost saving measures to protect its cash flows and liquidity during these adverse operating conditions. As a result, the Company expects it will lower its 2020 annual gross G&A expenses, before capitalization and overhead recoveries, from an original 2020 budget of $13 million to a revised forecast total of approximately $10 million. This translates to an expected annual reduction of 23%. Actual gross G&A expenses in the current quarter have continued to trend in-line with the revised forecast.

During the current quarter the Government of Canada announced and implemented the Canada Emergency Wage Subsidy (“CEWS”). The CEWS is a program designed to aid employers who have experienced significant declines in their revenues as a direct result of COVID-19’s impact on the economy

14 | P a g e

but have continued to maintain their employees on payroll. During the quarter, the government provided eligible employers with a subsidy equal to 75% of the amount of remuneration paid to the employees over the qualifying period(s), capped at a maximum benefit of $847 per week per employee. Pipestone Energy applied for and received $0.3 million in relief from the CEWS program in the current quarter which has been netted against gross G&A expenses. Pipestone Energy expects to continue to qualify for the CEWS program at similar subsidy levels throughout the currently announced extension through December 2020.

During the three months ended June 30, 2020, the Company’s gross G&A expenses were $2.1 million compared to $3.4 million for the three months ended June 30, 2019, representing a decrease of $1.3 million or 39 percent for the period.

During the six months ended June 30, 2020, the Company’s gross G&A expenses were $5.0 million compared to $6.6 million for the six months ended June 30, 2019, representing a decrease of $1.6 million or 24 percent year-to-date.

G&A expenses were lower than in the comparative periods of 2019 predominantly due to cost saving efforts put in place, government wage subsidies received and changes in the corporate office structure.

Transaction Expenses

Three months ended	Six months ended
June 30, June 30,
2020 2019	2020 2019
$ $ $ $ Transaction_($ thousands) -275 -4,246 Per boe($)_ - 2.15 - 29.96

During the three and six months ended June 30, 2020, the Company incurred $nil on transaction expenses compared to $0.3 million and $4.2 million during the three and six months ended June 30, 2019, respectively. The decrease was due to the Company not having any corporate transactions occur in 2020.

In 2019 transaction expenses were incurred through services related to the Corporate Acquisition of Blackbird Energy Inc., which closed January 4, 2019. These included fees for financial advisors, legal consultations, due diligence and reservoir engineers. In aggregate over 2018 and 2019 the Company incurred a total of $6.8 million in transaction expenses related to the Corporate Acquisition.

Share-based compensation

Three months ended	Six months ended
June 30, June 30,
2020 2019	2020 2019
$ $ $ $ Share-based compensation_($ thousands) 569 78 1,022 78 Per boe($)_ 0.37 0.61 0.36 0.55

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 and six months ended June 30, 2020, the Company incurred share-based compensation of $0.6 million and $1.0 million, respectively, compared to $0.1 million for the comparative periods in 2019. The increase from the comparative periods was due to the Company only having implemented its long-term incentive plan in the latter part of the second quarter of 2019 with minimal expense recognized.

15 | P a g e

Exploration and Evaluation (“E&E”) Expenses

Three months ended	Six months ended
June 30, June 30,
2020 2019	2020 2019
$ $ $ $ E&E_($ thousands) 414 - 414 - Per boe($)_ 0.27 - 0.15 -

During the three and six months ended June 30, 2020, the Company incurred E&E expenses of $0.4 million compared to $nil for the comparative periods in 2019. The expense recognized was due to the mineral rights expiry on a single section of undeveloped land that occurred in April 2020. This section of undeveloped land was related to the Corporate Acquisition.

During the quarter, in recognition of the multiple challenges facing the oil and gas sector, Alberta Energy began to offer one-year extensions for petroleum and natural gas agreements expiring from March 20, 2020 up to and including March 31, 2021. Pipestone Energy has submitted its applications and extended its mineral rights on 8 sections of land in the Pipestone area with expiries from this period to take advantage of the program. The Company expected to continue most of these licenses through normal course operations prior to the relief program being announced. As a result, the Company has no mineral rights expiries set to occur in the second half of 2020 and Q1 2021.

Depletion and Depreciation (“D&D”) Expenses

Three months ended	Six months ended
June 30, June 30,
2020 2019	2020 2019
$ $ $ $ Depletion_($ thousands) 13,702 1,376 24,949 1,516 Per boe($)_ 8.98 10.74 8.89 10.70
Depreciation – ROU lease assets_($ _thousands) 1,497 143 3,013 239 Per boe_($)_ 0.98 1.12 1.07 1.69
Depreciation – Corporate assets_($ _thousands) 20 19 42 24 Per boe_($)_ 0.01 0.15 0.02 0.17
Total D&D expenses_($ thousands) 15,219 1,538 28,004 1,779 Per boe($)_ 9.97 12.01 9.98 12.55

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 during the three and six months ended June 30, 2020 are $1.1 billion.

