Pembina Pipeline Corp 6-K, filed Nov 3, 2022

Pembina Pipeline Corp (PBA)

6-K 2022-11-03 For: 2022-09-30

View Original

Added on April 09, 2026

About this 6-K

Pembina Pipeline Corp filed this 6-K on November 3, 2022.

Search and read filings like this one from Claude or ChatGPT with the SEC filings MCP server →


		PEMBINA PIPELINE CORPORATION



Date:	November 3, 2022	By:	/s/ Cameron J. Goldade
			Name: Cameron J. Goldade
			Title: Senior Vice President & Chief Financial Officer


Exhibit Number						Document Description

99.1						Q3 2022 Management's Discussion and Analysis & Financial Statements
99.2						CEO Certificate
99.3						CFO Certificate


REPORT TO SHAREHOLDERS
Third Quarter 2022

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									25
5. Share Capital									28
6. Capital Expenditures									31
7. Selected Quarterly Information									32
8. Selected Equity Accounted Investee Information									34
9. Other									36
10. Accounting Policies & Estimates									37
11. Risk Factors									38
12. Non-GAAP & Other Financial Measures									39
13. Abbreviations									43
14. Forward-Looking Statements & Information									44


($ millions, except where noted)	2022	2021	Change


Revenue	2,779	2,149	630
Net revenue(1)	1,030	961	69

Gross profit	874	682	192
Earnings	1,829	588	1,241
Earnings per common share – basic (dollars)	3.24	1.01	2.23
Earnings per common share – diluted (dollars)	3.23	1.01	2.22
Cash flow from operating activities	767	913	(146)
Cash flow from operating activities per common share – basic (dollars)	1.38	1.66	(0.28)
Adjusted cash flow from operating activities(1)	574	786	(212)
Adjusted cash flow from operating activities per common share – basic (dollars)(1)	1.04	1.43	(0.39)
Capital expenditures	131	209	(78)
Adjusted EBITDA(1)	967	850	117
Total volumes (mboe/d)(2)	3,424	3,411	13


Changes in Results for the Three Months Ended September 30


Revenue	▲	$630 million increase, largely due to an increase in crude oil, certain NGL, and natural gas market prices, higher volumes on the Peace Pipeline system and higher tolls primarily due to inflation, higher volumes on the Cochin Pipeline and higher recoverable costs, partially offset by lower revenue from the Field-based Gas Processing Assets contributed to PGI and now reflected in share of profit from equity accounted investees, and lower contracted volumes on the Nipisi Pipeline system.
Cost of goods sold	▼	$561 million increase, largely due to higher crude oil, certain NGL, and natural gas market prices.
Operating expenses	▼	$38 million increase, primarily due to higher power and fuel costs, the majority of which are recoverable, as a result of higher power pool prices and higher AECO prices during the third quarter of 2022 and higher integrity costs, partially offset by lower operating expenses due to the PGI Transaction, discussed above.
Depreciation and amortization included in operations	▲	$34 million decrease, primarily due to a smaller asset base resulting from the PGI Transaction, as well as from the impairment of certain assets in Pipelines in the fourth quarter of 2021.
Share of profit from equity accounted investees	▲	$48 million increase, primarily due to higher revenues at Aux Sable and Alliance as a result of a wider AECO-Chicago natural gas price differential, combined with higher revenue due to the strong performance of the PGI assets, an unrealized gain on commodity-related derivatives in Aux Sable and the sale of linepack inventory at Alliance in the third quarter of 2022, partially offset by higher depreciation, interest expense, and unrealized loss on commodity-related derivatives in PGI.
Realized loss on commodity-related derivatives	▲	$24 million positive variance, primarily due to lower realized losses on NGL-based derivative instruments driven by the change in NGL market prices during the period.
Unrealized gain on commodity-related derivatives	▲	$55 million positive variance, due to gains on NGL and crude oil marketing derivatives as a result of the decrease in the forward prices for propane and crude during the third quarter of 2022, partially offset by the decrease in the forward AECO natural gas prices.
General & administrative	▼	$8 million increase, largely due to higher salaries and wages, consulting and legal fees, partially offset by lower long-term incentive costs following the decline in global equity markets which impacted Pembina's share price during the third quarter of 2022.
Other expense (income)	▼	$338 million decrease, primarily due to the $350 million Arrangement Termination Payment received in the third quarter of 2021, partially offset by lower restructuring costs and lower acquisition costs.
Gain on PGI Transaction	▲	$1.1 billion increase related to the gain on the PGI Transaction.

Net finance costs	●	Consistent with the prior period. Lower foreign exchange losses and lower interest due to tax settlements were largely offset by higher losses on non-commodity derivative financial instruments and higher interest on long-term debt as a result of terming out variable rate debt to fixed rate debt at higher interest rates.
Current tax expense	▲	$71 million decrease, primarily due to higher tax recognized in the third quarter of 2021 associated with the Arrangement Termination Payment received in the third quarter of 2021.

Deferred tax expense	▲	$210 million decrease, primarily due to the impacts of the PGI Transaction.

