Pembina Pipeline Corp 6-K, filed Aug 5, 2021

Pembina Pipeline Corp (PBA)

6-K 2021-08-05 For: 2021-06-30

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Added on April 09, 2026

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Pembina Pipeline Corp filed this 6-K on August 5, 2021.

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		PEMBINA PIPELINE CORPORATION



Date:	August 5, 2021	By:	/s/ J. Scott Burrows
			Name: J. Scott Burrows
			Title: Senior Vice President and Chief Financial Officer


Exhibit Number						Document Description

99.1						Q2 2021 Management's Discussion and Analysis & Financial Statements
99.2						CEO Certificate
99.3						CFO Certificate


REPORT TO SHAREHOLDERS
Second Quarter 2021

MANAGEMENT'S DISCUSSION AND ANALYSIS


Table of Contents

1. About Pembina									2
2. Financial & Operating Overview									3
3. Segment Results									7
4. Liquidity & Capital Resources									19
5. Share Capital									23
6. Capital Investments									24
7. Selected Quarterly Information									25
8. Selected Equity Accounted Investee Information									27
9. Other									28
10. Accounting Policies & Estimates									29
11. Risk Factors									31
12. Non-GAAP Measures									32
13. Abbreviations									35
14. Forward-Looking Statements & Information									36


($ millions, except where noted)	2021	2020(3)	Change	% Change
Infrastructure and other services revenue	739	707	32	5
Product sales revenue	1,215	561	654	117
Total revenue	1,954	1,268	686	54
Net revenue(1)	894	776	118	15

Gross profit	550	460	90	20
Earnings	254	258	(4)	(2)
Earnings per common share – basic and diluted (dollars)	0.39	0.40	(0.01)	(3)

Cash flow from operating activities	584	642	(58)	(9)
Cash flow from operating activities per common share – basic (dollars)(1)	1.06	1.17	(0.11)	(9)
Adjusted cash flow from operating activities(1)	538	586	(48)	(8)
Adjusted cash flow from operating activities per common share – basic (dollars)(1)	0.98	1.07	(0.09)	(8)
Capital investments	146	211	(65)	(31)
Adjusted EBITDA(1)	778	789	(11)	(1)
Total volumes (mboe/d)(2)	3,500	3,427	73	2


Changes in Results for the Three Months Ended June 30
Infrastructure and other services revenue	▲	$32 million increase, due to assets placed into service in Facilities, higher interruptible volumes in Pipelines, combined with increased operating expense recoveries, partially offset by fully recovered capital fees at the Edmonton South Rail Terminal during the second quarter of 2020 and the impact of lower U.S. dollar exchange rates.
Product sales revenue	▲	$654 million increase ($69 million increase net of cost of goods sold), largely due to higher NGL and crude oil market prices, combined with higher marketed NGL volumes as sales have returned to pre-pandemic levels, partially offset by strong storage performance during the second quarter of 2020, compared to 2021 where storage is performing more consistently throughout the year.
Cost of goods sold	▼	$568 million increase, largely due to higher NGL and crude oil market prices, combined with higher marketed NGL volumes, as discussed above.
Operating expenses	▼	$32 million increase, largely due to additional assets being placed into service in Facilities, combined with a $27 million increase in power costs, of which $18 million were recovered in revenue, as a result of the higher power pool price during the second quarter of 2021.
Depreciation and amortization included in operations	▼	$15 million increase, primarily due to additional assets being placed into service during the second quarter of 2021.
Share of profit from equity accounted investees	▼	$14 million decrease, largely due to a lower contribution from Ruby, combined with the impact of lower U.S. dollar exchange rates, partially offset by increased share of profit from Aux Sable as a result of higher NGL margins and a wider AECO-Chicago natural gas price differential.
Realized loss (gain) on commodity-related derivatives	▼	$69 million negative variance, due to higher NGL and crude oil market prices during the second quarter of 2021, which also drove higher margins on NGL and crude sales, resulting in a realized loss on crude- and NGL-based derivative financial instruments for the period, compared to realized gains recognized during the second quarter of 2020. Pembina utilizes derivative instruments to stabilize the results of its marketing business.
Unrealized (gain) loss on commodity-related derivatives	▲	$102 million positive variance, primarily due to fewer contracts maturing in the period and an unrealized gain on an embedded derivative in Facilities partially offset by the increase in the forward prices for NGL and crude oil during the second quarter of 2021.
General & administrative	▼	$20 million increase largely due to higher long-term incentives driven by Pembina's increasing share price in the second quarter of 2021 compared to a decreasing share price in the second quarter of 2020, partially offset by a reduction in salaries and wages.
Other expense	▼	$45 million increase primarily due to lower income received in connection with the CEWS program during the second quarter of 2021 and an increase in acquisition related costs.

Net finance costs	▼	$24 million increase, primarily driven by losses on non-commodity-related derivative financial instruments compared to gains in the second quarter of 2020, combined with higher interest expense associated with higher average debt levels, partially offset by higher foreign exchange gains.



