Pembina Pipeline Corp 6-K, filed Aug 3, 2023

Pembina Pipeline Corp (PBA)

6-K 2023-08-03 For: 2023-06-30

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Added on April 09, 2026

About this 6-K

Pembina Pipeline Corp filed this 6-K on August 3, 2023.

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		PEMBINA PIPELINE CORPORATION



Date:	August 3, 2023	By:	/s/ Cameron J. Goldade
			Name: Cameron J. Goldade
			Title: Senior Vice President & Chief Financial Officer


Exhibit Number						Document Description

99.1						Q2 2023 Management's Discussion and Analysis & Financial Statements
99.2						CEO Certificate
99.3						CFO Certificate


REPORT TO SHAREHOLDERS
Second Quarter 2023

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									23
5. Share Capital									27
6. Capital Expenditures									29
7. Selected Quarterly Information									30
8. Selected Equity Accounted Investee Information									33
9. Other									34
10. Accounting Policies & Estimates									36

11. Non-GAAP & Other Financial Measures									37
12. Abbreviations									41
13. Forward-Looking Statements & Information									43


($ millions, except where noted)	2023	2022	Change


Revenue	2,070	3,095	(1,025)
Net revenue(1)	858	1,020	(162)

Gross profit	659	711	(52)
Adjusted EBITDA(1)	823	849	(26)

Earnings	363	418	(55)
Earnings per common share – basic (dollars)	0.60	0.70	(0.10)
Earnings per common share – diluted (dollars)	0.60	0.69	(0.09)
Cash flow from operating activities	653	604	49
Cash flow from operating activities per common share – basic (dollars)	1.19	1.09	0.10
Adjusted cash flow from operating activities(1)	606	683	(77)
Adjusted cash flow from operating activities per common share – basic (dollars)(1)	1.10	1.23	(0.13)
Capital expenditures	123	152	(29)
Total volumes (mboe/d)(2)	3,187	3,344	(157)


Changes in Results for the Three Months Ended June 30


Revenue						$1.0 billion decrease. Lower revenue in Marketing & New Ventures primarily due to a decrease in prices across the crude oil complex, lower NGL prices and lower crude oil volumes, combined with lower revenue in Facilities largely due to revenue from the field-based gas processing assets contributed to PGI in connection with the PGI Transaction now being reflected in share of profit from equity accounted investees ("Share of Profit") (second quarter of 2022, included $118 million in revenue related to the assets contributed to PGI) and lower recoverable costs. Additionally, during the second quarter of 2023, volumes on certain assets in Pipelines were temporarily curtailed due to the wildfires in Alberta and British Columbia ("Wildfires"), resulting in a negative impact to consolidated revenue of $23 million. Also, on February 23, 2023, service on the Northern Pipeline system resumed at reduced operating pressures, following the unplanned outage which occurred in the first quarter of 2023 ("Northern Pipeline system outage"), resulting in a negative impact to consolidated revenue of $17 million. Full operating pressure resumed mid-May on the Northern Pipeline system. These results were partially offset by higher tolls on the Cochin Pipeline and the Peace Pipeline system.
Cost of goods sold						$863 million decrease, primarily due to lower crude oil and NGL market prices, as well as lower crude oil volumes in Marketing & New Ventures.
Operating expenses						$22 million decrease, primarily due to lower Facilities operating expenses primarily due to the PGI Transaction (second quarter of 2022, included $32 million in operating expenses related to the assets contributed to PGI), coupled with lower operating expenses at Empress and lower recoverable geotechnical costs related to the Western Pipeline, partially offset by the costs associated with the Northern Pipeline system outage.













Cash flow from operating activities						$49 million increase, primarily driven by an increase in the change in non-cash working capital, higher distributions from equity accounted investees, and lower taxes paid, partially offset by earnings adjusted for items not involving cash and a decrease in payments collected through contract liabilities.
Adjusted cash flow from operating activities(1)						$77 million decrease, largely due to the change in cash flow from operating activities, excluding the change in non-cash working capital and taxes paid, combined with higher current tax expense, partially offset by lower accrued share-based payment expense.
Adjusted EBITDA(1)						$26 million decrease, primarily due to the impact in the Pipelines and Facilities Divisions resulting from the Wildfires ($24 million) and Northern Pipeline system outage ($23 million). These are combined with lower net revenue from Facilities and Marketing & New Ventures, as well as $21 million associated with, a combination of, an insurance contract provision related to the parental guarantee and letters of credit for Cedar LNG, a deferred recognition of flow-through charges related to capital integrity work that resulted in a revenue timing difference, and a final arbitration award issued against CKPC. These factors were partially offset by realized gains on commodity-related derivatives during the second quarter of 2023 compared to losses recognized during the second quarter of 2022 and higher adjusted EBITDA from equity accounted investees, due to the contributions from PGI which outweighed the lower contributions from Alliance and Aux Sable.