Cash flow from operating activities	▼	$146 million decrease, primarily due to lower operating results driven by non-cash items and the $350 million Arrangement Termination Payment, discussed above, partially offset by a change in non-cash working capital, an increase in distributions from equity accounted investees, combined with a decrease in net interest paid.
Adjusted cash flow from operating activities(1)	▼	$212 million decrease, largely due to the same items impacting cash flow from operating activities, discussed above, net of the change in non-cash working capital, partially offset by lower current tax expense and decrease in accrued share based payments.
Adjusted EBITDA(1)	▲	$117 million increase, largely due to higher margins on crude oil and natural gas sales, higher contribution from Aux Sable and Alliance due to higher revenues driven by a wider AECO-Chicago natural gas price differential, and from the strong performance of the PGI assets, lower realized losses on commodity-related derivatives, higher volumes on the Peace Pipeline system and on the Cochin Pipeline and higher tolls due to inflation, partially offset by lower NGL margins and lower contribution from Ruby due to Ruby Pipeline, L.L.C ("Ruby Pipeline") filing for bankruptcy protection on March 31, 2022 and higher integrity costs. Refer to the "Selected Equity Accounted Investee Information" section for further details on Ruby. Included in adjusted EBITDA is $241 million (2021: $178 million) related to equity accounted investees.
Total volumes (mboe/d)(2)	▲	13 mboe/d increase, largely driven by higher volumes on the Peace Pipeline system due to increased upstream activity, higher volumes at the Alberta Ethane Gathering System ("AEGS") due to third party outages in the third quarter of 2021, combined with higher interruptible volumes on the Cochin Pipeline, higher volumes at the Redwater complex, and at Younger due to less outage days during the third quarter of 2022, partially offset by contract expirations on the Nipisi and Mitsue Pipeline systems during the fourth quarter of 2021, and Ruby Pipeline filing for bankruptcy protection on March 31, 2022. Volumes include 355 mboe/d (2021: 298 mboe/d) related to equity accounted investees.


Changes in Results for the Nine Months Ended September 30


Revenue	▲	$2.8 billion increase, largely due to an increase in crude oil, NGL and natural gas market prices, higher volumes on the Peace Pipeline system and higher tolls largely due to inflation, combined with higher volumes on the Cochin Pipeline and higher recoverable costs, partially offset by lower contracted volumes on the Nipisi and Mitsue Pipeline systems and lower revenue from the Field-based Gas Processing Assets contributed to PGI and now reflected in share of profit from equity accounted investees.
Cost of goods sold	▼	$2.5 billion increase, largely due to higher crude oil, NGL, and natural gas market prices.
Operating expenses	▼	$74 million increase, primarily due to higher power and fuel costs, the majority of which are recoverable, as a result of higher power pool prices and higher AECO prices during the period, combined with higher integrity costs and higher recoverable geotechnical costs largely related to the Western Pipeline, partially offset by lower operating expenses due to the PGI Transaction, discussed above.
Depreciation and amortization included in operations	▲	$22 million decrease, primarily due to a smaller asset base in Pipelines from the impairment of certain assets in the fourth quarter of 2021 and in Facilities following the PGI Transaction, partially offset by higher asset retirements in Facilities and the Prince Rupert Terminal being placed into service in March 2021.
Share of profit from equity accounted investees	▲	$84 million increase, primarily due to higher revenues at Aux Sable and Alliance as a result of a wider AECO-Chicago natural gas price differential, higher revenue due to the strong performance of the PGI assets and the sale of linepack inventory at Alliance in the second and third quarters of 2022, partially offset by a lower contribution from Ruby due to Ruby Pipeline filing for bankruptcy protection on March 31, 2022 and higher depreciation, interest expense, and unrealized loss on commodity-related derivatives in PGI.
Realized loss on commodity-related derivatives	▲	$49 million positive variance, primarily due to lower realized losses on NGL-based derivative instruments driven by the change in NGL market prices and the increase in the AECO price during the period resulting in realized gains for certain gas processing fees tied to AECO prices, partially offset by higher realized losses on crude oil-based derivative instruments due to higher crude oil market prices during the period.
Unrealized gain on commodity-related derivatives	▲	$149 million positive variance, primarily due to gains on NGL marketing derivatives and renewable power purchase agreements resulting from the increase in the forward prices for natural gas and power during the period as well as newly added contracts, and gains on crude oil marketing derivatives resulting from contracts maturing in the period, partially offset by the change in the AECO forward prices in the period resulting in lower unrealized gains for certain processing fees tied to AECO prices.
General & administrative	▼	$39 million increase, largely due to higher long-term incentive costs primarily driven by Pembina's performance relative to peers, combined with higher salaries and wages, consulting fees and legal fees.
Other expense (income)	▼	$299 million decrease, primarily due to the $350 million Arrangement Termination Payment received in the third quarter of 2021, partially offset by lower restructuring costs and lower acquisition costs.
Impairments	▲	$35 million decrease, primarily due to impairment charges of $21 million recognized on Pembina's interest in Fort Corp in 2021 and $10 million on an advance made to Ruby in 2021 compared to nil in 2022.
Gain on PGI Transaction	▲	$1.1 billion increase related to the gain on the PGI Transaction.
Net finance costs	▼	$30 million increase, primarily due to foreign exchange losses in the period compared to gains in 2021, higher interest on long-term debt as a result of terming out variable rate debt to fixed rate debt at higher interest rates, lower interest income, and higher losses on non-commodity derivative financial instruments, partially offset by lower interest expense associated with tax settlements.
Current tax expense	▲	$10 million decrease, primarily due to the tax associated with the $350 million Arrangement Termination Payment received in the third quarter of 2021, partially offset by higher current year earnings.
Deferred tax expense	▲	$199 million decrease, primarily due to the PGI Transaction, partially offset by higher current year earnings.