Cash flow from operating activities	▼	$58 million decrease, primarily driven by a $55 million increase in taxes paid as the tax installments for 2020 were deferred until the third quarter of 2020 as a result of the COVID-19 pandemic, $14 million increase in net interest paid, and a decrease in operating results after adjusting for non-cash items, partially offset by a $40 million change in non-cash working capital.
Adjusted cash flow from operating activities(1)	▼	$48 million decrease largely due to the same items impacting cash flow from operating activities, discussed above, net of the increase in taxes paid and change in non-cash working capital and an increase in accrued share based payment expense.
Adjusted EBITDA(1)	▼	$11 million decrease, largely due to an increase in realized loss on commodity-related derivatives, lower revenue at the Edmonton South Rail Terminal, the impact of lower U.S. dollar exchange rates, strong storage performance during the second quarter of 2020, combined with higher general and administrative expenses and higher power costs not recoverable in revenue, partially offset by higher margins on NGL and crude oil sales, the contributions from assets placed into service in Facilities, combined with higher interruptible volumes on the Peace Pipeline system. Included in adjusted EBITDA is $174 million (2020: $168 million) related to equity accounted investees.
Total volumes (mboe/d)(2)	▲	73 mboe/d increase, largely driven by higher interruptible volumes in Pipelines due to increased upstream activities. Revenue volumes include 321 mboe/d (2020: 323 mboe/d) related to equity accounted investees.


Changes in Results for the Six Months Ended June 30
Infrastructure and other services revenue	▲	$29 million increase in revenue due to assets placed into service in Facilities and higher interruptible volumes and cost recoveries in Pipelines, combined with higher supply volumes and operating expense recoveries at the Redwater Complex, partially offset by fully recovered capital fees at the Edmonton South Rail Terminal and the impact of lower U.S. dollar exchange rates.
Product sales revenue	▲	$1.0 billion increase ($203 million increase net of cost of goods sold), largely due to higher NGL and crude oil market prices, resulting in higher margins, combined with higher marketed NGL volumes as Pembina monetized a portion of its previously built up storage positions.
Cost of goods sold	▼	$808 million increase, largely due to higher NGL and crude oil market prices, combined with higher marketed NGL volumes as Pembina monetized a portion of previously built up storage positions.
Operating expenses	▼	$35 million increase, largely due to operating expenses associated with the additional assets being placed into service in Facilities, combined with a $40 million increase in power costs, of which $34 million were recovered in revenue, as a result of the higher power pool price during the first six months of 2021.
Depreciation and amortization included in operations	▼	$17 million increase, primarily due to additional assets being placed into service during the first six months of 2021.
Share of profit from equity accounted investees	▼	$27 million decrease, largely due to a lower contribution from Ruby, combined with the impact of lower U.S. dollar exchange rates, partially offset by higher NGL margins and a wider AECO-Chicago natural gas price differential at Aux Sable.
Realized loss (gain) on commodity-related derivatives	▼	$174 million negative variance, due to higher NGL and crude oil market prices during the period, which also drove higher margins on NGL and crude sales, resulting in a realized loss on NGL- and crude oil-based derivative instruments for the period, compared to realized gains recognized during the first six months of 2020. Pembina utilizes derivative instruments to stabilize the results of its marketing business.
Unrealized loss (gain) on commodity-related derivatives	▼	$12 million negative variance, primarily due to the recovery in the forward prices for NGL and crude oil during the first six months of 2021, partially offset by contracts maturing in the period and the increase in the the AECO price during the period resulting in gains for certain gas processing fees tied to AECO prices.
General & administrative	▼	$46 million increase largely due to higher long-term incentives driven by Pembina's increasing share price in the first six months of 2021, partially offset by a reduction in salaries and wages.
Other expense	▼	$32 million increase in part due to lower income associated with CEWS and transformation and restructuring related costs during the first six months of 2021.

Net finance costs	▲	$80 million decrease, primarily driven by foreign exchange gains in the period compared to foreign exchange losses in the first six months of 2020 as a result of hedge accounting adopted in the second quarter of 2020, combined with lower unrealized losses on U.S. dollar instruments and non-commodity related derivative financial instruments, partially offset by higher interest expense associated with higher average debt levels.
Current tax expense	▲	$29 million decrease, primarily due to lower taxable income in the first six months of 2021, combined with the reduction of the Alberta corporate tax rate from 10 to 8 percent effective July 2020.
Deferred tax expense	▲	$14 million decrease, largely due to the release of final U.S. tax regulations in 2020, combined with the recovery on the impairment expense.