Total volumes (mboe/d)(2)						157 mboe/d decrease, largely driven by the disposition of Pembina's interest in certain Facilities assets at Empress in the fourth quarter of 2022, the impacts of the Wildfires and the Northern Pipeline system outage which resulted in lower volumes of 58 mboe/d and 57 mboe/d, respectively, partially offset by higher volumes at the Alberta Ethane Gathering System ("AEGS") due to third-party outages in the second quarter of 2022 and the volumes from PGI's gas processing assets following the PGI Transaction.


Changes in Results for the Six Months Ended June 30


Revenue						$1.8 billion decrease. Lower revenue in Marketing & New Ventures primarily due to a decrease in prices across the crude oil complex and lower crude oil volumes, as well as lower NGL prices and marketed NGL volumes, combined with lower revenue in Facilities largely due to revenue from the field-based gas processing assets contributed to PGI now being reflected in Share of Profit (2022 included $231 million in revenue related to the assets contributed to PGI) and lower recoverable costs. In addition, the Northern Pipeline system outage and the Wildfires had a negative impact on consolidated revenue of $54 million and $23 million, respectively. These results were partially offset by higher Pipelines revenue mainly on the Cochin Pipeline and the Peace Pipeline system.
Cost of goods sold						$1.4 billion decrease, primarily due to lower crude oil and NGL market prices, as well as lower crude oil and marketed NGL volumes in Marketing & New Ventures.
Operating expenses						$15 million decrease, primarily due to lower Facilities operating expenses primarily due to the PGI Transaction (2022 included $61 million in operating expenses related to the assets contributed to PGI) and lower recoverable costs at Empress, combined with lower recoverable geotechnical costs related to the Western Pipeline, partially offset with higher power costs in Pipelines, the majority of which are recoverable, as a result of the higher power pool price during the quarter, and the $23 million in costs associated with the Northern Pipeline system outage.












Cash flow from operating activities						$148 million decrease, primarily driven by a decrease in earnings adjusted for items not involving cash, a decrease in the change in non-cash working capital, higher share-based compensation payments, and a decrease in payments collected through contract liabilities, partially offset by lower taxes paid and higher distributions from equity accounted investees.
Adjusted cash flow from operating activities(1)						$143 million decrease, primarily due to the same items impacting cash flow from operating activities, discussed above, excluding the change in non-cash working capital, taxes paid, and share-based compensation payments, partially offset by lower accrued share-based payment expense.
Adjusted EBITDA(1)						$84 million decrease, primarily due to the impact in the Pipelines and Facilities Divisions resulting from the Northern Pipeline system outage ($77 million) and the Wildfires ($24 million). These are combined with lower net revenue from Facilities and Marketing & New Ventures, as well as $21 million associated with, a combination of, an insurance contract provision related to the parental guarantee and letters of credit for Cedar LNG, a deferred recognition of flow-through charges related to capital integrity work that resulted in a revenue timing difference, and a final arbitration award issued against CKPC. These factors were partially offset by realized gains on commodity-related derivatives during the first six months of 2023 compared to losses recognized during the first six months of 2022. Additionally, adjusted EBITDA from equity accounted investees increased, primarily due to the contributions from PGI which outweighed the lower contributions from Aux Sable, Alliance, and Ruby, while general and administrative expenses decreased due to lower long-term incentive costs.

Total volumes (mboe/d)(2)						172 mboe/d decrease, largely driven by the disposition of Pembina's interest in certain Facilities assets at Empress in the fourth quarter of 2022, impacts of the Northern Pipeline system outage and the Wildfires which resulted in lower volumes of 92 mboe/d and 29 mboe/d, respectively, combined with lower volumes from Ruby, partially offset by the volumes from PGI's gas processing assets following the PGI Transaction and higher volumes on certain Pipeline systems and third-party outages in 2022.


	3 Months Ended June 30
	2023		2022
($ 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	2,438	350		501	2,476	382	523
Facilities	749	153		272	868	147	277
Marketing & New Ventures	—	115		96	—	135	103
Corporate	—	(161)		(46)	—	(149)	(54)
Total	3,187	457		823	3,344	515	849

	6 Months Ended June 30
	2023		2022
($ 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	2,452	726		1,026	2,486	743	1,044
Facilities	734	288		570	872	397	558
Marketing & New Ventures	—	235		265	—	352	370
Corporate	—	(317)		(91)	—	(344)	(118)
Total	3,186	932		1,770	3,358	1,148	1,854


Change in Results



Pipelines revenue(1)						Consistent with prior period. Higher volumes on certain of Pembina's Pipelines assets and higher tolls on the Cochin Pipeline and the Peace Pipeline system, were largely offset by lower revenue due to the impacts of the Wildfires, the impact of third-party outages on certain of Pembina's Pipelines assets, the Northern Pipeline system outage, as well as a deferred recognition of flow-through charges related to capital integrity work on the Peace Pipeline system that resulted in a revenue timing difference.
Operating expenses(1)						Consistent with prior period. Higher recoverable power costs, as a result of the higher power pool price during the period, as well as costs associated with the Northern Pipeline system outage, were largely offset by lower recoverable geotechnical costs related to the Western Pipeline.