Cash flow from operating activities	▲	$73 million increase, primarily driven by an increase in distributions from equity accounted investees and a change in non-cash working capital, partially offset by lower operating results driven by non-cash items, the $350 million Arrangement Termination Payment, discussed above, an increase in taxes paid, and an increase in share-based compensation payments.
Adjusted cash flow from operating activities(1)	▲	$51 million increase, largely due to the same items impacting cash flow from operating activities, discussed above, net of the change in non-cash working capital, taxes paid and share-based compensation payments, combined with lower current tax expense.
Adjusted EBITDA(1)	▲	$358 million increase, primarily due to higher margins on crude oil, NGL, and natural gas sales, higher contributions due to the strong performance of the PGI assets, higher contributions from Aux Sable and Alliance, higher volumes on the Peace Pipeline system and on the Cochin Pipeline, higher tolls due to inflation, lower losses on commodity-related derivatives, and higher recoverable costs from the Horizon Pipeline system. These are partially offset by lower contributions from Ruby, higher general & administrative expense, and lower contracted volumes on the Nipisi and Mitsue Pipeline systems. Included in adjusted EBITDA is $596 million (2021: $536 million) related to equity accounted investees.
Total volumes (mboe/d)(2)	▼	85 mboe/d decrease, largely driven by lower volumes on the Ruby Pipeline and contract expirations on the Nipisi and Mitsue Pipeline systems, partially offset by higher volumes on the Peace Pipeline system and Drayton Valley Pipeline as higher crude oil and NGL market prices have resulted in increased upstream activity, and higher interruptible volumes on the Cochin Pipeline. Volumes include 294 mboe/d (2021: 318 mboe/d) related to equity accounted investees.


	3 Months Ended September 30
	2022		2021
($ millions, except where noted)	Volumes(1)	Reportable Segment Earnings (Loss) Before Tax		Adjusted EBITDA(2)	Volumes(1)	Reportable Segment Earnings Before Tax	Adjusted EBITDA(2)
Pipelines	2,531	377		535	2,563	329	503
Facilities	893	1,270		291	848	207	273
Marketing & New Ventures(3)	—	252		180	—	91	109
Corporate	—	(158)		(39)	—	154	(35)
Total	3,424	1,741		967	3,411	781	850

	9 Months Ended September 30
	2022		2021
($ millions, except where noted)	Volumes(1)	Reportable Segment Earnings (Loss) Before Tax		Adjusted EBITDA(2)	Volumes(1)	Reportable Segment Earnings (Loss) Before Tax	Adjusted EBITDA(2)
Pipelines	2,500	1,120		1,579	2,592	987	1,554
Facilities	879	1,659		849	872	555	812
Marketing & New Ventures(3)	—	612		550	—	167	237
Corporate	—	(502)		(157)	—	(177)	(140)
Total	3,379	2,889		2,821	3,464	1,532	2,463


Change in Results
Conventional revenue(1)(2)	▲	Increase largely due to higher volumes on the Peace Pipeline system as higher crude oil and certain NGL market prices resulted in increased upstream activity, combined with higher recoverable power costs and higher tolls largely due to inflation.
Transmission revenue(1)(2)	▲	Increase primarily due to higher interruptible volumes on the Cochin Pipeline due to increased demand resulting from wider condensate price differentials between Western Canada and the U.S. Gulf Coast and higher volumes on the Vantage Pipeline due to planned outages during the third quarter of 2021.
Oil Sands revenue(1)(2)	▼	Decrease largely due to lower contracted volumes on the Nipisi Pipeline system as a result of the expiration of contracts during the fourth quarter of 2021.
Operating expenses(1)	▼	Increase largely due to higher power costs, the majority of which are recovered in revenue, as a result of the higher power pool price during the third quarter of 2022 as well as an increase in integrity spending primarily on the Peace Pipeline system.