Cash flow from operating activities	▼	$12 million decrease, primarily driven by a $24 million increase in net interest paid, combined with a $23 million decrease in payments collected through contract liabilities, and a $12 million decrease in distributions from equity accounted investees, partially offset by the increase in operating results after adjusting for non-cash items.
Adjusted cash flow from operating activities(1)	▼	$42 million decrease, largely due to the same factors impacting cash flow from operating activities, discussed above, combined with $45 million higher accrued share-based payments, partially offset by $29 million lower current tax expense.
Adjusted EBITDA(1)	●	Consistent with the prior period. Higher margins on NGL and crude oil sales, combined with new assets placed into service in Facilities and higher interruptible volumes on the Peace Pipeline system, were largely offset by an increase in realized loss on commodity-related derivatives, higher general and administrative expenses, discussed above, lower revenue at the Edmonton South Rail Terminal and the impact of lower U.S. dollar exchange rates. Included in adjusted EBITDA is $358 million (2020: $347 million) related to equity accounted investees.
Total volumes (mboe/d)(2)	▲	23 mboe/d increase, largely driven by higher interruptible volumes in Pipelines due to increased upstream activities and higher seasonal volumes on the Alliance Pipeline, combined with higher supply volumes at the Redwater Complex, partially offset by lower interruptible volumes on the Drayton Valley Pipeline. Revenue volumes include 328 mboe/d (2020: 311 mboe/d) related to equity accounted investees.











	3 Months Ended June 30					6 Months Ended June 30
	2021		2020			2021			2020
($ millions, except where noted)	Volumes(1)	Gross Profit	Adjusted EBITDA(2)	Volumes(1)	Gross Profit(4)	Adjusted EBITDA(2)	Volumes(1)	Gross Profit		Adjusted EBITDA(2)	Volumes(1)	Gross Profit(4)	Adjusted EBITDA(2)
Pipelines	2,627	341	522	2,555	379	540	2,607	700		1,051	2,592	778	1,090
Facilities	873	198	270	872	165	250	884	395		539	876	341	506
Marketing & New Ventures(3)	—	12	38	—	(85)	29	—	85		128	—	72	84
Corporate	—	(1)	(52)	—	1	(30)	—	—		(105)	—	2	(61)
Total	3,500	550	778	3,427	460	789	3,491	1,180		1,613	3,468	1,193	1,619


($ millions, except where noted)	2021	2020(4)	Change	% Change
Conventional revenue(1)	342	303	39	13
Transmission revenue(1)	110	104	6	6
Oil Sands revenue(1)	102	121	(19)	(16)
Pipelines revenue(1)	554	528	26	5
Operating expenses(1)	132	107	25	23
Share of profit from equity accounted investees	27	58	(31)	(53)
Depreciation and amortization included in operations	108	100	8	8
Gross profit	341	379	(38)	(10)
Adjusted EBITDA(2)	522	540	(18)	(3)
Volumes (mboe/d)(3)	2,627	2,555	72	3
Distributions from equity accounted investees	60	87	(27)	(31)


Change in Results
Conventional revenue(1)	▲	Increase largely due to higher interruptible volumes on the Peace Pipeline system as higher crude oil and NGL market prices have resulted in increased upstream activities, combined with higher recoverable costs.
Transmission revenue(1)	●	Consistent with the prior period. Increased interruptible volumes on the Cochin Pipeline, were offset by lower interruptible volumes on the Vantage Pipeline as market conditions exist for end users to source their supply from the Redwater Complex, combined with the impact of lower U.S. dollar exchange rates.
Oil Sands revenue(1)	▼	Decrease largely due to a $11 million adjustment associated with the Edmonton South Rail Terminal during the second quarter of 2020 as Pembina continued to finalize the identification of lessor leases acquired as part of the Kinder Acquisition, combined with lower capital recoveries.
Operating expenses(1)	▼	Increase largely due to a $17 million increase in power costs, of which $9 million was recovered in revenue, as a result of the higher power pool price during the second quarter of 2021, combined with increased integrity spending.
Share of profit from equity accounted investees	▼	Decrease largely due to lower contribution from Ruby as the owners have agreed to defer distributions for the second quarter of 2021, combined with the impact of lower U.S. dollar exchange rates.

Distributions from equity accounted investees	▼	$60 million (2020: $57 million) from Alliance and no distributions (2020: $30 million) from Ruby. The reduction in distributions from Ruby is due to the same factors impacting share of profit from equity accounted investees discussed above.
Volumes (mboe/d)(3)	▲	Increase largely driven by higher interruptible volumes, discussed above, and higher seasonal volumes on the Alliance Pipeline, partially offset by lower volumes on the Ruby Pipeline due to contract expirations. Revenue volumes include 136 mboe/d (2020: 126 mboe/d) related to Alliance and 99 mboe/d (2020: 116 mboe/d) related to Ruby.
Adjusted EBITDA(2)	▼	Decrease largely due to lower revenue at the Edmonton South Rail Terminal, discussed above, combined with the impact of lower U.S. dollar exchange rates and increased operating expenses due to higher integrity spending and higher power costs not recoverable in revenue, partially offset by higher interruptible volumes on the Peace Pipeline system. Included in adjusted EBITDA is $65 million (2020: $69 million) related to Alliance and $40 million (2020: $49 million) related to Ruby.