Share of profit from equity accounted investees						Decrease primarily due to lower revenues from Alliance as the second quarter of 2022 included the sale of linepack inventory, combined with seasonal contracts being replaced by firm contracts at lower regulated rates and lower interruptible volumes driven by a narrower AECO-Chicago natural gas price differential.
Reportable segment earnings before tax						Decrease primarily due to lower contributions from Alliance, discussed above, the impacts of the Wildfires, the impact of third-party outages on certain of Pembina's Pipelines assets, and the Northern Pipeline system outage, as well as a deferred recognition of flow-through capital charges on the Peace Pipeline system, partially offset by higher volumes on certain of Pembina's Pipelines assets and higher tolls on the Cochin Pipeline and the Peace Pipeline system.
Adjusted EBITDA(3)						Decrease due to the same items impacting reportable segment earnings before tax, discussed above. Included in adjusted EBITDA is $61 million (2022: $85 million) related to Alliance.
Volumes (mboe/d)(4)						Decrease largely due to lower volumes on the Peace Pipeline system and Drayton Valley Pipeline mainly due to the impacts of the Wildfires, lower volumes related to the Northern Pipeline system outage, combined with lower interruptible volumes at Alliance, discussed above, partially offset by higher volumes at AEGS due to third-party outages in the second quarter of 2022. Volumes include 132 mboe/d (2022: 142 mboe/d) related to Alliance.


Change in Results



Pipelines revenue(1)						Increase largely due to higher recoverable costs on various systems, higher tolls and the higher U.S. dollar exchange rate on revenues from the Cochin Pipeline, as well as higher tolls and volumes on the Peace Pipeline system, and higher volumes on the Vantage Pipeline due to third-party outages in 2022, partially offset by lower revenue due to the Northern Pipeline system outage and the Wildfires, as well as a deferred recognition of flow-through charges related to capital integrity work on the Peace Pipeline system that resulted in a revenue timing difference.
Operating expenses(1)						Increase largely due to higher recoverable power costs, as a result of the higher power pool price during the period, as well as costs associated with the Northern Pipeline system outage, partially offset by lower recoverable geotechnical costs primarily related to the Western Pipeline.

Share of profit from equity accounted investees						Decrease primarily due to lower revenues from Alliance as the second quarter of 2022 included the sale of linepack inventory, combined with seasonal contracts being replaced by firm contracts at lower regulated rates.
Reportable segment earnings before tax						Decrease primarily due to lower contributions from Alliance, higher operating expenses associated with the Northern Pipeline system outage, as well as a deferred recognition of flow-through capital charges on the Peace Pipeline system, partially offset by higher revenue, as discussed above.
Adjusted EBITDA(3)						Decrease due to the same items impacting reportable segment earnings before tax, discussed above, as well as no adjusted EBITDA from Ruby since the first quarter of 2022. Refer to the "Selected Equity Accounted Investee Information" section for further details on Ruby. Included in adjusted EBITDA is $138 million (2022: $161 million) related to Alliance and nil (2022: $15 million) related to Ruby.
Volumes (mboe/d)(4)						Decrease largely due to lower volumes related to the Northern Pipeline system outage and from Ruby, partially offset by higher volumes at AEGS and on the Vantage Pipeline due to third-party outages in the second quarter of 2022 and higher volumes on the Peace Pipeline system. Volumes include 140 mboe/d (2022: 144 mboe/d) related to Alliance and nil (2022: 28 mboe/d) related to Ruby.


Significant Projects			In-service Date
Phase VII Peace Pipeline Expansion			June 2022
Phase IX Peace Pipeline Expansion			December 2022


Phase VIII Peace Pipeline Expansion
Capital Budget: $530 million	In-service Date: First half of 2024	Status: On time, trending under 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. Pipe manufacturing is complete and mainline construction activities have commenced. One pump station has been completed, with two additional pump stations expected to be completed in the second half of 2023.