Share of profit from equity accounted investees	▲	Increase primarily due to higher revenue from Alliance as a result of a wider AECO-Chicago natural gas price differential, which increased demand and resulted in higher interruptible tolls, combined with higher margins realized on the sale of linepack inventory in the third quarter of 2022.
Reportable segment earnings before tax	▲	Increase largely due to higher volumes on the Peace Pipeline system and higher tolls due to inflation, combined with higher interruptible volumes on the Cochin Pipeline and higher contributions from Alliance, partially offset by the expiration of contracts on the Nipisi Pipeline system, higher integrity spending, and higher legal fees.
Adjusted EBITDA(3)	▲	Increase largely due to the same items impacting reportable segment earnings before tax, discussed above, partially offset by lower adjusted EBITDA from Ruby due to Ruby Pipeline filing for bankruptcy protection on March 31, 2022. Included in adjusted EBITDA is $79 million (2021: $62 million) related to Alliance and nil (2021: $24 million) related to Ruby. Refer to the "Selected Equity Accounted Investee Information" section for further details on Ruby.
Volumes (mboe/d)(4)	▼	Decrease largely driven by contract expirations on the Nipisi and Mitsue Pipeline systems during the fourth quarter of 2021, combined with Ruby Pipeline filing for bankruptcy protection on March 31, 2022, partially offset by higher volumes on the Peace Pipeline system as higher crude oil and certain NGL market prices have resulted in increased upstream activity, higher volumes on AEGS due to third party outages in the third quarter of 2021, higher interruptible volumes on the Cochin Pipeline, and higher volumes on the Vantage Pipeline. Volumes include 140 mboe/d (2021: 139 mboe/d) related to Alliance and nil (2021: 70 mboe/d) related to Ruby.
Distributions from equity accounted investees	▲	$77 million (2021: $46 million) from Alliance. The increase in distributions from Alliance are due to the same factors impacting share of profit from equity accounted investees discussed above.


Significant Projects			In-service Date
NEBC Montney Infrastructure			February 2021
Phase VII Peace Pipeline Expansion			June 2022


Phase VIII Peace Pipeline Expansion
Capital Budget: $530 million	In-service Date: First half of 2024	Status: On time, trending on budget
This expansion will enable segregated pipeline service for ethane-plus and propane-plus NGL mix from Gordondale, Alberta, which is centrally located within the Montney trend, into the Edmonton area for market delivery. The project includes new 10-inch and 16-inch pipelines, totaling approximately 150 km, in the Gordondale to La Glace corridor of Alberta, as well as new mid-point pump stations and terminal upgrades located throughout the Peace Pipeline system. Phase VIII will add approximately 235 mbpd of incremental capacity between Gordondale, Alberta and La Glace, Alberta, as well as approximately 65 mbpd of capacity between La Glace, Alberta and the Namao hub near Edmonton, Alberta. Procurement activities have commenced and site clearing activities are expected to begin in the fourth quarter of 2022.


Phase IX Peace Pipeline Expansion
Capital Budget: $120 million	In-service Date: Fourth quarter of 2022	Status: On time, trending on budget
This expansion includes 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 was previously part of the Phase VII project scope. Construction of the Wapiti-to-Kakwa pump station was completed in July 2022. Mainline pipeline construction is complete and commissioning activities have begun on schedule.


Changes in Results
Gas Services revenue(1)(2)	▼	Decrease largely due to the change in ownership of Pembina's formerly wholly-owned Field-based Gas Processing Assets as of August 15, 2022 as part of the PGI Transaction. The revenue from these assets are included in share of profit from equity accounted investees. Refer to the "About Pembina – Pembina Gas Infrastructure" section of this MD&A. This is partially offset by higher recoveries as a result of higher power and fuel costs.
NGL Services revenue(1)(2)	▲	Increase primarily due to higher recoveries as a result of higher power and fuel costs and higher volumes at the Redwater complex.
Operating expenses(1)	▼	Increase largely due to an increase in power and fuel costs, the majority of which are recovered in revenue, as a result of higher power pool prices and AECO prices in the third quarter of 2022, partially offset by lower operating expenses due to the PGI Transaction.
Depreciation and amortization included in operations	▲	Decrease primarily due to a smaller asset base following the PGI Transaction.

Unrealized loss (gain) on commodity-related derivatives	▼	Unrealized loss on commodity-related derivatives primarily due to the decrease in the forward AECO natural gas prices, partially offset by contracts maturing in the period, compared to unrealized gains recognized during the third quarter of 2021 when forward AECO prices were significantly increasing.
Share of profit from equity accounted investees	▼	Decrease primarily due to the PGI Transaction resulting in higher depreciation, interest expense, and an unrealized loss on commodity-related derivatives, partially offset by higher revenue due to the strong performance of the PGI assets.
Reportable segment earnings before tax	▲	Increase primarily due to the $1.1 billion gain recognized on the PGI Transaction, partially offset by the unrealized loss on commodity-related derivatives in the third quarter of 2022 compared to gains in the third quarter of 2021.
Adjusted EBITDA(3)	▲	Increase primarily due to higher contributions as a result of the strong performance of the PGI assets. Included in adjusted EBITDA is $31 million (2021: $52 million) related to Veresen Midstream and $71 million (2021: nil) related to PGI.

Volumes (mboe/d)(4)	▲	Increase primarily due to higher volumes at the Redwater complex and at Younger due to less outage days during the third quarter of 2022. Volumes include 50 mboe/d (2021: 89 mboe/d) related to Veresen Midstream and 165 mboe/d (2021: nil) related to PGI.
Distributions from equity accounted investees	▼	$16 million (2021: nil) from PGI, $2 million (2021: $1 million) from Fort Corp, and no distributions (2021: $31 million) from Veresen Midstream. The change in distributions is due to the PGI Transaction.