D&D expenses also include depreciation of the Company’s ROU assets on a straight-line basis over the shorter of the estimated useful life or the lease term.

During the three months ended June 30, 2020, the Company incurred D&D expenses of $15.2 million compared to $1.5 million for the comparative period in 2019.

16 | P a g e

During the six months ended June 30, 2020, the Company incurred D&D expenses of $28.0 million compared to $1.8 million for the comparative period in 2019.

The increase in 2020 was due to the Company having production on-stream from its wells located north of the Wapiti River partially offset by a lower depletion rate per boe due to reduced future development costs associated with the Company’s reserves. In the comparative periods for 2019 the Company only had minor production volumes from its southern legacy wells acquired as part of the Corporate Acquisition.

The Company’s depreciation on ROU lease assets also increased in 2020 from the comparative periods as a result of a significant compressor lease which commenced in late 2019.

Financing Expense

	Three months ended June 30,	Six months ended
		June 30,
($ thousands, exceptper boe amounts)	2020 2019	2020 2019
Letter of credit fees Interest on bank debt Bank charges Foreign exchange (gain) loss on U.S. denominated debt Realized loss (gain) on cross-currency swaps Lease liabilities interest expense Cash financing expense Accretion on decommissioning provisions Amortization of bank debt issuance costs Non-cash financing expense Total financing expense Cash financing expense, per boe Non-cash financingexpense, per boe	$ $ 37 394 1,400 2,036 111 - (4,197) - 4,197 - 1,572 38	$ $ 147 1,039 2,997 3,458 113 20 1,609 - (1,609) - 3,181 52
	3,120 2,468	6,438 4,569
	22 27 32 557	51 55 32 895
	54 584	83 950
	3,174 3,052 2.04 19.27 0.04 4.57	6,521 5,519 2.29 32.24 0.03 6.70

During the three months ended June 30, 2020, the Company incurred total financing expenses of $3.2 million compared to $3.1 million for the comparative period in 2019.

During the six months ended June 30, 2020, the Company incurred total financing expenses of $6.5 million compared to $5.5 million for the comparative period in 2019.

These increases were due to additional indebtedness in 2020, partially offset by lower borrowing rates, and additional lease interest expense resulting from leases that commenced in late 2019.

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

For the three and six months ended June 30, 2020, the Company drew from its credit facility in U.S. dollars, as permitted under the credit facility, which when repaid created a foreign exchange (gain) loss due to fluctuations in the value of the Canadian dollar over the same periods. Concurrent with the draw of U.S. dollar denominated borrowings, the Company entered into cross-currency swaps to manage the foreign currency risk resulting from holding U.S. dollar denominated borrowings. This transaction allows the

17 | P a g e

Company to take advantage of the interest rate spread between CDOR and LIBOR without being exposed to any foreign exchange risk.

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 remained relatively consistent from the 2019 comparative periods as a result of the Company having a similar decommissioning provision balance.

Amortization of financing costs relate to the bank due diligence fees related to Pipestone Energy’s bank debt and the initial mark-to-market value of the associated interest rate swaps entered in 2019.

Financing Income

Three months ended	Six months ended
June 30, June 30,
2020 2019	2020 2019
$ $ $ $ Financing income_($ thousands) 14 250 187 564 Per boe($)_ 0.01 1.95 0.07 3.98

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

During the three months ended June 30, 2020, the Company earned financing income of $14 thousand compared to $0.3 million for the comparative period in 2019.

During the six months ended June 30, 2020, the Company earned financing income of $0.2 million compared to $0.6 million for the comparative period in 2019.

Financing income was lower in 2020 than in 2019, due to lower bank balances maintained throughout the periods.

Income Tax

For the three and six months ended June 30, 2020, the Company had a deferred income tax recovery of $5.6 million and $1.0 million, respectively, compared to a deferred income tax recovery of $1.1 million and $7.1 million for the three and six months ended June 30, 2019, respectively. The deferred income tax recoveries in the current periods were a result of the losses before income taxes incurred. The deferred income tax recoveries in the 2019 comparative periods were primarily a result of reductions to the Alberta corporate income tax rate combined with the recognition of a previously unrecognized deferred tax asset.

