Pembina Pipeline Corp 6-K, filed May 4, 2023

Pembina Pipeline Corp (PBA)

6-K 2023-05-04 For: 2023-03-31

View Original

Added on April 09, 2026

About this 6-K

Pembina Pipeline Corp filed this 6-K on May 4, 2023.

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


		PEMBINA PIPELINE CORPORATION



Date:	May 4, 2023	By:	/s/ Cameron J. Goldade
			Name: Cameron J. Goldade
			Title: Senior Vice President & Chief Financial Officer


Exhibit Number						Document Description

99.1						Q1 2023 Management's Discussion and Analysis & Financial Statements
99.2						CEO Certificate
99.3						CFO Certificate


REPORT TO SHAREHOLDERS
First Quarter 2023

MANAGEMENT'S DISCUSSION AND ANALYSIS


Table of Contents

1. About Pembina									2
2. Financial & Operating Overview									3
3. Segment Results									5
4. Liquidity & Capital Resources									17
5. Share Capital									20
6. Capital Expenditures									22
7. Selected Quarterly Information									23
8. Selected Equity Accounted Investee Information									26
9. Other									27
10. Accounting Policies & Estimates									29

11. Non-GAAP & Other Financial Measures									30
12. Abbreviations									33
13. Forward-Looking Statements & Information									35


($ millions, except where noted)	2023	2022	Change


Revenue	2,297	3,038	(741)
Net revenue(1)	946	1,154	(208)

Gross profit	672	857	(185)
Earnings	369	481	(112)
Earnings per common share – basic and diluted (dollars)	0.61	0.81	(0.20)

Cash flow from operating activities	458	655	(197)
Cash flow from operating activities per common share – basic (dollars)	0.83	1.19	(0.36)
Adjusted cash flow from operating activities(1)	634	700	(66)
Adjusted cash flow from operating activities per common share – basic (dollars)(1)	1.15	1.27	(0.12)
Capital expenditures	137	179	(42)
Adjusted EBITDA(1)	947	1,005	(58)
Total volumes (mboe/d)(2)	3,188	3,369	(181)


Changes in Results for the Three Months Ended March 31


Revenue	▼	$741 million decrease. Lower revenue in Marketing & New Ventures primarily due to a decrease in prices across the crude oil complex and 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 and now reflected in share of profit from equity accounted investees ("share of profit") and lower recoverable costs. These are partially offset by higher Pipeline revenue mainly on the Peace Pipeline system and Cochin Pipeline. On January 18, 2023, an unplanned outage occurred on the Northern Pipeline system (“Northern Pipeline system outage”), resulting in an impact to consolidated revenue of $37 million. Service on the Northern Pipeline system resumed on February 23, 2023 at a reduced operating pressure.
Cost of goods sold	▲	$533 million decrease, largely due to lower crude oil and NGL market prices in Marketing & New Ventures.
Operating expenses	▼	$7 million increase, primarily due to higher power costs in Pipelines, the majority of which are recoverable, as a result of the higher power pool price during the quarter, as well as an impact of $17 million resulting from the Northern Pipeline system outage, partially offset by lower Facilities operating expenses primarily due to the operating expenses from the field-based gas processing assets contributed in connection with the PGI Transaction now being reflected in share of profit, coupled with lower recoverable costs at Empress.
Depreciation and amortization included in operations	▲	$21 million decrease, primarily due to the contributed field-based gas processing assets now being accounted for under equity accounting by Pembina for its investment in PGI.
Share of profit from equity accounted investees	●	Consistent with the prior period. Lower share of profit from Aux Sable as a result of lower NGL prices and re-contracting in the fourth quarter of 2022 was largely offset by contributions from PGI following the PGI Transaction.
Realized (gain) loss on commodity-related derivatives	▲	$71 million positive variance, primarily due to realized gains on NGL-based derivative instruments driven by the change in NGL market prices during the period compared to losses in the first quarter of 2022.
Unrealized loss (gain) on commodity-related derivatives	▼	$59 million negative variance, primarily due to NGL-based derivative contracts maturing in the period.
General and administrative	▲	$15 million decrease, primarily due to lower long-term incentive costs driven by the change in Pembina's share price in the first quarter of 2023 compared to the first quarter of 2022, partially offset by higher information technology-related maintenance costs.
Other (income) expense	▲	$14 million increase, primarily due to lower acquisition and restructuring costs recognized during the period compared to the first quarter of 2022, partially offset by a gain on the initial recognition of a lease in Pipelines in the first quarter of 2022.