Changes in Results


Facilities revenue(1)						Decrease largely due to the change in ownership of the majority of Pembina's wholly-owned field-based gas processing assets as part of the PGI Transaction. The revenue from these assets is included in Share of Profit (second quarter of 2022, included $118 million in revenue related to the assets contributed to PGI). This is combined with lower recoverable costs mainly as a result of the commissioning of the Empress Cogeneration Facility which occurred in the fourth quarter of 2022 and lower supply volumes at the Redwater Complex and at Younger resulting from the Northern Pipeline system outage.
Operating expenses(1)						Decrease largely due to the PGI Transaction which resulted in operating expenses for the formerly wholly-owned field-based gas processing assets now being accounted for in Share of Profit (second quarter of 2022, included $32 million in operating expenses related to the assets contributed to PGI), as well as reduced operating expenses resulting from the commissioning of the Empress Cogeneration Facility, discussed above.
Depreciation and amortization included in operations						Decrease primarily due to an asset retirement in the second quarter of 2022 and the field-based gas processing assets contributed to PGI as part of the PGI Transaction now being accounted for under equity accounting by Pembina for its investment in PGI.

Realized and unrealized (gain) loss on commodity-related derivatives						The commodity-related derivatives were transferred as part of the field-based gas processing assets contributed to PGI on August 15, 2022.
Share of profit from equity accounted investees						Increase primarily due to the high earnings of the former Energy Transfer Canada plants and the Dawson Assets, partially offset by income tax expense, depreciation resulting from the PGI assets recorded at fair value, and interest on long-term debt, compared to the contributions in the second quarter of 2022 when Pembina owned a 45 percent interest in Veresen Midstream, as well as the impacts of the Wildfires.
Reportable segment earnings before tax						Consistent with prior period. High Share of Profit from PGI and lower depreciation, were largely offset by lower contributions resulting from the change in ownership of the majority of Pembina's wholly-owned field-based gas processing assets and commodity-related derivatives as part of the PGI Transaction.
Adjusted EBITDA(3)						Consistent with prior period. Lower contributions resulting from the change in ownership of Pembina's formerly wholly-owned field-based gas processing assets and realized commodity-related derivatives as part of the PGI Transaction, were largely offset by the strong performance of certain PGI gas processing assets, as discussed above. Included in adjusted EBITDA is $141 million (2022: nil) related to PGI and nil (2022: $50 million) related to Veresen Midstream.

Volumes (mboe/d)(4)						Decrease primarily due to the disposition of Pembina's interest in the assets comprising the Empress I Plant, Empress I Expansion Plant, and the Empress VI Plant (collectively "E1 and E6") in the fourth quarter of 2022, in exchange for a processing agreement that provides Pembina the right to first priority for gas processing at all Plains Midstream-operated assets at Empress. In addition, the Northern Pipeline system outage resulted in lower volumes at Younger and at the Redwater Complex, partially offset by the volumes from PGI, primarily at the former Energy Transfer Canada plants and on the Dawson Assets. Volumes include 337 mboe/d (2022: nil) related to PGI and nil (2022: 89 mboe/d) related to Veresen Midstream.


RFS IV
Capital Budget: $460 million	In-service Date(2): First half of 2026	Status: On time, on budget
RFS IV is a 55,000 bpd propane-plus fractionator at the existing Redwater fractionation and storage complex (the "Redwater Complex"). The project includes additional rail loading capacity and will leverage the design, engineering, and operating best practices of its existing facilities. With the addition of RFS IV, the fractionation capacity at the Redwater Complex will total 256,000 bpd. Engineering activities are progressing and the ordering of long-lead equipment commenced in the second quarter of 2023.


Change in Results


Net revenue(1)(2)						Decrease largely due to lower margins on crude oil resulting from the lower prices across the crude oil complex, coupled with lower NGL margins due to lower propane and butane prices.
Realized (gain) loss on commodity-related derivatives						The realized gain is primarily due to a $7 million gain (2022: $12 million loss) on NGL-based derivative instruments and $5 million in realized gains related to renewable power purchase agreements and crude oil-based derivatives (2022: $47 million loss).
Unrealized gain on commodity-related derivatives						Unrealized gain on commodity-related derivatives primarily due to the change in the forward price for propane and gains on newly added contracts, partially offset by the change in the forward price for power and contracts maturing in the period.



Reportable segment earnings before tax						Decrease largely due to lower margins on crude oil and NGL sales, as well as costs related to an insurance contract provision associated with the parental guarantee and letters of credit for Cedar LNG and a final arbitration award issued against CKPC, partially offset by higher gains on commodity-related derivatives for the quarter compared to the second quarter of 2022 and lower net finance costs related to gains on non-commodity related derivatives compared to losses in the second quarter of 2022.
Adjusted EBITDA(2)						Decrease largely due to a lower adjusted EBITDA contribution from Aux Sable as a result of lower NGL prices, as well as the costs impacting reportable segment earnings before tax, as discussed above, related to Cedar LNG and CKPC, partially offset by realized gains on commodity-related derivatives, compared to losses in the second quarter of 2022, which more than offset the decrease in net revenue. Included in adjusted EBITDA is $21 million (2022: $41 million) related to Aux Sable.