Change in Results


Net revenue(1)(2)	▲	Higher margins on crude oil resulting from the increased crude oil market price environment contributed to a significant quarter-over-quarter increase for the marketing business, combined with contributions from natural gas marketing, where higher margins resulted from the increase in Chicago natural gas prices, partially offset by lower NGL margins as a result of lower propane prices and higher input natural gas prices.
Realized loss on commodity-related derivatives	▲	The realized loss is primarily due to a $14 million (2021: $42 million) loss on NGL-based derivative instruments due to the change in NGL market prices during the third quarter of 2022.
Unrealized (gain) on commodity-related derivatives	▲	Unrealized gain on commodity-related derivatives primarily due to gains on NGL and crude oil marketing derivatives due to the decrease in the forward prices for propane and crude during the third quarter of 2022.


Share of profit from equity accounted investees	▲	Increase largely due to higher revenues at Aux Sable as a result of a wider AECO-Chicago natural gas price differential and an unrealized gain on commodity-related derivatives for the third quarter of 2022.
Reportable segment earnings before tax	▲	Increase largely due to the gain on commodity-related derivatives for the third quarter of 2022 compared to losses recognized during the third quarter of 2021, higher margins on crude oil and natural gas sales, and a higher contribution from Aux Sable, partially offset by lower NGL margins, discussed above, higher net finance costs related to higher losses on non-commodity derivative financial instruments and foreign exchange losses in the period compared to gains in 2021 and a project write-off due to reduced commercial opportunities.
Adjusted EBITDA(2)	▲	Increase largely due to the same items impacting reportable segment earnings before tax, discussed above, net of the unrealized gain on commodity-related derivatives, net finance costs and the project write-off cost. Included in adjusted EBITDA is $59 million (2021: $36 million) related to Aux Sable.

Volumes (mboe/d)(3)	●	Consistent with the prior period. Revenue volumes include 36 mboe/d (2021: 35 mboe/d) related to Aux Sable.
Distributions from equity accounted investees	▲	$43 million (2021: $27 million) from Aux Sable. Increase largely due to the same factors impacting share of profit from equity accounted investees discussed above.


Change in Results


Net revenue(1)(2)	▲	Higher margins on crude oil and NGL sales as a result of the increased crude oil and NGL price environment contributed to a significant year-over-year increase for the marketing business, combined with contributions from natural gas marketing, where higher margins resulted from the increase in Chicago natural gas prices.
Realized loss on commodity-related derivatives	▲	The realized loss is primarily due to a $82 million (2021: $35 million) loss on crude oil-based derivative instruments and a $52 million (2021: $124 million) loss on NGL-based derivative instruments due to the change in NGL and crude oil and market prices during the first nine months of 2022.
Unrealized (gain) loss on commodity-related derivatives	▲	Unrealized gain on commodity-related derivatives primarily due to gains on NGL marketing derivatives and renewable power purchase agreements resulting from the increase in the forward prices for natural gas and power during the period as well as newly added contracts, combined with gains on crude oil marketing derivatives resulting from contracts maturing in the period.
Share of profit from equity accounted investees	▲	Increase largely due to higher revenues at Aux Sable as a result of a wider AECO-Chicago natural gas price differential during 2022 and higher NGL margins, partially offset by an unrealized loss on commodity-related derivatives for the period.


Reportable segment earnings before tax	▲	Increase largely due to higher margins on crude oil, NGL, and natural gas sales, the gain on commodity-related derivatives for the period compared to losses recognized during the first nine months of 2021, and a higher contribution from Aux Sable, partially offset by higher net finance costs related to foreign exchange losses in the period compared to gains in 2021 and higher losses on non-commodity derivative financial instruments.
Adjusted EBITDA(2)	▲	Increase largely due to the same items impacting reportable segment earnings before tax, discussed above, net of the unrealized gain on commodity-related derivatives, Aux Sable's unrealized loss on commodity-related derivatives, and higher net finance costs. Included in adjusted EBITDA is $128 million (2021: $62 million) related to Aux Sable.

Volumes (mboe/d)(3)	●	Consistent with the prior period. Revenue volumes include 36 mboe/d (2021: 36 mboe/d) related to Aux Sable.
Distributions from equity accounted investees	▲	$105 million (2021: $63 million) from Aux Sable. Increase largely due to the same factors impacting share of profit from equity accounted investees discussed above.


Change in Results
General & administrative	▼	Increase primarily due to higher long-term incentive costs driven by Pembina's performance relative to peers and higher salaries and wages and consulting fees, partially offset due to lower share-based incentives.
Other expense (income)	▼	Decrease in other income is primarily due to the $350 million received from the Arrangement Termination Payment in the third quarter of 2021, partially offset by lower restructuring costs and lower acquisition costs.
Net finance costs	▼	Increase primarily due to higher interest on long-term debt as a result of terming out variable rate debt to fixed rate debt at higher interest rates, combined with lower interest income and lower foreign exchange gains, partially offset by lower interest expense associated with tax settlements.
Reportable segment loss before tax	▼	Decrease primarily due to the proceeds received from the Arrangement Termination Payment in the third quarter of 2021, combined with higher long-term incentive costs and higher interest expense, discussed above, partially offset by lower restructuring costs and lower acquisition costs, discussed above.