Significant Projects			In-service Date
NEBC Montney Infrastructure			February 2021
Phase VI Expansion			June 2020
Wapiti Condensate Lateral			March 2020


Phase VII Peace Pipeline Expansion
Capital Budget: $775 million	In-service Date: First half of 2023	Status: On time, trending on budget
This expansion includes a new 20-inch, approximately 220 km pipeline and two new pump stations or terminal upgrades. Phase VII will add approximately 160 mbpd of incremental capacity upstream of Fox Creek, accessing capacity available on the mainlines downstream of Fox Creek. All major procurement activities were completed by end of the second quarter. Construction is underway and progressing according to schedule.


Phase IX Peace Pipeline Expansion
Capital Budget: $120 million	In-service Date: Second half of 2022	Status: On time, trending on budget
This expansion will include new 6-inch and 16-inch pipelines debottlenecking the corridor north of Gordondale, Alberta as well as upgrades at one pump station. In addition, this expansion will see existing pipelines, which are currently batching, converted to single product lines. Phase IX also includes a pump station in the Wapiti-to-Kakwa corridor that is partially complete and was previously part of the Phase VII project scope.


Phase VIII Peace Pipeline Expansion									Status: Deferred
This expansion will include 10-inch and 16-inch pipelines in the Gordondale to La Glace corridor as well as six new pump stations or terminal upgrades located between Gordondale and Fox Creek.


Changes in Results
Gas Services net revenue(1)(2)	▲	Increase largely due to Empress Infrastructure and Duvernay III being placed into service in the fourth quarter of 2020 and increased operating expense recoveries as a result of higher power costs, combined with the Burstall Ethane Storage Facility being transferred from NGL Services to Gas Services in January 2021.
NGL Services net revenue(1)(2)	▲	Increase primarily due to the Prince Rupert Terminal being placed into service in March 2021, higher operating expense recoveries at the Redwater Complex, partially offset by the transfer of the Burstall Ethane Storage Facility to Gas Services, discussed above.
Operating expenses(1)	▼	Increase largely due to operating expenses associated with the additional assets placed into service, discussed above, combined with higher power pool prices during the second quarter of 2021.
Share of profit from equity accounted investees	●	Consistent with the prior period.
Unrealized gain on commodity-related derivatives	▲	Certain gas processing fees are tied to AECO prices and the increase in the AECO price has resulted in an unrealized gain for the second quarter of 2021.

Distributions from equity accounted investees	●	Consistent with the prior period. $33 million (2020: $26 million) from Veresen Midstream and $1 million (2020: $1 million) from Fort Corp.
Volumes (mboe/d)(3)	●	Consistent with prior period. Increased revenue volumes associated with Duvernay III being placed into service in the fourth quarter of 2020 was largely offset by lower supply volumes on the East NGL System, which are now being processed by the Empress Infrastructure. Revenue volumes include 86 mboe/d (2020: 81 mboe/d) related to Veresen Midstream.
Adjusted EBITDA(2)	▲	Increase primarily due to the contribution from Empress Infrastructure, Duvernay III and the Prince Rupert Terminal, being placed into service, discussed above, combined with the contribution from the Veresen Midstream Hythe Developments going into service in March of 2021. Included in adjusted EBITDA is $50 million (2020: $45 million) related to Veresen Midstream.


Empress Co-generation Facility
Capital Budget: $120 million	In-service Date: Fourth quarter of 2022	Status: Ahead of schedule, on budget
The Empress Co-generation Facility will use natural gas to generate up to 45 megawatts of electrical power, thereby reducing overall operating costs by providing power and heat to the existing Empress NGL Extraction Facility. All the power will be consumed on site, thereby supplying approximately 90 percent of the site's power requirements. Further, this project will contribute to annual greenhouse gas emission reductions at the Empress NGL Extraction Facility through the utilization of the co-generation waste heat and the low-emission power generated. Pembina anticipates a reduction of approximately 90,000 tonnes of carbon dioxide equivalent per year based on the current energy demand of the Empress NGL Extraction Facility. Construction commenced in May 2021.


			o Form 20-F			x Form 40-F


($ millions)	June 30, 2021	December 31, 2020

Working capital(1)	(500)	(792)
Variable rate debt(2)(3)
Bank debt	1,712	1,534
Variable rate debt swapped to fixed	(310)	(318)
Total variable rate loans and borrowings outstanding (weighted average interest rate of 1.3% (2020: 1.6%))	1,402	1,216
Fixed rate debt(2)

Senior unsecured medium-term notes	9,050	9,300
Variable rate debt swapped to fixed	310	318
Total fixed rate loans and borrowings outstanding (weighted average interest rate of 3.9% (2020: 3.9%))	9,360	9,618


Total loans and borrowings outstanding	10,762	10,834
Cash and unutilized debt facilities	1,675	2,685
Subordinated hybrid notes (weighted average interest rate of 4.8% (2020: nil))	600	—


Contractual Obligations(1)	Payments Due By Period
($ millions)	Total	Less than 1 year	1 – 3 years	3 – 5 years	After 5 years
Leases(2)	1,032	121	188	157	566
Long-term debt(3)	16,906	887	2,895	2,284	10,840

Construction commitments(4)	1,092	503	77	33	479

Other	549	85	128	70	266
Total contractual obligations	19,579	1,596	3,288	2,544	12,151