Pipestone Energy’s consolidated tax pools are estimated as summarized in the table below:

$ thousands	As at June 30, 2020 As at December 31, 2019
Canadian oil and gas property expense Canadian development expense Canadian exploration expense Non-capital losses Undepreciated capital cost (“UCC”) pools(1) Debt and share issuance costs	$ $ 30,431 31,667 127,461 118,410 48,280 46,165 256,205 235,957 75,959 75,398 1,377 3,897
	539,713 511,494

(1) Substantially all the Company’s UCC pools relate to Class 41 assets, which are deductible at a rate of 25 percent per year.

The above tax pools include non-capital losses that expire in 2024 through 2038.

18 | P a g e

Income (Loss)

For the three and six months ended June 30, 2020, the Company had a loss of $19.5 million ($0.10 per share basic and diluted) and $3.9 million ($0.02 per share basic and diluted), respectively, compared to income of $4.9 million ($0.03 per share basic and diluted) and $0.6 million ($0.00 per share basic and diluted) for the three and six months ended June 30, 2019, respectively. The losses in the current periods were primarily a result of reduced revenues due to the low commodity price environment, partially offset by realized hedging gains, combined with fluctuations in the unrealized gains (losses) on commodity financial derivative instruments. The income in the 2019 prior periods was primarily a result of stronger commodity pricing combined with deferred income tax recoveries recognized.

Liability Management Rating (“LMR”) and Decommissioning Provisions

At June 30, 2020, Pipestone Energy’s Alberta LMR rating was positive 33.0. At June 30, 2020, the Company’s total decommissioning provision was $7.5 million or 1.4 percent of its total property and equipment balance. Pipestone Energy believes it is well positioned with respect to its long-term abandonment and reclamation obligations, the majority of which are expected to be incurred between the year 2045 and 2055.

19 | P a g e

Supplemental Information

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

Netback Analysis

Three months ended	Six months ended
June 30, June 30,
2020 2019	2020 2019
$ $ $ $ Average sales price of liquids and natural gas 17.28 42.62 20.81 41.75 Royalties 0.28 (2.15) (0.37) (2.11) Operating expense (10.64) (13.83) (11.00) (15.26) Transportation expense (3.32) (5.72) (3.47) (9.85)
Operating netback(1) 3.60 20.92 5.97 14.53 G&A expense (0.93) (19.42) (1.14) (33.67) Transaction costs - (2.15) - (29.96) Realized gain (loss) on commodity financial derivative instruments 6.85 (0.96) 5.92 (0.86) Realized loss on interest rate financial derivative instruments (0.12) - (0.31) - Financing income 0.01 1.95 0.07 3.98 Financingexpense – cash (2.04) (19.27) (2.29) (32.24)
Adjusted funds flow netback(1) 7.37 (18.93) 8.22 (78.22) Financing expense – non-cash (0.04) (4.57) (0.03) (6.70) D&D expense (9.97) (12.01) (9.98) (12.55) E&E expense (0.27) - (0.15) - Share-based compensation (0.37) (0.61) (0.36) (0.55) Unrealized gain (loss) on interest rate financial derivative instruments (0.18) 1.45 (0.36) (1.45) Unrealized gain (loss) on commodity financial derivative instruments (12.99) 64.29 0.91 53.32 Deferred income tax recovery 3.70 8.40 0.35 50.15
Income(loss) per boe (12.75) 38.02 (1.40) 4.00
(1) See “Non-GAAP measures”.

The operating netbacks per boe declined in the current periods due primarily to extremely weak commodity pricing experienced in Q2 2020. The adjusted funds flow per boe increased in the current periods as a result of realized hedging gains, which protected against commodity price fluctuations, as well as generally reduced cash expenses on a per boe basis as a result of the increased production base from Pipestone Energy’s northern wells. Losses per boe in 2020 were mainly due to fluctuations in unrealized gains (losses) on commodity financial derivative instruments. Costs in the above table for the 2019 periods were abnormally high due to the Company’s early stage of development at the time and having a number of fixed costs spread over limited production volumes, as described elsewhere in this MD&A.