Adjusted EBITDA(2)	▼	Decrease primarily due to higher long-term incentive costs and higher salaries and wages costs, discussed above.


			o Form 20-F			x Form 40-F


($ millions)	September 30, 2022	December 31, 2021

Working capital(1)	(741)	(1,145)
Variable rate debt(2)(3)
Senior unsecured credit facilities	342	910
Variable rate bank debt swapped to fixed	(342)	(316)
Total variable rate loans and borrowings outstanding (weighted average interest rate of nil (2021: 1.1%))	—	594
Fixed rate debt(2)

Senior unsecured medium-term notes	9,650	9,700
Variable rate bank debt swapped to fixed	342	316
Total fixed rate loans and borrowings outstanding (weighted average interest rate of 3.9% (2021: 3.9%))	9,992	10,016


Total loans and borrowings outstanding	9,992	10,610
Cash and unutilized debt facilities	2,828	2,469
Subordinated hybrid notes (weighted average interest rate of 4.8% (2021: 4.8%)	600	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)	903	101	174	142	486
Long-term debt(3)	16,471	1,541	2,163	1,762	11,005

Construction commitments(4)(5)	727	399	102	14	212

Other	617	75	140	92	310
Total contractual obligations	18,718	2,116	2,579	2,010	12,013


(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 45 and 193 mbpd of NGL each year up to and including 2030. Power purchase agreements range from one to 24 years and involve the purchase of power from electrical service providers. Pembina has secured up to 77 megawatts per day each year up to and including 2046.
(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)			Includes required maintenance and/or turnarounds and excludes significant projects that are awaiting regulatory approval, projects which Pembina is not committed to construct, and projects that are executed by equity accounted investees.
(5)			Includes construction commitments related to assets held for sale of $28 million as at September 30, 2022; $3 million related to payments due in less than 1 year, and $25 million after 5 years.



(millions, except as noted)	September 30, 2022	December 31, 2021
Number of common shares repurchased for cancellation (thousands)	5,320	450
Average price per share	$46.76	$37.77
Total cost(1)	249	17



Issued and outstanding (thousands)(1)			October 28, 2022
Common shares			551,564
Stock options			12,417
Stock options exercisable			7,143
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(2)			12,000
Series 25 Class A Preferred Shares			10,000


(mboe/d)	2022			2021				2020
	Q3	Q2	Q1	Q4	Q3	Q2	Q1	Q4
Volumes(1)(2)
Pipelines
Conventional Pipelines	977	937	897	959	918	892	862	993
Transmission Pipelines	577	564	621	616	595	685	674	684
Oil Sands Pipelines	977	975	975	996	1,050	1,050	1,051	1,053
Facilities
Gas Services	686	664	675	677	660	662	677	673
NGL Services	207	204	201	189	188	211	218	211

Total	3,424	3,344	3,369	3,437	3,411	3,500	3,482	3,614


($ millions)(1)	September 30, 2022	December 31, 2021

Pipelines(2)	678	642
Facilities(3)	2,631	1,214
Marketing & New Ventures	—	1
Total	3,309	1,857


	3 Months Ended September 30		9 Months Ended September 30

($ millions, except per share amounts)	2022	2021	2022	2021
Cash flow from operating activities	767	913	2,026	1,953
Cash flow from operating activities per common share – basic (dollars)	1.38	1.66	3.66	3.55
Add (deduct):
Change in non-cash operating working capital	(157)	(7)	(15)	70
Current tax expense	(70)	(141)	(245)	(255)
Taxes paid, net of foreign exchange	68	68	306	265
Accrued share-based payment expense	(3)	(16)	(66)	(56)
Share-based compensation payment	—	—	45	32
Preferred share dividends paid	(31)	(31)	(94)	(103)
Adjusted cash flow from operating activities	574	786	1,957	1,906
Adjusted cash flow from operating activities per common share – basic (dollars)	1.04	1.43	3.54	3.47


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


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		Regulators & Acts
bpd	barrels per day	ABCA	Business Corporations Act (Alberta)
mbbls	thousands of barrels	AER	Alberta Energy Regulator
mbpd	thousands of barrels per day	BCEAO	British Columbia Environmental Assessment Office
mmbpd	millions of barrels per day	BCOGC	British Columbia Oil and Gas Commission
mmbbls	millions of barrels	BCUC	British Columbia Utilities Commission
mboe/d	thousands of barrels of oil equivalent per day	CER	Canadian Energy Regulator
mmboe/d	millions of barrels of oil equivalent per day	FERC	United States Federal Energy Regulatory Commission
MMcf/d	millions of cubic feet per day	ICA	Interstate Commerce Act of 1887 (United States)
bcf/d	billions of cubic feet per day	NEB	National Energy Board
km	kilometer	NGA	Natural Gas Act of 1938 (United States)
		PHMSA	Pipeline and Hazardous Material Safety Administration
		IAAC	Impact Assessment Agency of Canada