Issued and outstanding (thousands)(1)			July 30, 2021
Common shares			550,057
Stock options			23,601
Stock options exercisable			12,803
Series 1 Class A Preferred shares			10,000
Series 3 Class A Preferred Shares			6,000
Series 5 Class A Preferred Shares			10,000
Series 7 Class A Preferred Shares			10,000
Series 9 Class A Preferred Shares			9,000
Series 15 Class A Preferred Shares			8,000
Series 17 Class A Preferred Shares			6,000
Series 19 Class A Preferred Shares			8,000
Series 21 Class A Preferred Shares			16,000
Series 23 Class A Preferred Shares			12,000
Series 25 Class A Preferred Shares			10,000


Prince Rupert Terminal Expansion									Status: Deferred
The Prince Rupert Terminal Expansion will increase the export capacity of the Prince Rupert Terminal.


Change in Results


Net revenue(1)(2)	▲	Increase due to higher NGL and crude oil market prices, resulting in higher margins, combined with higher marketed NGL volumes, discussed below, partially offset by rail transportation costs to re-position propane to Corunna for sale in the fourth quarter of 2021 and first quarter of 2022, and charges related to the Prince Rupert Terminal and Empress Infrastructure. Additionally, the increase in net revenue was further offset by the timing of storage related margins, as the majority of 2020 storage margins were earned in the second quarter of 2020, compared to 2021 where storage margins are being realized evenly throughout the year.
Share of profit from equity accounted investees	▲	Increase largely due to higher revenues at Aux Sable as a result of higher NGL margins and a wider AECO-Chicago natural gas price differential.
Realized loss (gain) on commodity-related derivatives	▼	Realized loss due to higher NGL and crude oil market prices during the second quarter of 2021, which also drove higher margins on NGL and crude oil sales, resulting in a realized loss on NGL- and crude oil-based derivative instruments for the period, compared to realized gains recognized during the second quarter of 2020. Pembina utilizes derivative instruments to stabilize the results of its marketing business.
Unrealized loss on commodity-related derivatives	▲	Lower unrealized loss on commodity-related derivatives primarily due to fewer contracts maturing in the period, partially offset by the increase in the forward prices for NGL and crude oil during the second quarter of 2021.

Distributions from equity accounted investees	▲	$18 million (2020: $2 million) from Aux Sable. Increase largely due to the higher margins at Aux Sable, discussed above.
Volumes (mboe/d)(3)	▲	Marketed NGL volumes increased as sales have returned to pre-pandemic levels compared to the second quarter of 2020 when Pembina built up storage positions due to lower commodity prices, combined with increased volumes at Aux Sable. Revenue volumes includes 36 mboe/d (2020: 32 mboe/d) related to Aux Sable.
Adjusted EBITDA(2)	●	Consistent with the prior period. Higher margins on NGL and crude oil sales as a result of the higher NGL and crude oil prices during the second quarter of 2021 and higher marketed NGL volumes were largely offset by the timing of storage related margins in the second quarter of 2020, discussed above, and the realized loss on commodity-related derivatives due to higher NGL and crude oil market prices. Included in adjusted EBITDA is $14 million (2020: $4 million) related to Aux Sable.


Change in Results


Net revenue(1)(2)	▲	Increase largely due to higher crude oil and NGL market prices, resulting in higher margins, combined with higher marketed NGL volumes, discussed below.
Share of profit from equity accounted investees	▲	Increase largely due to higher revenues at Aux Sable as a result of higher NGL margins and a wider AECO-Chicago natural gas price differential.
Realized loss (gain) on commodity-related derivatives	▼	Realized loss due to higher NGL and crude oil market prices during the period, which also drove higher margins on NGL and crude sales, resulting in a realized loss on NGL- and crude oil-based derivative instruments for the period, compared to realized gains recognized during the first six months of 2020. Pembina utilizes derivative instruments to stabilize the results of its marketing business.
Unrealized loss (gain) on commodity-related derivatives	▼	Unrealized loss on commodity-related derivatives primarily due to the recovery in the forward prices for NGL and crude oil during the first six months of 2021, partially offset by contracts maturing in the period.

Distributions from equity accounted investees	▲	$36 million (2020: $13 million) from Aux Sable. Increase largely due to the higher margins at Aux Sable, discussed above.
Volumes (mboe/d)(3)	▲	Marketed NGL volumes increased as Pembina monetized storage positions during the first six months of 2021, that were built up during the second and third quarters of 2020, when commodity prices were lower. Revenue volumes includes 36 mboe/d (2020: 37 mboe/d) related to Aux Sable.
Adjusted EBITDA(2)	▲	Increase largely due to higher margins on NGL and crude oil sales as a result of the higher NGL and crude oil prices during the first six months of 2021 and higher marketed NGL volumes, combined with a higher contribution from Aux Sable due to higher NGL margins and the wider AECO-Chicago natural gas price differential, partially offset by the realized loss on commodity-related derivatives due to higher NGL market prices. Included in adjusted EBITDA is $26 million (2020: $13 million) related to Aux Sable.


