Pembina secures financing to fund growth and announces plans to further expand pipeline capacity
All financial figures are in Canadian dollars unless noted otherwise. This report contains forward-looking statements and information that are based on Pembina Pipeline Corporation’s (“Pembina” or the “Company”) current expectations, estimates, projections and assumptions in light of its experience and its perception of historic trends. Actual results may differ materially from those expressed or implied by these forward-looking statements. Please see “Forward-Looking Statements & Information” in the accompanying Management’s Discussion & Analysis (“MD&A”) for more details. This report also refers to financial measures that are not defined by Generally Accepted Accounting Principles (“GAAP”), including operating margin, adjusted EBITDA, and adjusted cash flow from operating activities, that do not have standardized meanings as prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other companies. For more information about the measures which are not defined by GAAP, see “Non-GAAP Measures” of the accompanying MD&A.
CALGARY, Nov. 1, 2013 /CNW/ – On April 2, 2012, Pembina completed its acquisition of Provident Energy Ltd. (“Provident”) (the “Acquisition”). The amounts disclosed herein for the comparative nine month period ending September 30, 2012 reflect results of the post-Acquisition Pembina from April 2, 2012 together with results of legacy Pembina alone, excluding Provident, from January 1 through April 1, 2012. For further information with respect to the Acquisition, please refer to Note 4 of the Condensed Consolidated Interim Financial Statements for the period ended June 30, 2013.
Financial & Operating Overview
| ($ millions, except where noted) | 3 Months Ended September 30 |
9 Months Ended September 30 |
||||||||
| 2013 | 2012 | 2013 | 2012 | |||||||
| Revenue | 1,300.2 | 815.4 | 3,723.7 | 2,161.8 | ||||||
| Operating margin(1) | 225.8 | 177.5 | 673.4 | 454.1 | ||||||
| Gross profit | 177.2 | 102.9 | 557.8 | 366.6 | ||||||
| Earnings for the period | 71.8 | 30.7 | 256.1 | 143.7 | ||||||
| Earnings per share – basic and diluted (dollars) | 0.22 | 0.11 | 0.83 | 0.58 | ||||||
| Adjusted EBITDA(1) | 200.8 | 153.8 | 596.1 | 391.1 | ||||||
| Cash flow from operating activities | 87.3 | 130.9 | 456.5 | 220.3 | ||||||
| Adjusted cash flow from operating activities(1) | 188.7 | 133.2 | 540.1 | 321.5 | ||||||
| Adjusted cash flow from operating activities per share (dollars) (1) | 0.61 | 0.46 | 1.77 | 1.30 | ||||||
| Common share dividends declared | 129.1 | 117.3 | 375.1 | 299.2 | ||||||
| Dividends per common share (dollars) | 0.42 | 0.41 | 1.23 | 1.20 | ||||||
| (1) | Refer to “Non-GAAP Measures.” |
Third Quarter Highlights
Growth and Operational Update
Conventional Pipelines Developments
Construction of the Company’s Phase I Low Vapour Pressure Expansion (“Phase I LVP Expansion”) on its Peace Pipeline between Fox Creek and Edmonton, Alberta, is substantially complete. This expansion will provide an additional 40 mbpd of crude oil and condensate capacity on this segment by the end of November 2013.
Subsequent to the quarter end, Pembina has substantially completed construction of its Phase I NGL Expansion, which expanded NGL capacity by 52 mbpd on the Peace and Northern Pipelines, bringing total capacity on this system to 167 mbpd by the end of November 2013.
On September 16, 2013, in response to requests from area producers for firm service between Simonette and Fox Creek, Alberta, Pembina announced plans to proceed with a $115 million expansion of its Peace Pipeline System (the “Simonette Pipeline Expansion”). This expansion is expected to initially deliver approximately 40 mbpd of additional liquids to Pembina’s Fox Creek Terminal from which it will access Pembina’s previously announced Phase I and II Peace Pipeline mainline expansions to reach Edmonton area markets. The new pipeline will have a capacity of approximately 150 mbpd and is expected to be in-service in the third quarter of 2014, subject to the necessary environmental and regulatory approvals.
The Simonette Pipeline Expansion will include approximately 60 kilometres of 16-inch pipeline along the Company’s existing right-of-way, providing service to producers developing the regional Montney and Duvernay formation resource plays. Once complete, Pembina will have three pipelines in the corridor capable of segregating and shipping various grades of crude oil, condensate and NGL.