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 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:
PGI			60 percent interest in Pembina Gas Infrastructure Inc., a premier gas processing entity in Western Canada serving customers throughout the Montney and Duvernay trends from central Alberta to northeast British Columbia.
Veresen Midstream			Prior to August 15, 2022, Pembina owned a 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. On August 15, 2022, Pembina contributed its equity interest in Veresen Midstream to PGI, resulting in Pembina holding a 60 percent interest indirectly through its investment in PGI.
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 proposed floating LNG facility in Kitimat, British Columbia, Canada


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


December 31, 2021	15,678	2,517	(3,920)	28	14,303	60	14,363
Total comprehensive income
Earnings	—	—	2,728	—	2,728	—	2,728
Other comprehensive income (Note 13)	—	—	—	336	336	—	336




Total comprehensive income	—	—	2,728	336	3,064	—	3,064
Transactions with shareholders of the Company (Note 9)

Part VI.1 tax on preferred shares	—	(7)	—	—	(7)	—	(7)
Repurchase of common shares	(152)	—	(97)	—	(249)	—	(249)


Share-based payment transactions	316	—	—	—	316	—	316
Dividends declared – common	—	—	(1,050)	—	(1,050)	—	(1,050)
Dividends declared – preferred	—	—	(94)	—	(94)	—	(94)

Total transactions with shareholders of the Company	164	(7)	(1,241)	—	(1,084)	—	(1,084)

September 30, 2022	15,842	2,510	(2,433)	364	16,283	60	16,343



December 31, 2020	15,644	2,946	(3,637)	2	14,955	60	15,015
Total comprehensive income
Earnings	—	—	1,162	—	1,162	—	1,162
Other comprehensive income (Note 13)	—	—	—	8	8	—	8


Total comprehensive income	—	—	1,162	8	1,170	—	1,170
Transactions with shareholders of the Company (Note 9)

Part VI.1 tax on preferred shares	—	(7)	—	—	(7)	—	(7)

Preferred shares redemption	—	(420)	—	—	(420)	—	(420)
Share-based payment transactions	26	—	—	—	26	—	26
Dividends declared – common	—	—	(1,040)	—	(1,040)	—	(1,040)
Dividends declared – preferred	—	—	(102)	—	(102)	—	(102)

Total transactions with shareholders of the Company	26	(427)	(1,142)	—	(1,543)	—	(1,543)

September 30, 2021	15,670	2,519	(3,617)	10	14,582	60	14,642


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







Balance at December 31, 2021	456	9,279	9,384	2,084	915	22,118
Additions and transfers	21	620	142	52	(391)	444
Disposition (Note 5)	(1)	(475)	(2,440)	(104)	(20)	(3,040)

Change in decommissioning provision	—	(20)	(100)	(21)	—	(141)
Other	(1)	(55)	(81)	(9)	(14)	(160)
Foreign exchange	6	71	30	—	—	107
Transfers to assets held for sale	—	—	(112)	(1)	(1)	(114)
Balance at September 30, 2022	481	9,420	6,823	2,001	489	19,214

Depreciation




Balance at December 31, 2021	26	2,015	1,421	463	—	3,925

Depreciation	4	145	167	59	—	375
Disposition (Note 5)	—	(85)	(384)	(38)	—	(507)
Other	—	(36)	(32)	(4)	—	(72)
Transfers to assets held for sale	—	—	(28)	—	—	(28)
Balance at September 30, 2022	30	2,039	1,144	480	—	3,693

Carrying amounts
Balance at December 31, 2021	430	7,264	7,963	1,621	915	18,193
Balance at September 30, 2022	451	7,381	5,679	1,521	489	15,521


		Intangible Assets
($ millions)	Goodwill	Purchase and Sale Contracts and Other	Customer Relationships(1)	Total	Total Goodwill & Intangible Assets
Cost







Balance at December 31, 2021	4,693	288	1,861	2,149	6,842
Additions	—	38	—	38	38

Disposition (Note 5)	(153)	(23)	(66)	(89)	(242)
Foreign exchange adjustments	20	1	56	57	77

Balance at September 30, 2022	4,560	304	1,851	2,155	6,715

Amortization






Balance at December 31, 2021	—	189	415	604	604
Amortization	—	6	62	68	68


Disposition (Note 5)	—	(8)	(22)	(30)	(30)
Foreign exchange adjustments	—	1	8	9	9
Balance at September 30, 2022	—	188	463	651	651

Carrying amounts

Balance at December 31, 2021	4,693	99	1,446	1,545	6,238
Balance at September 30, 2022	4,560	116	1,388	1,504	6,064


($ millions)			August 15, 2022


Cash and cash equivalents			167
Trade receivables and other			145
Inventory			18
Property, plant and equipment (Note 3)			2,533

Intangible assets and goodwill (Note 4)			212

Derivative financial instruments (Note 14)			113
Total assets			3,188
Trade payables and other			72
Decommissioning provision (Note 8)			20
Contract liabilities (Note 10)			92