Net finance costs	●	Consistent with the prior period.
Current tax expense	▲	$22 million decrease, primarily due to lower current period earnings and the tax impact of the PGI Transaction.

Deferred tax expense	▲	$24 million decrease, primarily due to lower current period earnings and the tax impact of the PGI Transaction.

Cash flow from operating activities	▼	$197 million decrease, primarily driven by a decrease in the change in non-cash working capital due mainly to the Ruby settlement and lower operating results, as well as higher share-based compensation payments, partially offset by a decrease in taxes paid and higher distributions from equity accounted investees.
Adjusted cash flow from operating activities(1)	▼	$66 million decrease, largely 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 current tax expense and accrued share-based payments.
Adjusted EBITDA(1)	▼	$58 million decrease, primarily due to lower net revenue from Marketing & New Ventures and Facilities, partially offset by higher adjusted EBITDA from equity accounted investees, due to the contributions from PGI which outweighed the lower contributions from Aux Sable and Ruby. Additionally, the first quarter of 2023 had realized gains on commodity-related derivatives compared to losses recognized during the first quarter of 2022, as well as higher Pipeline revenue and lower long-term incentive costs. The Northern Pipeline system outage had an impact on consolidated adjusted EBITDA of $54 million in the period.

Total volumes (mboe/d)(2)	▼	181 mboe/d decrease, largely driven by the disposition of Pembina's interest in certain Facilities assets at Empress in the fourth quarter of 2022, lower volumes due to the Northern Pipeline system outage (decrease of 132 mboe/d) and from Ruby, partially offset by the recognition of volumes in Facilities following the PGI Transaction and higher volumes on certain Pipeline systems resulting from increased upstream activity and third-party outages in the first quarter of 2022. Volumes include 490 mboe/d (2022: 294 mboe/d) related to equity accounted investees.


	3 Months Ended March 31
	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	2,467	376		525	2,493	361	521
Facilities	721	135		298	876	250	281
Marketing & New Ventures	—	120		169	—	217	267
Corporate	—	(156)		(45)	—	(195)	(64)
Total	3,188	475		947	3,369	633	1,005


Change in Results
Conventional revenue(1)(2)	▲	Increase largely due to higher volumes on the Peace Pipeline system resulting from increased upstream activity, higher recoverable project costs, and higher tolls, partially offset by lower revenue due to the Northern Pipeline system outage. Refer to the "Financial & Operating Overview - Results Overview" section for further details on the Northern Pipeline system outage.
Transmission revenue(1)(2)	▲	Increase primarily due to the higher U.S. dollar exchange rate and higher tolls on the Cochin Pipeline, higher volumes on the Vantage Pipeline due to third-party outages during the first quarter of 2022, and higher recoverable costs at the Alberta Ethane Gathering System ("AEGS").
Oil Sands revenue(1)(2)	▼	Decrease primarily due to lower revenue related to recoverable project costs on the Horizon Pipeline system, partially offset by higher recoverable power costs.
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 quarter, combined with costs associated with the Northern Pipeline system outage, partially offset by lower geotechnical costs primarily related to the Western Pipeline.