20 | P a g e

Selected Quarterly Information

Three months ended	June 30,	March 31,	Dec. 31,	Sept. 30,	June 30,	March 31,	Dec. 31,	Sept. 30,
	2020	2020	2019	2019	2019	2019	2018(2)(4)	2018(2) (4)
Financial
($ thousands, except per share amounts
and share numbers)
Sales of liquids and natural gas	26,380	32,017	48,796	7,808	5,917	460	59	-
Cash from (used in) operating
activities	(175)	31,067	30,750	(6,626)	(777)	(12,785)	(3,490)	(361)
Adjusted funds flow from (used
in) operations	11,231	11,820	16,608	(2,734)	(2,423)	(8,663)	(8,260)	(512)
Per share,
basic and diluted_($)_(1)	0.06	0.06	0.09	(0.01)	(0.01)	(0.05)	(0.14)	(0.01)
Income (loss)	(19,486)	15,541	(13,143)	(1,409)	4,869	(4,302)	(9,603)	(1,349)
Per share,
basic and diluted_($)_(1)	(0.10)	0.08	(0.07)	(0.01)	0.03	(0.02)	(0.16)	(0.03)
Capital expenditures	19,893	29,154	36,457	29,434	46,835	49,468	60,252	5,428
Total assets_(end of quarter)_	652,798	663,140	663,816	607,287	579,297	531,994	216,300	147,240
Working capital (deficit)(end of
quarter)	(16,781)	(7,103)	(12,015)	20,893	(8,026)	2,411	(20,180)	10,332
Bank debt_(end of quarter)_	183,248	163,000	163,048	156,983	115,754	80,735	53,436	52,187
Shareholders’ equity_(end of_
quarter)	367,298	386,147	370,075	382,867	383,843	378,896	114,058	85,661
Weighted-average basic shares
outstanding_(000s)_(1)	190,136	189,820	189,743	189,627	187,096	184,540	60,707	52,782
Weighted-average diluted shares
outstanding_(000s)_(1)	190,253	189,942	189,777	189,627	187,116	184,540	60,707	52,782
Operations
Total production_(boe/d)_	16,772	14,066	14,885	2,467	1,407	152	73	-
Condensate and crude oil_(% of_
total production)	29	29	36	45	42	54	100	-
Total liquids_(% of total production)_	43	38	43	51	49	65	100	-
Average realized price_(per boe)_	17.28	25.01	35.63	34.40	42.62	33.53	8.60	-
Operating netback_(per boe)_(3)	3.60	8.79	17.26	11.61	20.92	(45.09)	(6.93)	-
Adjusted funds flow netback_(per_
boe) (3)	7.37	9.24	12.13	(12.04)	(18.93)	(631.58)	(1,221.29)	-

(1) The number of common shares has been adjusted retrospectively to reflect the 10:1 share consolidation, as well as the 0.5996 exchange ratio, as part of the Corporate Acquisition that closed on January 4, 2019.

(2) IFRS 16, Leases , was adopted January 1, 2019 using the modified retrospective approach; therefore, 2018 comparative information was not restated. See “Critical Accounting Judgments, Estimates and Policies”.

(3) See “Non-GAAP measures”.

(4) The comparative figures presented for 2018 are that of the predecessor company, Predecessor Pipestone.

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 financial instruments, changes in per-unit expenses, and deferred income taxes. Please refer to “Financial and Operating Results” above for an explanation of changes.

Share Capital

As at the date of this MD&A, the Company had 190.5 million common shares, 17.5 million warrants, 1.9 million stock options, 1.9 million PSUs and 2.0 million RSUs outstanding. The warrants and any stock options related to the Corporate Acquisition are presented post the 10:1 share consolidation.

21 | P a g e

Related Party Transactions

During the three and six months ended June 30, 2020, Pipestone Energy incurred $Nil of general and administrative expenses from CNOR LP for management and related services as the Services Agreement between Pipestone Energy and CNOR LP expired on December 31, 2019 (three and six months ended June 30, 2019 - $1.5 million and $3.0 million, respectively). At June 30, 2020, $2.3 million (December 31, 2019 –$3.0 million) was included in accrued liabilities. All related-party transactions are recorded at the exchange amount. At June 30, 2020, CNOR LP held approximately 55 percent of Pipestone Energy’s issued and outstanding common shares.

Liquidity and Capital Resources

At June 30, 2020, the Company had an adjusted working capital deficit of $13.4 million (June 30, 2019 – adjusted working capital deficit of $9.3 million), excluding the interest rate and commodity financial derivative instrument liabilities, as well as lease liabilities. Adjusted funds flow from operations for the three and six months ended June 30, 2020 was $11.2 million and $23.1 million, respectively.

Available Funding

	As at June 30,
($ thousands)	2020 2019
Current assets Current liabilities Working capital deficit Less: current asset commodity financial derivative instruments Plus: current liability commodity financial derivative instruments Plus: current liability interest rate financial derivative instruments Plus: current lease liabilities Adjusted working capital deficit_(1) Plus: Credit Facility capacity(2)_	$ $ 20,793 49,777 (37,574) (57,803)
	(16,781) (8,026)
	(1,469) (4,105) 53 - 838 2,286 3,924 515
	(13,435) (9,330) 26,856 55,363
Available funding_(1)_	13,421 46,033

(1) See “Non-GAAP measures”.