Volumes (mboe/d)(3)						Marketed NGL volumes decreased largely due to reduced ethane sales as a result of lower supply volumes from the Redwater Complex following the Northern Pipeline system outage. Revenue volumes include 34 mboe/d (2022: 39 mboe/d) related to Aux Sable.


Change in Results


Net revenue(1)(2)						Decrease largely due to lower NGL margins resulting from lower propane and butane prices and lower marketed NGL volumes, discussed below, coupled with lower margins on crude oil resulting from the lower prices across the crude oil complex.
Realized (gain) loss on commodity-related derivatives						The realized gain is primarily due to a $28 million gain (2022: $37 million loss) on NGL-based derivative instruments and $8 million in realized gains related to renewable power purchase agreements and crude oil-based derivatives (2022: $76 million loss).
Unrealized gain on commodity-related derivative financial instruments						Primarily due to unrealized gains on NGL-based derivatives due to the change in forward prices and newly added contracts, offset by unrealized losses due to the change in the forward price for power and contracts maturing in the period.
Share of profit from equity accounted investees						Decrease largely due to lower revenues at Aux Sable as a result of lower NGL prices and re-contracting in the fourth quarter of 2022, partially offset by an unrealized loss on commodity-related derivatives during the first six months of 2022.


Reportable segment earnings before tax						Decrease largely due to lower margins on NGL and crude oil sales and lower marketed NGL volumes, combined with lower contribution from Aux Sable, as well as costs related to an insurance contract provision associated with the parental guarantee and letters of credit for Cedar LNG and a final arbitration award issued against CKPC, partially offset by gains on commodity-related derivatives for the period compared to losses recognized during 2022 and lower net finance costs related to gains on non-commodity related derivatives compared to losses in the first six months of 2022.
Adjusted EBITDA(2)						Decrease largely due to the same items impacting reportable segment earnings before tax, as discussed above, excluding the unrealized loss on commodity-related derivatives and lower net finance costs, combined with lower adjusted EBITDA from Aux Sable as a result of lower NGL prices and re-contracting in 2022. Included in adjusted EBITDA is $25 million (2022: $69 million) related to Aux Sable.

Volumes (mboe/d)(3)						Marketed NGL volumes decreased largely due to reduced ethane and butane sales as a result of lower supply volumes from the Redwater Complex following the Northern Pipeline system outage. Revenue volumes include 34 mboe/d (2022: 36 mboe/d) related to Aux Sable.


			o Form 20-F			x Form 40-F


($ millions)	June 30, 2023	December 31, 2022

Working capital(1)	(630)	(696)
Variable rate debt(2)
Senior unsecured credit facilities	881	771
Interest rate swapped debt	(31)	(338)


Total variable rate loans and borrowings outstanding (weighted average interest rate of 6.0% (2022: 5.9%))	850	433
Fixed rate debt(2)
Senior unsecured medium-term notes	9,100	9,200
Interest rate swapped debt	31	338


Total fixed rate loans and borrowings outstanding (weighted average interest rate of 4.0% (2022: 3.9%))	9,131	9,538
Total loans and borrowings outstanding	9,981	9,971
Cash and unutilized debt facilities	2,057	2,181
Subordinated hybrid notes (weighted average interest rate of 4.8% (2022: 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)	870	100	172	143	455
Long-term debt(3)	16,242	1,152	1,929	3,026	10,135

Construction commitments(4)	844	314	504	26	—

Other commitments related to lease contracts(5)	473	43	81	76	273
Transportation and processing(6)	96	40	31	14	11
Funding commitments(7)	61	53	8	—	—
Software, cloud computing and other	36	13	20	2	1

Total contractual obligations	18,622	1,715	2,745	3,287	10,875



(millions, except as noted)	June 30, 2023	December 31, 2022
Number of common shares repurchased for cancellation (thousands)	1,197	7,154
Average price per share	$41.76	$46.55
Total cost(1)	50	333


Change in Results
Shared service revenue						Pertains to fixed fee income related to shared service agreements with joint ventures following the PGI Transaction. $5 million was netted against general and administrative in the second quarter of 2022.
General and administrative						Consistent with prior period. Higher consulting fees, salaries and wages, and information technology-related maintenance costs were largely offset by lower long-term incentive costs driven by Pembina's performance relative to peers, and the change in Pembina's share price in the second quarter of 2023 compared to the second quarter of 2022.
Other expense (income)						The change is primarily due to acquisition fees. In the second quarter of 2022, the acquisition fees associated with the PGI Transaction, which were previously expensed, were capitalized as it was concluded that PGI was an investment in a joint venture. Apart from this, other expenses were consistent with the prior period.