Share of profit from equity accounted investees	●	Consistent with the prior period.
Reportable segment earnings before tax	▲	Increase largely due to higher volumes and higher recoverable project costs on the Peace Pipeline system and higher revenues from the Cochin Pipeline, Vantage Pipeline, and at AEGS, partially offset by the impacts of the Northern Pipeline system outage and lower revenue related to recoverable project costs on the Horizon Pipeline system.
Adjusted EBITDA(3)	●	Consistent with the prior period. Due to the same items impacting reportable segment earnings before tax, discussed above, largely offset by lower adjusted EBITDA from Ruby. Included in adjusted EBITDA is $77 million (2022: $76 million) related to Alliance and nil (2022: $15 million) related to Ruby.
Volumes (mboe/d)(4)	▼	Decrease largely driven by lower volumes due to the Northern Pipeline system outage and from Ruby, partially offset by higher volumes on the Peace Pipeline system resulting from increased upstream activity, combined with higher volumes at AEGS and on the Vantage Pipeline due to third-party outages in the first quarter of 2022. Volumes include 147 mboe/d (2022: 146 mboe/d) related to Alliance and nil (2022: 57 mboe/d) related to Ruby.
Distributions from equity accounted investees	▼	$70 million (2022: $87 million) from Alliance. The decrease is due to the re-financing of debt in the fourth quarter of 2021 which provided an incremental distribution in the first quarter of 2022.


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 construction progressed at several locations in the first quarter of 2023. Three pump stations are expected to enter service throughout 2023.


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 part of the PGI Transaction. The revenue from these assets is included in share of profit. This is combined with lower recoverable costs as a result of the commissioning of the Empress Cogeneration Facility and 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"), both of which occurred in the fourth quarter of 2022. This decrease in recoverable costs was accompanied by a corresponding reduction in operating expenses, as discussed below. Additionally, there were lower volumes at Younger resulting from the Northern Pipeline system outage.
NGL Services revenue(1)(2)	▼	Decrease primarily due to lower supply volumes at the Redwater Complex resulting from the Northern Pipeline system outage, coupled with lower terminalling revenue.
Operating expenses(1)	▲	Decrease largely due to the PGI Transaction which resulted in operating expenses for the formally wholly-owned field-based gas processing assets now being accounted for in share of profit, as well as reduced operating expenses resulting from the commissioning of the Empress Cogeneration Facility and the disposition of Pembina's interest in the E1 and E6 assets, discussed above.
Depreciation and amortization included in operations	▲	Decrease primarily due to the contributed field-based gas processing assets now being accounted for under equity accounting by Pembina for its investment in PGI.

Realized and unrealized gain on commodity-related derivatives	▼	The change is due to the transfer of the commodity-related derivatives from Pembina to PGI as part of the contributed field-based gas processing assets.
Share of profit from equity accounted investees	▲	Increase primarily due to the contributions from PGI's gas processing assets, partially offset by interest expense on long-term debt, depreciation resulting from the PGI assets recorded at fair value, and income tax expense, compared to the contributions in the first quarter of 2022 when Pembina owned a 45 percent interest in Veresen Midstream.
Reportable segment earnings before tax	▼	Decrease primarily due to lower contribution from Gas Services as a result of the PGI Transaction, which involved a change in ownership of Pembina's formerly wholly-owned field-based gas processing assets and commodity-related derivatives, combined with lower supply volumes at the Redwater Complex and lower terminalling revenue, partially offset by increased share of profit from PGI and lower depreciation.
Adjusted EBITDA(3)	▲	Increase primarily due to adjusted EBITDA from PGI due to the contributions from certain PGI gas processing assets, including the former Energy Transfer Canada plants and the Dawson Assets, partially offset by lower contribution from Gas Services and lower supply volumes at the Redwater Complex. Included in adjusted EBITDA is nil (2022: $54 million) related to Veresen Midstream and $172 million (2022: nil) related to PGI.