(1)			Pembina enters into product purchase agreements and power purchase agreements to secure supply for future operations. Purchase prices of both NGL and power are dependent on current market prices. Volumes and prices for NGL and power contracts cannot be reasonably determined, and therefore, an amount has not been included in the contractual obligations schedule. Product purchase agreements range from one to 9 years and involve the purchase of NGL products from producers. Assuming product is available, Pembina has secured between 12 and 138 mbpd of NGL each year up to and including 2029. Power purchase agreements range from one to 24 years and involve the purchase of power from electrical service providers. Pembina has secured up to 80 megawatts per day each year up to and including 2045.
(2)			Includes terminals, rail, office space, land and vehicle leases.
(3)			Includes loans and borrowings, subordinated hybrid notes and interest payments on Pembina's senior unsecured medium-term notes and subordinated hybrid notes. Excludes deferred financing costs.
(4)			Excluding significant projects that are awaiting regulatory approval, projects which Pembina is not committed to construct, and projects that are executed by equity accounted investees.


(mboe/d)	2021		2020				2019
	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Volumes(1)(2)
Pipelines
Conventional Pipelines	892	862	993	863	834	902	958	908
Transmission Pipelines	685	674	684	661	668	668	646	594
Oil Sands Pipelines	1,050	1,051	1,053	1,056	1,053	1,059	1,063	1,068
Facilities
Gas Services	662	677	673	657	658	678	690	672
NGL Services	211	218	211	214	214	201	220	194

Total	3,500	3,482	3,614	3,451	3,427	3,508	3,577	3,436


($ millions, except where noted)	2021		2020(2)				2019(2)
	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Revenue	1,954	2,045	1,694	1,569	1,268	1,671	1,754	1,700
Net revenue(1)	894	999	954	849	776	865	837	751
Operating expenses	186	182	201	178	154	179	177	151
Realized loss (gain) on commodity-related derivative financial instruments	33	88	6	(7)	(36)	(17)	(8)	(5)
Share of profit (loss) from equity accounted investees	52	71	(244)	62	66	84	89	90
Gross profit	550	630	247	568	460	733	605	615
Earnings (loss)	254	320	(1,216)	323	258	319	150	373
Earnings (loss) per common share – basic and diluted (dollars)	0.39	0.51	(2.28)	0.52	0.40	0.51	0.22	0.67

Cash flow from operating activities	584	456	766	434	642	410	728	535
Cash flow from operating activities per common share – basic (dollars)(1)	1.06	0.83	1.39	0.78	1.17	0.75	1.41	1.05
Adjusted cash flow from operating activities(1)	538	582	603	524	586	576	576	530
Adjusted cash flow from operating activities per common share – basic (dollars)(1)	0.98	1.06	1.10	0.95	1.07	1.05	1.11	1.04
Common shares outstanding (millions):
Weighted average – basic	550	550	550	550	550	549	518	512
Weighted average – diluted	551	550	550	550	550	549	519	513
End of period	550	550	550	550	550	550	548	512
Common share dividends declared	347	346	346	346	347	346	314	307
Dividends per common share	0.63	0.63	0.63	0.63	0.63	0.63	0.60	0.60
Preferred share dividends declared	35	36	38	38	37	38	34	31
Capital investments	146	127	161	174	211	483	429	421
Contributions to equity accounted investees	—	12	—	28	2	194	120	25
Distributions from equity accounted investees	112	115	109	111	116	123	123	142


Adjusted EBITDA(1)	778	835	866	796	789	830	787	736


($ millions)(1)	June 30, 2021	December 31, 2020

Pipelines	854	926
Facilities	1,195	1,200

Total	2,049	2,126


	6 Months Ended	Remainder of
($ millions)(1)	June 30, 2021	2021	2022	2023	2024	2025+
Pipelines	80	33	601	61	67	92
Facilities	5	12	36	36	1,111	—

Total	85	45	637	97	1,178	92


($ millions)	3 Months Ended June 30, 2020			6 Months Ended June 30, 2020
	Previously reported	Adjustments	Restated	Previously reported	Adjustments	Restated
Cost of sales	813	(4)	809	1,965	(8)	1,957
Share of profit from equity accounted investees	65	1	66	148	2	150
Gross profit	455	5	460	1,183	10	1,193


Net finance costs	72	(1)	71	281	(2)	279
Earnings before income tax	344	6	350	785	12	797
Deferred tax expense	24	1	25	75	2	77
Earnings attributable to shareholders	253	5	258	567	10	577

Total comprehensive income attributable to shareholders	50	5	55	843	10	853
Earnings attributable to common shareholders, net of preferred share dividends	214	5	219	489	10	499
Earnings per common share - basic and diluted	0.39	0.01	0.40	0.89	0.02	0.91