(2) As at June 30, 2020, Pipestone Energy has a $125.0 million Senior Facility, which is reduced by $125.0 million of principal drawn, and a $70.0 million Additional Facility, which is reduced by $48.0 million of principal drawn. At June 30, 2020, the Company also has a $30.0 million Operating Line, which is reduced by $10.9 million of principal drawn and $14.3 million in outstanding letters of credit issued, which reduce the available funding on the Operating Line. Subsequent to June 30, 2020, the Company secured a $15.0 million letter of credit facility and transferred the $14.3 million of letters of credit outstanding to the new facility. This provides the Company with an additional $14.3 million of credit facility capacity and available funding.

22 | P a g e

Bank Debt

Six months ended June 30, Balance, beginning of year Increase in borrowing Debt issuance costs, cash Amortization of debt issuance costs Balance, end of period Current portion Long-term portion	2020
	$ 163,048 20,844 (676) 32
	183,248
	- 183,248

On June 12, 2020, Pipestone Energy completed its spring redetermination and maintained 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 an amendment to the RBL, the Company is restricted from spending more than $65.0 million of capital in 2020 without unanimous consent from its banking syndicate. This provision is a temporary amendment, which will terminate at the next redetermination scheduled for November 2020. Refer to the “Financing” heading above for contingent updates that may subsequently alter these terms.

At June 30, 2020, the Company had $125.0 million drawn against the Senior Facility (December 31, 2019 - $150.0 million), $48.0 million drawn against the Additional Facility (December 31, 2019 – no Additional Facility) and $10.9 million drawn on the Operating Line (December 31, 2019 - $13.0 million). In addition to the balance of $183.9 million, the Company had $14.3 million in outstanding letters of credit issued against its Operating Line which reduces the available funding on the Operating Line (December 31, 2019 - $14.1 million). See the “Letter of Credit Facility” heading above for details of a letter of credit facility that the Company closed on July 16, 2020, which provides additional available funding and liquidity through EDC guaranteeing these letters of credit subsequent to June 30, 2020.

DC guaranteeing these letters of credit subsequent to June 30, 2020.
As at June 30, RBL – portion drawn Unamortized debt issuance costs Balance, end of period	2020
	$ 183,892 (644)
	183,248

The borrowing base on the facility will be redetermined bi-annually in the spring and fall each year (pending successful closing of the Financing the 2020 fall redetermination will be foregone), subject to amendments, and is based on the lenders' assessment of our reserves and future commodity prices. If not extended by any or all lenders, the commitments of such non-extending lenders under the RBL will cease to revolve, all outstanding advances thereunder owing to such non-extending lenders will become repayable in one year from the term date and the margins owing on such outstanding advances will increase by 0.50%. In the event the borrowing base is reduced below amounts outstanding, any excess will become due and payable 60 days subsequently. Borrowing base redetermination will also be required if the Company’s Liability Management Rating or equivalent measurement falls below 2.00 in any material jurisdiction where Pipestone Energy operates.

Advances under the RBL are available by way of Canadian prime rate, and U.S. base rate loans with interest rates ranging between 2.00 percent and 6.00 percent, on the Senior Facility and Operating Line, and 4.00

23 | P a g e

percent and 8.00 percent, on the Additional Facility, over the bank's prime lending rate, as well as bankers' acceptances and London Inter-bank Offered Rate (LIBOR) loans, which are subject to stamping fees and margins ranging from 3.00 percent to 7.00 percent, on the Senior Facility and Operating Line, and 5.00 percent to 9.00 percent, on the Additional Facility, depending upon our senior debt to Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) ratio calculated at our previous quarter end. LIBOR loans bear a premium of an additional 0.25 percent. Given the start-up nature of Pipestone Energy’s operations in 2020, for purposes of calculating EBITDA, the credit agreement allows for annualized EBITDA calculations for the first three quarters of 2020.

As at June 30, 2020, Pipestone Energy’s applicable pricing included a 3.25 percent to 5.25 percent per annum margin on prime loans, a 4.25 percent to 6.25 percent per annum stamping fee and margin on bankers' acceptances and LIBOR loans along with a 0.45 percent per annum standby fee on the portion of the RBL that is not drawn. Borrowing margins and fees are reviewed annually as part of the bank syndicate's annual renewal. For the three and six months ended June 30, 2020, borrowing costs averaged 3.5 percent and 3.8 percent, respectively (three and six months ended June 30, 2019 – 8.8 percent and 8.3 percent, respectively).