Volumes (mboe/d)(4)	▼	Decrease primarily due to the disposition of Pembina's interest in the E1 and E6 assets in exchange for a processing agreement that provides Pembina the right to first priority for gas processing at all Plains-operated assets at Empress. Additionally, lower volumes at the Redwater Complex and Younger resulting from the Northern Pipeline system outage, partially offset by the volumes from PGI, primarily at the former Energy Transfer Canada plants and on the Dawson assets. Volumes include 343 mboe/d (2022: nil) related to PGI and nil (2022: 91 mboe/d) related to Veresen Midstream.
Distributions from equity accounted investees	▲	$120 million (2022: nil) from PGI, $1 million (2022: $1 million) from Fort Corp, and no distributions (2022: $34 million) from Veresen Midstream. The increase in distributions is attributed to the contributions made by PGI's gas processing assets.


RFS IV
Capital Budget: $460 million	In-service Date(2): First half of 2026	Status: Recently Announced
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.


Change in Results


Net revenue(1)(2)	▼	Decrease largely due to lower NGL margins as a result of 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 $21 million gain (2022: $25 million loss) on NGL-based derivative instruments due to the change in NGL market prices during the first quarter of 2023.
Unrealized loss on commodity-related derivatives	●	Consistent unrealized losses relating primarily to NGL-based derivative contracts maturing in the period.


Share of (loss) 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.
Reportable segment earnings before tax	▼	Decrease largely due to lower margins on NGL and crude oil sales, coupled with lower marketed NGL volumes and lower contribution from Aux Sable, partially offset by realized gains on commodity-related derivatives for the quarter compared to losses recognized during the first quarter of 2022.
Adjusted EBITDA(2)	▼	Decrease largely due to the same items impacting reportable segment earnings before tax, discussed above. Included in adjusted EBITDA is $4 million (2022: $28 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: 34 mboe/d) related to Aux Sable.
Distributions from equity accounted investees	▼	$8 million (2022: $33 million) from Aux Sable. Decrease largely due to the same factors impacting share of profit from equity accounted investees discussed above.


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 first quarter of 2022.
General and administrative	▲	Decrease primarily due to lower long-term incentive costs driven by the change in Pembina's share price in the first quarter of 2023 compared to the first quarter of 2022, partially offset by higher information technology-related maintenance costs.
Other (income) expense	▲	Change from other expense to income is primarily due to lower acquisition and restructuring costs recognized during the period compared to the first quarter of 2022.
Net finance costs	●	Consistent with the prior period.
Reportable segment loss before tax	▲	Increase primarily due to lower acquisition costs, long-term incentive costs, and restructuring costs, coupled with shared service revenue, discussed above, partially offset by higher information technology-related maintenance costs.
Adjusted EBITDA(2)	▲	Increase largely due to the same items impacting reportable segment loss before tax, discussed above, excluding acquisition and restructuring costs.


($ millions)	March 31, 2023	December 31, 2022

Working capital(1)	(1,214)	(696)
Variable rate debt(2)(3)
Senior unsecured credit facilities	872	771
Variable rate bank debt swapped to fixed	(338)	(338)
Total variable rate loans and borrowings outstanding (weighted average interest rate of 6.1% (2022: 5.9%))	534	433
Fixed rate debt(2)
Senior unsecured medium-term notes	9,200	9,200
Variable rate bank debt swapped to fixed	338	338
Total fixed rate loans and borrowings outstanding (weighted average interest rate of 3.9% (2022: 3.9%))	9,538	9,538
Total loans and borrowings outstanding	10,072	9,971
Cash and unutilized debt facilities	2,079	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)	890	101	173	144	472
Long-term debt(3)	16,343	1,721	1,494	2,924	10,204