	3 Months Ended June 30		6 Months Ended June 30

($ millions, except per share amounts)	2021	2020	2021	2020
Cash flow from operating activities	584	642	1,040	1,052
Cash flow from operating activities per common share – basic (dollars)	1.06	1.17	1.89	1.91
Add (deduct):
Change in non-cash operating working capital	(2)	38	77	79
Current tax expense	(56)	(67)	(114)	(143)
Taxes paid, net of foreign exchange	69	18	197	200
Accrued share-based payments	(22)	(8)	(40)	5
Share-based payments	—	—	32	44
Preferred share dividends paid	(35)	(37)	(72)	(75)
Adjusted cash flow from operating activities	538	586	1,120	1,162
Adjusted cash flow from operating activities per common share – basic (dollars)	0.98	1.07	2.04	2.11


Other
AECO			Alberta Energy Company benchmark price for natural gas
B.C.			British Columbia
GAAP			Canadian generally accepted accounting principles
IFRS			International Financial Reporting Standards


NGL			Natural gas liquids
U.S.			United States
WCSB			Western Canadian Sedimentary Basin
Deep cut			Ethane-plus capacity extraction gas processing capabilities
Shallow cut			Sweet gas processing with propane and/or condensate-plus extraction capabilities
Kinder Acquisition			Pembina's acquisition of Kinder Morgan Canada Limited and the U.S. portion of the Cochin Pipeline system on December 16, 2019

Volumes			Volumes for Pipelines and Facilities are revenue volumes, defined as physical volumes plus volumes recognized from take-or-pay commitments. Volumes for Marketing & New Ventures are marketed NGL volumes. Volumes are stated in mboe/d, with natural gas volumes converted to mboe/d from MMcf/d at a 6:1 ratio.


Measurement
bpd			barrels per day
mbbls			thousands of barrels
mbpd			thousands of barrels per day
mmbpd			millions of barrels per day
mmbbls			millions of barrels
mboe/d			thousands of barrels of oil equivalent per day
mmboe/d			millions of barrels of oil equivalent per day
MMcf/d			millions of cubic feet per day
bcf/d			billions of cubic feet per day
km			kilometer


Investments in Equity Accounted Investees
Pipelines:
Alliance			50 percent interest in both Alliance Pipeline Limited Partnership and Alliance Pipeline L.P.
Ruby			50 percent convertible, cumulative preferred interest in the Ruby Pipeline Holding Company L.L.C.
Grand Valley			75 percent jointly controlled interest in Grand Valley 1 Limited Partnership wind farm ("Grand Valley")
Facilities:
Veresen Midstream			45 percent interest in Veresen Midstream Limited Partnership, which owns assets in western Canada serving the Montney geological play in northwestern Alberta and northeastern B.C. including gas processing plants and gas gathering pipelines and compression
Fort Corp			50 percent interest in Fort Saskatchewan Ethylene Storage Limited Partnership and Fort Saskatchewan Ethylene Corporation
Marketing & New Ventures:
Aux Sable			An ownership interest in Aux Sable (approximately 42.7 percent in Aux Sable U.S. and 50 percent in Aux Sable Canada), which includes an NGL fractionation facility and gas processing capacity near Chicago, Illinois and other natural gas and NGL processing facilities, logistics and distribution assets in the U.S. and Canada, as well as transportation contracts on Alliance
CKPC			50 percent interest in the PDH/PP Facility
Cedar LNG			49.9 percent interest in the floating LNG facility in Kitimat, British Columbia, Canada


	Attributable to Shareholders of the Company						Total Equity (Restated Note 2)
($ millions)	Common Share Capital	Preferred Share Capital	Deficit (Restated Note 2)	AOCI(1)	Total (Restated Note 2)	Non-Controlling Interest


December 31, 2020	15,644	2,946	(3,637)	2	14,955	60	15,015
Total comprehensive income (loss)
Earnings	—	—	574	—	574	—	574
Other comprehensive loss (Note 12)	—	—	—	(111)	(111)	—	(111)




Total comprehensive income (loss)	—	—	574	(111)	463	—	463
Transactions with shareholders of the Company

Part VI.1 tax on preferred shares (Note 8)	—	(4)	—	—	(4)	—	(4)
Preferred shares redemption (Note 8)	—	(420)	—	—	(420)	—	(420)

Share-based payment transactions (Note 8)	17	—	—	—	17	—	17
Dividends declared – common (Note 8)	—	—	(693)	—	(693)	—	(693)
Dividends declared – preferred (Note 8)	—	—	(71)	—	(71)	—	(71)

Total transactions with shareholders of the Company	17	(424)	(764)	—	(1,171)	—	(1,171)

June 30, 2021	15,661	2,522	(3,827)	(109)	14,247	60	14,307



Opening value January 1, 2020	15,539	2,956	(1,785)	98	16,808	60	16,868
Total comprehensive income (loss)
Earnings	—	—	577	—	577	—	577
Other comprehensive income
Exchange gain on translation of foreign operations	—	—	—	262	262	—	262
Remeasurements of defined benefit liability, net of tax	—	—	—	14	14	—	14
Total comprehensive income	—	—	577	276	853	—	853
Transactions with shareholders of the Company

Part VI.1 tax on preferred shares	—	(4)	—	—	(4)	—	(4)


Share-based payment transactions	90	—	—	—	90	—	90
Dividends declared – common	—	—	(693)	—	(693)	—	(693)
Dividends declared – preferred	—	—	(75)	—	(75)	—	(75)