Deferred tax liabilities			514
Total liabilities			698


	Ownership Interest (percent)		Share of Profit from Equity Accounted Investees		Investments in Equity Accounted Investees
			9 Months Ended September 30
($ millions)	September 30, 2022	December 31, 2021	2022	2021	September 30, 2022	December 31, 2021
Alliance	50	50	125	81	2,673	2,686
Aux Sable	42.7 - 50	42.7 - 50	103	44	405	377
Ruby(1)	—	—	—	13	—	—
Veresen Midstream(2)	—	45	51	57	—	1,349
PGI(3)	60	—	2	—	4,186	—

Cedar LNG	49.9	49.9	—	—	146	130
Other(4)	50 - 75	50 - 75	1	3	88	80
			282	198	7,498	4,622




($ millions)			As at August 15, 2022

Current assets			853
Non-current assets			6,648



Current liabilities			1,163
Non-current liabilities			2,483
Allocated to PGI assets and liabilities			3,855
Goodwill			328
Pembina's cost of investment in PGI			4,183


				Carrying Value
($ millions)	Authorized at September 30, 2022	Nominal Interest Rate	Year of Maturity	September 30, 2022	December 31, 2021

Loans and borrowings
Senior unsecured credit facilities(1)(3)(4)	2,862	4.32(2)	Various(1)	339	907






Senior unsecured medium-term notes series 2	450	3.77	2022	450	450
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	499
Senior unsecured medium-term notes series 7	600	3.71	2026	602	602
Senior unsecured medium-term notes series 8	650	2.99	2024	649	648
Senior unsecured medium-term notes series 9	550	4.74	2047	542	542
Senior unsecured medium-term notes series 10	650	4.02	2028	658	660
Senior unsecured medium-term notes series 11	800	4.75	2048	840	841
Senior unsecured medium-term notes series 12	650	3.62	2029	653	654
Senior unsecured medium-term notes series 13	700	4.54	2049	712	712
Senior unsecured medium-term notes series 14	600	2.56	2023	600	599
Senior unsecured medium-term notes series 15	600	3.31	2030	598	597
Senior unsecured medium-term notes series 16	400	4.67	2050	397	397
Senior unsecured medium-term notes series 17	500	3.53	2031	497	497
Senior unsecured medium-term notes series 18	500	4.49	2051	497	497
Senior unsecured medium-term notes series 3A	—	5.05	2022	—	50




Total loans and borrowings				10,026	10,645
Less current portion loans and borrowings				(1,050)	(1,000)
Total non-current loans and borrowings				8,976	9,645
Subordinated hybrid notes
Subordinated notes, series 1	600	4.80	2081	595	594


($ millions)			2022
Balance at January 1			412
Unwinding of discount rate			12
Change in rates			(185)

Disposition (Note 5)			(20)


Change in cost estimates and other			16


Balance at September 30			235


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





Balance at December 31, 2021	550	15,678



Share-based payment transactions	7	316
Repurchased	(5)	(152)
Balance at September 30, 2022	552	15,842


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




Balance at December 31, 2021	105	2,517



Part VI.1 tax	—	(7)
Balance at September 30, 2022	105	2,510



	9 Months Ended September 30, 2022			12 Months Ended December 31, 2021
($ millions)	Take-or-Pay	Other Contract Liabilities	Total Contract Liabilities	Take-or-Pay	Other Contract Liabilities	Total Contract Liabilities
Opening balance	3	288	291	3	289	292
Additions (net in the period)	14	60	74	—	64	64

Disposition (Note 5)	(2)	(90)	(92)	—	—	—
Revenue recognized from contract liabilities(1)	—	(61)	(61)	—	(65)	(65)

Closing balance	15	197	212	3	288	291
Less current portion(2)	(15)	(55)	(70)	(3)	(68)	(71)
Ending balance	—	142	142	—	220	220


3 Months Ended September 30, 2022	Pipelines(1)	Facilities	Marketing & New Ventures(2)	Corporate & Inter-segment Eliminations	Total
($ millions)
Revenue from external customers	608	192	1,979	—	2,779
Inter-segment revenue	37	122	—	(159)	—
Total revenue(3)	645	314	1,979	(159)	2,779
Operating expenses	175	132	—	(82)	225
Cost of goods sold, including product purchases	—	4	1,824	(79)	1,749
Depreciation and amortization included in operations	97	27	12	1	137
Cost of sales	272	163	1,836	(160)	2,111
Realized (gain) loss on commodity-related derivative financial instruments	—	(3)	22	—	19
Share of profit from equity accounted investees	39	15	69	—	123
Unrealized loss (gain) on commodity-related derivative financial instruments	—	3	(105)	—	(102)
Gross profit	412	166	295	1	874
Depreciation included in general and administrative	—	—	—	9	9
Other general and administrative	15	1	9	42	67
Other expense (income)	13	1	14	(1)	27


Gain on Pembina Gas Infrastructure Transaction (Note 5)	—	(1,110)	—	—	(1,110)
Reportable segment results from operating activities	384	1,274	272	(49)	1,881
Net finance costs	7	4	20	109	140
Reportable segment earnings (loss) before tax	377	1,270	252	(158)	1,741
Capital expenditures	75	36	7	13	131
Contributions to equity accounted investees	—	17	7	—	24