Construction commitments(4)	810	354	305	151	—

Other	721	190	142	93	296
Total contractual obligations	18,764	2,366	2,114	3,312	10,972


			o Form 20-F			x Form 40-F



Issued and outstanding (thousands)(1)			April 28, 2023
Common shares			550,384
Stock options			12,126
Stock options exercisable			8,706
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
	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2
Volumes(1)(2)
Pipelines
Conventional Pipelines	900	1,024	977	937	897	959	918	892
Transmission Pipelines	594	593	577	564	621	616	595	685
Oil Sands Pipelines	973	976	977	975	975	996	1,050	1,050
Facilities
Gas Services	563	588	686	664	675	677	660	662
NGL Services	158	211	207	204	201	189	188	211

Total	3,188	3,392	3,424	3,344	3,369	3,437	3,411	3,500
Marketing & New Ventures
Marketed NGL	194	193	184	176	206	193	177	173


($ millions)	2023	2022				2021
	Q1	Q4	Q3	Q2	Q1	Q4	Q3	Q2












Opening balance	3	15	27	25	3	21	35	23
Revenue deferred	49	48	55	51	48	43	48	47
Revenue recognized	(26)	(60)	(68)	(46)	(26)	(61)	(62)	(35)
Transfers to liabilities related to assets held for sale	—	—	3	(3)	—	—	—	—
Disposition	—	—	(2)	—	—	—	—	—
Ending take-or-pay contract liability balance	26	3	15	27	25	3	21	35


($ millions)(1)	March 31, 2023	December 31, 2022

Pipelines(2)	350	672
Facilities(3)	2,747	2,694
Marketing & New Ventures	—	—
Total	3,097	3,366


	3 Months Ended March 31

($ millions, except per share amounts)	2023	2022
Cash flow from operating activities	458	655
Cash flow from operating activities per common share – basic (dollars)	0.83	1.19
Add (deduct):
Change in non-cash operating working capital	199	39
Current tax expense	(99)	(121)
Taxes paid, net of foreign exchange	47	152
Accrued share-based payment expense	(20)	(39)
Share-based compensation payment	77	45
Preferred share dividends paid	(28)	(31)
Adjusted cash flow from operating activities	634	700
Adjusted cash flow from operating activities per common share – basic (dollars)	1.15	1.27


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.
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 the PDH/PP Facility which was cancelled in the third quarter of 2022
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, 2022	15,793	2,208	(2,613)	341	15,729	60	15,789
Total comprehensive income (loss)
Earnings	—	—	369	—	369	—	369
Other comprehensive loss (Note 11)	—	—	—	(15)	(15)	—	(15)




Total comprehensive income (loss)	—	—	369	(15)	354	—	354
Transactions with shareholders of the Company (Note 7)

Part VI.1 tax on preferred shares	—	(2)	—	—	(2)	—	(2)



Share-based payment transactions	2	—	—	—	2	—	2
Dividends declared – common	—	—	(359)	—	(359)	—	(359)
Dividends declared – preferred	—	—	(28)	—	(28)	—	(28)

Total transactions with shareholders of the Company	2	(2)	(387)	—	(387)	—	(387)

March 31, 2023	15,795	2,206	(2,631)	326	15,696	60	15,756



December 31, 2021	15,678	2,517	(3,920)	28	14,303	60	14,363
Total comprehensive income (loss)
Earnings	—	—	481	—	481	—	481
Other comprehensive loss (Note 11)	—	—	—	(30)	(30)	—	(30)


Total comprehensive income (loss)	—	—	481	(30)	451	—	451
Transactions with shareholders of the Company (Note 7)

Part VI.1 tax on preferred shares	—	(3)	—	—	(3)	—	(3)
Repurchase of common shares	(17)	—	(11)	—	(28)	—	(28)


Share-based payment transactions	101	—	—	—	101	—	101
Dividends declared – common	—	—	(347)	—	(347)	—	(347)
Dividends declared – preferred	—	—	(31)	—	(31)	—	(31)

Total transactions with shareholders of the Company	84	(3)	(389)	—	(308)	—	(308)

March 31, 2022	15,762	2,514	(3,828)	(2)	14,446	60	14,506


($ 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	—	80	8	12	31	131


Change in decommissioning provision	—	(1)	1	—	—	—


Foreign exchange and other	—	(8)	(2)	(12)	—	(22)