Income tax expense						Lower in the second quarter of 2023 as a result of lower earnings compared to the same period in 2022.
Reportable segment loss before tax						Decrease largely due to the change in acquisition fees, discussed above, partially offset by shared service revenue.
Adjusted EBITDA(2)						Increase largely due to the same items impacting reportable segment loss before tax, discussed above, excluding the change in acquisition fees.



Issued and outstanding (thousands)(1)			July 31, 2023
Common shares			549,198
Stock options			12,007
Stock options exercisable			8,593
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			14,972
Series 22 Class A Preferred Shares			1,028
Series 25 Class A Preferred Shares			10,000


(mboe/d)	2023		2022				2021
	Q2	Q1	Q4	Q3	Q2	Q1	Q4	Q3
Volumes(1)(2)
Pipelines
Conventional Pipelines	881	900	1,024	977	937	897	959	918
Transmission Pipelines	580	594	593	577	564	621	616	595
Oil Sands Pipelines	977	973	976	977	975	975	996	1,050
Facilities
Gas Services	564	563	588	686	664	675	677	660
NGL Services	185	158	211	207	204	201	189	188

Total	3,187	3,188	3,392	3,424	3,344	3,369	3,437	3,411
Marketing & New Ventures
Marketed NGL	163	194	193	184	176	206	193	177


($ millions)(1)	June 30, 2023	December 31, 2022

Pipelines(2)	346	672
Facilities(3)	2,400	2,694
Marketing & New Ventures	—	—
Total	2,746	3,366


	3 Months Ended June 30		6 Months Ended June 30

($ millions, except per share amounts)	2023	2022	2023	2022
Cash flow from operating activities	653	604	1,111	1,259
Cash flow from operating activities per common share – basic (dollars)	1.19	1.09	2.02	2.28
Add (deduct):
Change in non-cash operating working capital	(11)	103	188	142
Current tax expense	(78)	(54)	(177)	(175)
Taxes paid, net of foreign exchange	66	86	113	238
Accrued share-based payment expense	7	(24)	(13)	(63)
Share-based compensation payment	—	—	77	45
Preferred share dividends paid	(31)	(32)	(59)	(63)
Adjusted cash flow from operating activities	606	683	1,240	1,383
Adjusted cash flow from operating activities per common share – basic (dollars)	1.10	1.23	2.25	2.50


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 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, and also include revenue volumes from Pembina's equity accounted investees.


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	BCER	British Columbia Energy Regulator
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. On January 13, 2023, pursuant to the Ruby Subsidiary Plan, Ruby Pipeline Holding Company L.L.C sold its equity interest in the Ruby Subsidiary. As a result, Pembina ceased to have an interest in the Ruby Pipeline.
Grand Valley			75 percent interest in Grand Valley 1 Limited Partnership wind farm
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, and transportation contracts on Alliance
CKPC			50 percent interest in Canada Kuwait Petrochemical Corporation and the PDH/PP Facility which was cancelled in the third quarter of 2022
Cedar LNG			49.9 percent interest in Cedar LNG Partners LP and 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, 2022	15,793	2,208	(2,613)	341	15,729	60	15,789
Total comprehensive income (loss)
Earnings	—	—	732	—	732	—	732
Other comprehensive loss (Note 11)	—	—	—	(91)	(91)	—	(91)




Total comprehensive income (loss)	—	—	732	(91)	641	—	641
Transactions with shareholders of the Company (Note 7)

Part VI.1 tax on preferred shares	—	(5)	—	—	(5)	—	(5)
Repurchase of common shares	(34)	—	(16)	—	(50)	—	(50)


Share-based payment transactions	4	—	—	—	4	—	4
Dividends declared – common	—	—	(726)	—	(726)	—	(726)
Dividends declared – preferred	—	—	(59)	—	(59)	—	(59)

Total transactions with shareholders of the Company	(30)	(5)	(801)	—	(836)	—	(836)

June 30, 2023	15,763	2,203	(2,682)	250	15,534	60	15,594



December 31, 2021	15,678	2,517	(3,920)	28	14,303	60	14,363
Total comprehensive income (loss)
Earnings	—	—	899	—	899	—	899
Other comprehensive income	—	—	—	78	78	—	78


Total comprehensive income	—	—	899	78	977	—	977
Transactions with shareholders of the Company (Note 7)

Part VI.1 tax on preferred shares	—	(5)	—	—	(5)	—	(5)
Repurchase of common shares	(56)	—	(38)	—	(94)	—	(94)


Share-based payment transactions	307	—	—	—	307	—	307
Dividends declared – common	—	—	(696)	—	(696)	—	(696)
Dividends declared – preferred	—	—	(63)	—	(63)	—	(63)