The credit agreement contains customary borrowing base provisions and negative covenants including, but not limited to, restrictions on our ability to incur indebtedness, grant liens or security interests on assets, sell or otherwise transfer assets, make distributions, make investments or provide financial assistance and our ability to merge and consolidate with other companies or change our line of business, in each case, subject to certain exceptions.

The credit agreement contains customary positive covenants including, but not limited to, delivery of financial and other information to the lenders, maintenance of existence, payment of taxes and other claims, maintenance of properties and insurance, access to books and records by the lenders, compliance with applicable laws and regulations, including environmental laws, and further assurances and provision of additional collateral and guarantees.

The credit agreement provides that, upon the occurrence of certain events of default, our obligations thereunder may be accelerated and the lending commitments terminated. Such events of default include payment defaults to the lenders, covenant defaults, inaccuracies of representations and warranties, bankruptcy and insolvency proceedings, business suspension, material money judgments, cross defaults, change of control and other customary events of default. As is customary, the facility contains material adverse change clauses which would enable the lenders to demand immediate repayment of amounts outstanding if determined to represent an event of default.

The indebtedness under the credit agreement is secured by floating charges and a security interest against our current and future real and personal property. The Company does not currently have any material subsidiaries and, as such, no guarantees have been provided under the credit agreement.

The revolving period of the RBL currently ends on November 30, 2020 with an additional one-year term out period thereafter if the revolving period is not extended. An extension of the revolving period is subject to majority lender consent. As noted above, subject to the shareholder vote and closing of the Financing, the Company has re-confirmed and executed an amendment to its $225.0 million RBL with its corporate banking syndicate. In light of the significant capital injection, the banking syndicate will forgo the normal fall borrowing base review with the next redetermination, scheduled for May 2021. In addition, the previously imposed capital spending restrictions from the June 2020 re-determination will be removed, and the Company has agreed to implement a robust hedging program with respect to

24 | P a g e

expected condensate volumes through calendar 2021.

Capital Management

In response to the current commodity price weakness which has been exacerbated by the COVID-19 pandemic slowing the world economy and OPEC’s failure to reach an agreement on meaningful production cuts, the Company has responded by significantly reducing its currently planned capital expenditures for the remainder of 2020 to prudently manage its debt.

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 future high-return development growth. Near-term development activities as noted above have been suspended and future expenditures are anticipated to be funded by the Company's adjusted funds flow from operations and draws under the credit facilities.

Refer to the “Financing” heading above for an additional source of funding the Company expects to receive in 2020 as well as the “Letter of Credit Facility” heading for details of a letter of credit facility that the Company closed on July 16, 2020, which provides additional available funding subsequent to June 30, 2020.

Pipestone Energy manages its liquidity risk through its capital structure, cash flow forecasting and available credit.

The Company has significant financial liabilities and commitments over the next one to two years. The Company believes in the short term that its financial requirements will be addressed through its current and future lending arrangements which were significantly enhanced by the Letter of Credit Facility and the RBL amendments and upon successful closing of the Financing an increase in expected future operating cash flows from production.

While the Company believes it will be successful in meeting its liquidity requirements, significant uncertainty exists due to the adverse impacts that the COVID-19 pandemic has had on the state of the global economy, the resulting weakness in commodity prices from COVID-19’s demand destruction as well as global oversupply of crude oil; future reserve and production risks; and despite the expected successful closing of the Financing, 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 into as part of its normal operations at June 30, 2020:

($Thousands)	2020 2021 2022 2023 2024 Thereafter
Gathering commitments Processing commitments Transportation commitments Total payments	$ $ $ $ $ $ 5,564 12,055 12,134 12,134 12,140 60,008 10,420 25,938 30,265 30,265 30,348 146,349 8,509 16,355 16,965 16,965 17,011 99,375
	24,493 54,348 59,364 59,364 59,499 305,732

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

25 | P a g e

of Financial Statements .

The following table details the undiscounted cash flows and contractual maturities of Pipestone Energy’s lease liabilities, as at June 30, 2020:

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	June 30, 2020
	$ 9,936 9,704 9,292 9,292 9,121 38,489
	85,834 (33,630)
	52,204

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, 2019 annual consolidated financial statements and in notes 2 and 3 to the June 30, 2020 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.

New accounting standards

IFRS 3, Business Combinations

The following amendment as issued by the IASB has been early adopted, as permitted, by the Company effective January 1, 2019. IFRS 3, Business Combinations, sets out the principles in accounting for the acquisition of a business. The amendments to this standard include a change in the definition of a business and the addition of an optional concentration test to determine if the acquisition is a business.