Balance at March 31, 2023	481	9,566	6,956	2,014	398	19,415

Depreciation




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

Depreciation	2	48	44	18	—	112

Other	—	(4)	(1)	—	—	(5)

Balance at March 31, 2023	34	2,131	1,228	502	—	3,895

Carrying amounts
Balance at December 31, 2022	449	7,408	5,764	1,530	367	15,518
Balance at March 31, 2023	447	7,435	5,728	1,512	398	15,520


	Ownership Interest (percent)		Share of Profit from Equity Accounted Investees		Investments in Equity Accounted Investees
			3 Months Ended March 31
($ millions)	March 31, 2023	December 31, 2022	2023	2022	March 31, 2023	December 31, 2022
Alliance	50	50	35	38	2,572	2,609
Aux Sable	42.7 - 50	42.7 - 50	(1)	22	351	360

Veresen Midstream(1)	—	—	—	22	—	—
PGI	60	60	47	—	4,117	4,158

Cedar LNG(3)	49.9	49.9	—	—	172	167
Other(2)	50 - 75	50 - 75	1	3	89	88
			82	85	7,301	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	—	1,164
Non-current liabilities	2,834	13	2,847
Allocated to PGI assets and liabilities	3,284	—	3,284
Goodwill	899	—	899
Pembina's cost of investment in PGI	4,183	—	4,183



($ millions)	Authorized at March 31, 2023	Nominal Interest Rate	Year of Maturity	March 31, 2023	December 31, 2022
Variable rate debt(1)
Senior unsecured credit facilities(2)(3)(4)	2,858	6.10(5)	Various(2)	872	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	450	3.54	2025	450	450
Senior unsecured medium-term notes series 6	500	4.24	2027	500	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	600	2.56	2023	600	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
Total fixed rate loans and borrowings outstanding				9,200	9,200
Deferred financing costs				34	34
Total loans and borrowings				10,106	10,005
Less current portion loans and borrowings				(1,250)	(600)
Total non-current loans and borrowings				8,856	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)	—	2

Balance at March 31, 2023	550	15,795


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




Balance at December 31, 2022	93	2,208



Part VI.1 tax	—	(2)
Balance at March 31, 2023	93	2,206


	3 Months Ended March 31, 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)	23	9	32	2	57	59

Disposition	—	—	—	(2)	(90)	(92)
Revenue recognized from contract liabilities(1)	—	(35)	(35)	—	(64)	(64)

Closing balance	26	165	191	3	191	194
Less current portion(2)	(26)	(31)	(57)	(3)	(53)	(56)
Ending balance	—	134	134	—	138	138


3 Months Ended March 31, 2023	Pipelines(1)	Facilities	Marketing & New Ventures(2)	Corporate & Inter-segment Eliminations	Total
($ millions)
Revenue from external customers(3)	600	128	1,558	11	2,297
Inter-segment revenue	28	80	—	(108)	—
Total revenue(4)	628	208	1,558	(97)	2,297
Operating expenses	172	80	—	(52)	200
Cost of goods sold, including product purchases	—	—	1,409	(58)	1,351
Depreciation and amortization included in operations	99	34	12	1	146
Cost of sales	271	114	1,421	(109)	1,697
Realized gain on commodity-related derivative financial instruments	—	—	(24)	—	(24)
Share of profit (loss) from equity accounted investees	35	48	(1)	—	82
Unrealized loss on commodity-related derivative financial instruments	—	—	34	—	34
Gross profit	392	142	126	12	672
Depreciation included in general and administrative	—	—	—	9	9
Other general and administrative	10	5	9	59	83
Other income	(1)	—	(4)	(1)	(6)