Total transactions with shareholders of the Company	251	(5)	(797)	—	(551)	—	(551)

June 30, 2022	15,929	2,512	(3,818)	106	14,729	60	14,789


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







Balance at December 31, 2022	481	9,495	6,949	2,014	367	19,306
Additions and transfers	—	86	34	13	112	245


Change in decommissioning provision	—	3	17	5	—	25


Foreign exchange and other	(2)	(27)	(11)	(15)	—	(55)

Balance at June 30, 2023	479	9,557	6,989	2,017	479	19,521

Depreciation




Balance at December 31, 2022	32	2,087	1,185	484	—	3,788

Depreciation	3	97	88	37	—	225

Other	—	(6)	(2)	(1)	—	(9)

Balance at June 30, 2023	35	2,178	1,271	520	—	4,004

Carrying amounts
Balance at December 31, 2022	449	7,408	5,764	1,530	367	15,518
Balance at June 30, 2023	444	7,379	5,718	1,497	479	15,517


	Ownership Interest (percent)		Share of Profit from Equity Accounted Investees		Investments in Equity Accounted Investees
			6 Months Ended June 30
($ millions)	June 30, 2023	December 31, 2022	2023	2022	June 30, 2023	December 31, 2022
Alliance	50	50	54	85	2,500	2,609
Aux Sable	42.7 - 50	42.7 - 50	12	32	343	360

Veresen Midstream(1)	—	—	—	39	—	—
PGI	60	60	113	—	4,051	4,158

Cedar LNG(2)	49.9	49.9	—	—	178	167
Other(3)	50 - 75	50 - 75	—	3	90	88
			179	159	7,162	7,382




As at August 15, 2022	Previously reported	Adjustments	Updated
($ millions)	in Q4 2022

Current assets	641	(6)	635
Non-current assets	6,641	19	6,660
Current liabilities	1,164	(2)	1,162
Non-current liabilities	2,834	16	2,850
Allocated to PGI assets and liabilities	3,284	(1)	3,283
Goodwill	899	1	900
Pembina's cost of investment in PGI	4,183	—	4,183



($ millions)	Authorized at June 30, 2023	Nominal Interest Rate	Year of Maturity	June 30, 2023	December 31, 2022
Variable rate debt(1)
Senior unsecured credit facilities(2)(3)(4)	2,881	6.33(5)	Various(2)	881	771
Fixed rate debt(1)
Senior unsecured medium-term notes series 3	450	4.75	2043	450	450
Senior unsecured medium-term notes series 4	600	4.81	2044	600	600
Senior unsecured medium-term notes series 5	550	3.54	2025	550	450
Senior unsecured medium-term notes series 6	600	4.24	2027	600	500
Senior unsecured medium-term notes series 7	600	3.71	2026	600	600
Senior unsecured medium-term notes series 8	650	2.99	2024	650	650
Senior unsecured medium-term notes series 9	550	4.74	2047	550	550
Senior unsecured medium-term notes series 10	650	4.02	2028	650	650
Senior unsecured medium-term notes series 11	800	4.75	2048	800	800
Senior unsecured medium-term notes series 12	650	3.62	2029	650	650
Senior unsecured medium-term notes series 13	700	4.54	2049	700	700
Senior unsecured medium-term notes series 14	—	2.56	2023	—	600
Senior unsecured medium-term notes series 15	600	3.31	2030	600	600
Senior unsecured medium-term notes series 16	400	4.67	2050	400	400
Senior unsecured medium-term notes series 17	500	3.53	2031	500	500
Senior unsecured medium-term notes series 18	500	4.49	2051	500	500
Senior unsecured medium-term notes series 19	300	5.72	2026	300	—
Total fixed rate loans and borrowings outstanding				9,100	9,200
Deferred financing costs				25	34
Total loans and borrowings				10,006	10,005
Less current portion loans and borrowings				(650)	(600)
Total non-current loans and borrowings				9,356	9,405
Subordinated hybrid notes
Subordinated notes, series 1	600	4.80	2081	595	595


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






Balance at December 31, 2022	550	15,793



Share-based payment transactions(1)	—	4
Repurchased	(1)	(34)
Balance at June 30, 2023	549	15,763


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




Balance at December 31, 2022	93	2,208



Part VI.1 tax	—	(5)
Balance at June 30, 2023	93	2,203


	6 Months Ended June 30, 2023			12 Months Ended December 31, 2022

($ millions)	Take-or-Pay	Other Contract Liabilities	Total Contract Liabilities	Take-or-Pay	Other Contract Liabilities	Total Contract Liabilities
Opening balance	3	191	194	3	288	291
Additions (net in the period)	37	25	62	2	57	59