Total transactions with shareholders of the Company	90	(4)	(768)	—	(682)	—	(682)

June 30, 2020	15,629	2,952	(1,976)	374	16,979	60	17,039


($ millions)	Land and Land Rights	Pipelines	Facilities and Equipment	Cavern Storage and Other	Assets Under Construction(1)(2)	Total
Cost







Balance at December 31, 2020	429	9,206	8,907	1,993	1,109	21,644
Additions and transfers	12	75	430	122	(465)	174

Change in decommissioning provision	—	4	6	5	—	15
Disposals and other	(1)	(20)	(13)	(22)	—	(56)
Foreign exchange	(2)	(23)	(6)	—	—	(31)
Balance at June 30, 2021	438	9,242	9,324	2,098	644	21,746

Depreciation




Balance at December 31, 2020	21	1,547	1,118	409	—	3,095

Depreciation	2	96	115	42	—	255
Disposals and other	—	(9)	(11)	(11)	—	(31)
Balance at June 30, 2021	23	1,634	1,222	440	—	3,319

Carrying amounts
Balance at December 31, 2020	408	7,659	7,789	1,584	1,109	18,549
Balance at June 30, 2021	415	7,608	8,102	1,658	644	18,427

Assets subject to operating leases
December 31, 2020	8	300	496	170	—	974
June 30, 2021	8	299	485	166	—	958


	Ownership Interest (percent)		Share of Profit from Equity Accounted Investees		Investments in Equity Accounted Investees
			6 Months Ended June 30
($ millions)	June 30, 2021	December 31, 2020	2021	2020 (Restated Note 2)	June 30, 2021	December 31, 2020
Alliance	50	50	59	58	2,408	2,498
Aux Sable	42.7 - 50	42.7 - 50	13	2	367	401
Ruby(1)	—	—	13	61	—	—
Veresen Midstream	45	45	35	27	1,360	1,374
CKPC	50	50	—	1	—	—
Cedar LNG	49.9	—	—	—	129	—
Other(2)	50 - 75	50 - 75	3	1	82	104
			123	150	4,346	4,377


($ millions)	Terminals	Rail	Buildings	Land & Other	Total





Balance at December 31, 2020	213	221	121	96	651
Additions and adjustments	—	—	39	17	56
Disposals and other	—	(4)	(1)	(8)	(13)
Amortization	(6)	(21)	(9)	(6)	(42)
Balance at June 30, 2021	207	196	150	99	652



As at June 30, 2021
($ millions)	Operating Leases	Finance Leases
Less than one year	144	32
One to two years	142	31
Two to three years	130	31
Three to four years	114	31
Four to five years	108	32
More than five years	780	334
Total undiscounted lease receipts	1,418	491
Unearned finance income on lease receipts		(281)
Discounted unguaranteed residual value		14
Finance lease receivable		224
Less current portion(1)		(9)
Total non-current		215


				Carrying Value
($ millions)	Authorized at June 30, 2021	Nominal Interest Rate	Year of Maturity	June 30, 2021	December 31, 2020

Loans and borrowings
Senior unsecured credit facilities(1)(3)(4)	3,330	1.27(2)	Various(1)	1,708	1,530





Senior unsecured medium-term notes series 1	—	4.89	2021	—	250
Senior unsecured medium-term notes series 2	450	3.77	2022	450	449
Senior unsecured medium-term notes series 3	450	4.75	2043	447	447
Senior unsecured medium-term notes series 4	600	4.81	2044	597	597
Senior unsecured medium-term notes series 5	450	3.54	2025	449	449
Senior unsecured medium-term notes series 6	500	4.24	2027	499	498
Senior unsecured medium-term notes series 7	600	3.71	2026	603	603
Senior unsecured medium-term notes series 8	650	2.99	2024	648	647
Senior unsecured medium-term notes series 9	550	4.74	2047	542	542
Senior unsecured medium-term notes series 10	650	4.02	2028	660	661
Senior unsecured medium-term notes series 11	800	4.75	2048	842	842
Senior unsecured medium-term notes series 12	650	3.62	2029	654	654
Senior unsecured medium-term notes series 13	700	4.54	2049	713	713
Senior unsecured medium-term notes series 14	600	2.56	2023	599	599
Senior unsecured medium-term notes series 15	600	3.31	2030	597	597
Senior unsecured medium-term notes series 16	400	4.67	2050	397	397

Senior unsecured medium-term notes series 3A	50	5.05	2022	49	51

Senior unsecured medium-term notes series 5A	350	3.43	2021	350	350


Total loans and borrowings				10,804	10,876
Less current portion loans and borrowings				(399)	(600)
Total non-current loans and borrowings				10,405	10,276
Subordinated hybrid notes
Subordinated notes, series 1	600	4.80	2081	594	—


($ millions, except as noted)	Number of Common Shares (millions)	Common Share Capital





Balance at December 31, 2020	550	15,644



Share-based payment transactions	—	17
Balance at June 30, 2021	550	15,661