Reportable segment results from operating activities	383	137	121	(55)	586
Net finance costs	7	2	1	101	111
Reportable segment earnings (loss) before tax	376	135	120	(156)	475
Capital expenditures	106	20	3	8	137
Contributions to equity accounted investees	—	32	6	—	38


3 Months Ended March 31, 2022	Pipelines(1)	Facilities	Marketing & New Ventures(2)	Corporate & Inter-segment Eliminations	Total

($ millions)
Revenue from external customers(3)	529	238	2,271	—	3,038
Inter-segment revenue	44	119	—	(163)	—
Total revenue(4)	573	357	2,271	(163)	3,038
Operating expenses	141	134	—	(82)	193
Cost of goods sold, including product purchases	—	—	1,967	(83)	1,884
Depreciation and amortization included in operations	99	55	11	2	167
Cost of sales	240	189	1,978	(163)	2,244
Realized (gain) loss on commodity-related derivative financial instruments	—	(7)	54	—	47
Share of profit from equity accounted investees	40	24	21	—	85
Unrealized (gain) loss on commodity-related derivative financial instruments	—	(60)	35	—	(25)
Gross profit	373	259	225	—	857
Depreciation included in general and administrative	—	—	—	10	10
Other general and administrative	14	7	10	66	97
Other (income) expense	(9)	—	—	17	8



Reportable segment results from operating activities	368	252	215	(93)	742
Net finance costs (income)	7	2	(2)	102	109
Reportable segment earnings before tax	361	250	217	(195)	633
Capital expenditures	114	30	29	6	179
Contributions to equity accounted investees	—	13	6	—	19


($ 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	(11)	—	—	(11)
Other comprehensive gain (loss) resulting from hedging activities(1)	1	(5)	—	(4)


Balance at March 31, 2023	297	26	3	326


	March 31, 2023				December 31, 2022

	Carrying Value	Fair Value(1)			Carrying Value	Fair Value(1)
($ millions)		Level 1	Level 2	Level 3		Level 1	Level 2	Level 3
Financial assets carried at fair value
Derivative financial instruments(2)	94	—	54	40	129	—	92	37








Financial liabilities carried at fair value
Derivative financial instruments(2)	59	—	52	7	64	—	57	7
Contingent consideration(3)	43	—	6	37	49	—	12	37
Financial liabilities carried at amortized cost



Long-term debt(4)	10,701	—	9,836	—	10,600	—	9,590	—



($ millions)			2023
Level 3 derivative net asset at January 1			30

Included in gain (loss) on commodity-related derivative financial instruments in earnings			3




Level 3 derivative net asset at March 31			33


For the 3 Months Ended March 31 ($ millions)	2023	2022

Services provided(1)	101	43
Services received	10	3

As at:	March 31, 2023	December 31, 2022
Advances to related parties(2)	2	22
Trade receivables and other	34	42
Trade payables and other(3)	13	150



HEAD OFFICE Pembina Pipeline Corporation Suite 4000, 585 - 8th Avenue SW Calgary, Alberta T2P 1G1 AUDITORS KPMG LLP Chartered Professional Accountants Calgary, Alberta TRUSTEE, REGISTRAR & TRANSFER AGENT Computershare Trust Company of Canada Suite 600, 530 - 8th Avenue SW Calgary, Alberta T2P 3S8 1.800.564.6253 STOCK EXCHANGE Pembina Pipeline Corporation Toronto Stock Exchange listing symbols for: COMMON SHARES PPL PREFERRED SHARES PPL.PR.A, PPL.PR.C, PPL.PR.E, PPL.PR.G, PPL.PR.I, PPL.PR.O, PPL.PR.Q, PPL.PR.S, PPL.PF.A, PPL.PF.B and PPL.PF.E New York Stock Exchange listing symbol for: COMMON SHARES PBA INVESTOR INQUIRIES PHONE 403.231.3156 FAX 403.237.0254 TOLL FREE 1.855.880.7404 EMAIL investor-relations@pembina.com WEBSITE www.pembina.com