Disposition	—	—	—	(2)	(90)	(92)
Revenue recognized from contract liabilities(1)	—	(41)	(41)	—	(64)	(64)

Closing balance	40	175	215	3	191	194
Less current portion(2)	(40)	(42)	(82)	(3)	(53)	(56)
Ending balance	—	133	133	—	138	138


3 Months Ended June 30, 2023	Pipelines(1)	Facilities	Marketing & New Ventures(2)	Corporate & Inter-segment Eliminations	Total
($ millions)
Revenue from external customers(3)	576	126	1,357	11	2,070
Inter-segment revenue	32	94	—	(126)	—
Total revenue(4)	608	220	1,357	(115)	2,070
Operating expenses	160	90	—	(61)	189
Cost of goods sold, including product purchases	—	—	1,277	(65)	1,212
Depreciation and amortization included in operations	101	41	11	2	155
Cost of sales	261	131	1,288	(124)	1,556
Realized gain on commodity-related derivative financial instruments	—	—	(14)	—	(14)
Share of profit from equity accounted investees	20	69	8	—	97
Unrealized gain on commodity-related derivative financial instruments	—	—	(34)	—	(34)
Gross profit	367	158	125	9	659
Depreciation included in general and administrative	1	—	—	10	11
Other general and administrative	7	3	7	56	73
Other expense	1	—	7	1	9



Reportable segment results from operating activities	358	155	111	(58)	566
Net finance costs (income)	8	2	(4)	103	109
Reportable segment earnings (loss) before tax	350	153	115	(161)	457


Capital expenditures	77	33	—	13	123
Contributions to equity accounted investees	1	1	9	—	11


3 Months Ended June 30, 2022	Pipelines(1)	Facilities	Marketing & New Ventures(2)	Corporate & Inter-segment Eliminations	Total

($ millions)
Revenue from external customers(3)	559	236	2,300	—	3,095
Inter-segment revenue	45	124	—	(169)	—
Total revenue(4)	604	360	2,300	(169)	3,095
Operating expenses	156	141	—	(86)	211
Cost of goods sold, including product purchases	—	2	2,157	(84)	2,075
Depreciation and amortization included in operations	96	80	11	1	188
Cost of sales	252	223	2,168	(169)	2,474
Realized (gain) loss on commodity-related derivative financial instruments	—	(10)	59	—	49
Share of profit from equity accounted investees	48	20	6	—	74
Unrealized loss (gain) on commodity-related derivative financial instruments	—	9	(74)	—	(65)
Gross profit	400	158	153	—	711
Depreciation included in general and administrative	—	—	—	10	10
Other general and administrative	10	5	10	55	80
Other income	—	(1)	(3)	(14)	(18)



Reportable segment results from operating activities	390	154	146	(51)	639
Net finance costs	8	7	11	98	124
Reportable segment earnings (loss) before tax	382	147	135	(149)	515


Capital expenditures(5)	75	48	17	12	152
Contributions to equity accounted investees	—	—	6	—	6


6 Months Ended June 30, 2022	Pipelines(1)	Facilities	Marketing & New Ventures(2)	Corporate & Inter-segment Eliminations	Total

($ millions)
Revenue from external customers(3)	1,088	474	4,571	—	6,133
Inter-segment revenue	89	243	—	(332)	—
Total revenue(4)	1,177	717	4,571	(332)	6,133
Operating expenses	297	275	—	(168)	404
Cost of goods sold, including product purchases	—	2	4,124	(167)	3,959
Depreciation and amortization included in operations	195	135	22	3	355
Cost of sales	492	412	4,146	(332)	4,718
Realized (gain) loss on commodity-related derivative financial instruments	—	(17)	113	—	96
Unrealized gain on commodity-related derivative financial instruments	—	(51)	(39)	—	(90)
Share of profit from equity accounted investees	88	44	27	—	159


Gross profit	773	417	378	—	1,568
Depreciation included in general and administrative	—	—	—	20	20
Other general and administrative	24	12	20	121	177
Other (income) expense	(9)	(1)	(3)	3	(10)


Reportable segment results from operating activities	758	406	361	(144)	1,381
Net finance costs	15	9	9	200	233
Reportable segment earnings (loss) before tax	743	397	352	(344)	1,148


Capital expenditures(5)	189	78	46	18	331
Contributions to equity accounted investees	—	13	12	—	25


($ millions)	Currency Translation Reserve	Cash Flow Hedge Reserve	Pension and other Post-Retirement Benefit Plan Adjustments(2)	Total









Balance at December 31, 2022	307	31	3	341
Other comprehensive loss before hedging activities	(94)	—	—	(94)
Other comprehensive gain (loss) resulting from hedging activities(1)	7	(4)	—	3


Balance at June 30, 2023	220	27	3	250