The definition of a business under the amendment to IFRS 3 is now that a business consists of inputs and processes applied to those inputs that have the ability to contribute to the creation of outputs. The three elements of a business are defined as follows:

26 | P a g e

• Input: any economic resource that creates outputs, or has the ability to contribute to the creation of outputs, when one or more processes are applied to it.

• Process: Any system, standard, protocol, convention or rule that, when applied to an input or inputs, creates outputs or has the ability to contribute to the creation of outputs.

• Output: The result of inputs and processes applied to those inputs that provide goods or services to customers, generate investment income or generate other income from ordinary activities.

The optional concentration test permits a simplified assessment of whether an acquired set of activities and assets is in fact a business. An entity may elect to apply, or not apply, the test separately for each transaction or other event. The concentration test is met if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets. If the concentration test is met, the set of activities and assets is determined not to be a business and no further assessment is needed.

Non-GAAP financial measures and additional subtotals in financial statements

Additional subtotal – 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	Six months ended
June 30, June 30,
($ thousands) 2020 2019	2020 2019
$ $ $ $ Cash from (used in) operating activities (175) (777) 30,892 (13,562) Changes in non-cash working capital 11,404 (1,646) (7,859) 2,476 Decommissioning provision costs incurred 2 - 18 -
Adjusted funds flow from (used in) operations 11,231 (2,423) 23,051 (11,086)

Adjusted funds flow from operations was included in the consolidated statement of cash flow in order to provide users with a better understanding of the key metrics utilized by Pipestone Energy to assess performance and how the calculation was arrived at. Accordingly, adjusted funds flow performance measures are not presented as non-GAAP measures in this MD&A.

Non-GAAP measures

This MD&A includes references to financial measures commonly used in the oil and natural gas industry. The terms “operating netback”, “adjusted funds flow netback”, “available funding”, “adjusted working capital”, “free cash flow”, “net debt”, “CROIC”, “ROCE”, and “capital expenditures and acquisitions”, “capital expenditures, acquisitions and right-of-use lease asset additions” are not defined under IFRS, which have been incorporated into Canadian GAAP, as set out in Part 1 of the Chartered Professional

27 | P a g e

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.

Operating netback and adjusted funds flow netback

Operating netback is calculated on a per-unit-of-production basis and is determined by deducting royalties, operating and transportation expenses from liquids and natural gas sales.

Adjusted funds flow netback reflects adjusted funds flow on a per-unit-of-production basis and is determined by dividing adjusted funds flow 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 financial derivative instruments on a per-unitof-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.

Free Cash Flow

“Free cash flow” should not be considered an alternative to, or more meaningful than, cash flow – 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 – operating activities plus change in noncash working capital less capital expenditures.

Net debt

Net debt is a non-GAAP measure that equals total debt outstanding + negative working capital – cash and cash equivalents and includes transaction costs and the proceeds from the completed debt & equity financings. Total debt is calculated as long-term debt, long-term debt due within one year and short-term debt. Net debt is considered to be a useful measure in assisting management and investors to evaluate Pipestone Energy’s financial strength.

CROIC and ROCE

Adjusted EBITDA is calculated as profit or loss before interest, income taxes, depletion, depreciation and amortization, adjusted for certain non-cash and extraordinary items primarily relating to unrealized gains and losses on financial instruments. 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 for the ROCE calculation, net assets are defined as total assets on the Company’s consolidated

28 | P a g e

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 and six months ended June 30, 2020 and balances as at June 30, 2020 as follows:

($ thousands)	Three months ended June 30, 2020
Net loss and comprehensive loss	19,486
Deferred income tax recovery	5,643
Financing expense	(3,174)
Financing income	14
Unrealized loss on interest rate risk management	(273)
Realized loss on interest rate risk management	(188)
D&D expense	(15,219)
E&E expense	(414)
Share-based compensation	(569)
Unrealized loss on commodityrisk management	(19,831)
Adjusted EBITDA	14,525
Annualized Adjusted EBITDA(annualized factor 4x)	58,100

($ thousands)	Six months ended June 30, 2020
Net loss and comprehensive loss	3,945
Deferred income tax recovery	986
Financing expense	(6,521)
Financing income	187
Unrealized loss on interest rate risk management	(1,007)
Realized loss on interest rate risk management	(856)
D&D expense	(28,004)
E&E expense	(414)
Share-based compensation	(1,022)
Unrealizedgain on commodityrisk management	2,548
Adjusted EBITDA	30,158
Annualized Adjusted EBITDA(annualized factor 2x)	60,316

29 | P a g e

($ thousands)	As at June 30, 2020
Exploration and evaluation (E&E) assets – gross carrying value	38,982
Property and equipment (P&E) – net carrying value	542,441
P&E – accumulated D&D	42,047
E&E assets and P&E – gross carrying value	623,470
ROU assets – net carrying value	50,255
ROU assets – accumulated depreciation	4,544
E&E,P&E and ROU assets –gross carryingvalue	678,269
Annualized CROIC(three months ended June 30, 2020)	8.6%
Annualized CROIC(six months ended June 30, 2020)	8.9%

($ thousands)	Three months ended June 30, 2020
Adjusted EBITDA	14,525
D&D expense	(15,219)
Adjusted EBIT	(694)
Annualized Adjusted EBIT(annualized factor 4x)	(2,776)

($ thousands)	Six months ended June 30, 2020
Adjusted EBITDA	30,158
D&D expense	(28,004)
Adjusted EBIT	2,154
Annualized Adjusted EBIT(annualized factor 2x)	4,308

($ thousands)	As at June 30, 2020
Total assets	652,798
Total current liabilities	37,574
Net assets	615,224
Annualized ROCE(three months ended June 30, 2020)	(0.5%)
Annualized ROCE(six months ended June 30, 2020)	0.7%

30 | P a g e

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 financial derivative instruments 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.

Capital expenditures, acquisitions and right-of-use lease asset additions

Capital expenditures, acquisitions and right-of-use lease asset additions is used to reconcile the Company’s movement in its P&E, E&E asset and right-of-use lease asset balances during the period. Capital expenditures, acquisitions and right-of-use lease asset additions is calculated as capital expenditures and acquisitions plus any right-of-use lease asset additions and/or acquisitions, as disclosed in the right-of-use assets financial statement note.

Oil and Gas Measures

DCE&T

This document contains 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.

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 adversely impacted global commercial activity, including significantly reducing worldwide demand for crude oil. As a result of declining commodity prices and financial markets, the Company’s share price and market capitalization significantly declined from December 31, 2019.

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

31 | P a g e

a macro-scale and any new information that may emerge concerning the severity of the virus. These uncertainties may persist beyond when it is determined how to contain the virus or treat its impact. 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.

The acquisition, exploration and development of crude oil, condensate, other NGL and natural gas properties and the production, transportation and marketing of crude oil, condensate, other NGL and natural gas involves many other risks, which may influence the 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:

• The outcome of shareholder approval for the Financing to be voted on at the Company’s annual and special shareholder meeting on September 14, 2020;

• 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;

• Negative public perception of oil sands development, 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;

32 | P a g e

• 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;

• 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

33 | P a g e

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;

• 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 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.

34 | P a g e

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 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; estimated production growth; proposed development and drilling plans; use of proceeds from the Financing; increased capital guidance; plans for bringing on-stream Pipestone Energy’s 6-30 pad-site; plans for drilling and completion on Pipestone Energy’s 3-12 pad-site; plans to drill, complete and bring on-stream Pipestone Energy’s 8-15 pad-site; plans to bring 28-32 new wells into production in 2021; future capital spending; three year corporate growth trajectory; and plans to fill in-field infrastructure capacity and generate free cash flow; qualification for the CEWS program; and timing of abandonment and reclamation obligations.

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 and current oversupply of oil caused by OPEC; the ability to integrate Blackbird’s and Predecessor Pipestone’s historical businesses and operations and realize financial, operational and other synergies from the combination transaction completed on January 4, 2019; 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

35 | P a g e

regulatory approvals; the access, economic, regulatory and physical limitations 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; the ability to successfully integrate Blackbird’s and Predecessor Pipestone’s historical businesses and operations; 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 17, 2020, 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 our anticipate 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 forwardlooking 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

36 | P a g e

Other Abbreviations	Other Abbreviations
$000s	thousands of dollars
Adjusted	working capital (current assets less current liabilities), excluding financial derivative instruments and lease
workingcapital	liabilities
AECO	the AECO Hub, a natural gas storage facility located in Suffield and Countess, Alberta, part of the NOVA Pipeline
	System
Alliance Chicago	a market hub for natural gas transported on the Alliance Pipeline to be purchased and sold between entities
Exchange Hub
Alliance Pipeline	a naturalgaspipeline runningfrom northeastern British	Columbia to Illinois,in the United States
C$	Canadian dollars
Chicago City	Chicago Index Futures natural gas price
Gate
CNOR LP	Canadian Non-Operated Resources LP
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
XLE	extreme limited entry
YTD	year-to-date

37 | P a g e

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

Computershare Limited Calgary, Alberta

BANKERS

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

STOCK EXCHANGE LISTING

TSX Venture Exchange Symbol: PIPE

38 | P a g e