In conjunction with the Simonette Pipeline Expansion, Pembina is also installing eight clean crude oil and condensate truck unloading risers at its Fox Creek Terminal which the Company anticipates will be in-service in the fourth quarter of 2013. The addition of high-capacity truck unloading facilities will allow producers to access Edmonton area markets through the previously announced Phase I and II Peace Pipeline mainline expansions.
Pembina expects the Simonette Pipeline Expansion to support its potential Phase III Peace Pipeline mainline expansion plans by providing sufficient capacity and operational flexibility within the Simonette to Fox Creek corridor to transport substantially all future volumes nominated through its previously announced Open Season process. The Company continues to progress engineering design associated with the Open Season and is in the process of finalizing binding transportation agreements with area producers.
Gas Services Developments
On August 9, 2013, Pembina announced that it is pursuing Musreau II, a new 100 MMcf/d shallow cut gas plant with associated NGL and gas gathering pipelines near its existing Musreau facility (part of the greater Cutbank Complex). Musreau II is underpinned by long-term take-or-pay agreements with area producers. The facility is designed to handle propane-plus (C3+) and is expected to yield approximately 4.2 mbpd of NGL for transportation on Pembina’s Conventional Pipelines. Pembina has received all required regulatory and environmental approvals for Musreau II and construction is underway with a target in-service date in the first quarter of 2015.
Pembina placed its Saturn I gas plant into service in late-October and is progressing construction of the Saturn II and Resthaven gas plants.
Midstream Developments
Market demand for products and services in the Midstream space is strong for both crude oil and NGL. The capital being deployed in the Midstream business is primarily directed towards fee-for-service projects.
On September 3, 2013, Pembina announced the acquisition of a $20 million site in the Alberta Industrial Heartland featuring existing rail access and utility infrastructure to support the future development of rail, terminalling and storage facilities (the “Heartland Hub”). The Heartland Hub is a further build-out of Pembina’s larger Nexus terminal (“PNT”), servicing crude oil and diluent customers for terminalling, storage and rail.
At the same time, Pembina announced entering into a multi-year, fee-for-service agreement with a major North American refiner for provision of rail loading services for up to 40 mbpd of various crude oil grades at the Company’s Redwater facility.
Regarding Pembina’s previously announced $415 million RFS II project (a second 73 mbpd fractionator at Pembina’s Redwater site that is expected to be in-service in the fourth quarter of 2015), the Company completed land clearing during the third quarter, began washing the feed cavern for the fractionator, ordered all long-lead equipment and is progressing with construction.
Financing Activity
On July 26, 2013, Pembina closed its offering of 10,000,000 cumulative redeemable rate reset class A preferred shares, series 1 (the “Series 1 Preferred Shares”) at a price of $25.00 per share.
Subsequent to the end of the third quarter, on October 2, 2013, Pembina closed its offering of 6,000,000 cumulative redeemable rate reset class A preferred shares, series 3 (the “Series 3 Preferred Shares”) at a price of $25.00 per share.
The Company used the proceeds from the offerings to partially fund capital projects, repay amounts outstanding on Pembina’s credit facility, and for other general corporate purposes.
Transition of CEO and Organizational Changes
On September 4, 2013, the Board of Directors announced that Bob Michaleski, Pembina’s long-time Chief Executive Officer (“CEO”) plans to retire at the end of 2013 after 35 years of service with the Company. The Board also announced that Mick Dilger, Pembina’s President and Chief Operating Officer, will succeed Mr. Michaleski as CEO effective January 1, 2014, at which time he will also be appointed to the Company’s Board of Directors. Mr. Michaleski will continue to serve as a member of Pembina’s Board of Directors following his retirement as CEO.
Stu Taylor, Vice President, Gas Services, and Paul Murphy, Vice President, Conventional Pipelines, were promoted to the newly created positions of Senior Vice President, NGL & Natural Gas Facilities and Senior Vice President, Pipeline & Crude Oil Facilities, respectively. The Company believes this structure better reflects the bundled integrated services sought by Pembina’s customers.
In addition to these changes, Peter Robertson, the Company’s Chief Financial Officer also intends to retire at the end of 2014.
Summary
“During the third quarter, Pembina’s momentum of securing value-added growth projects continued at a solid pace in addition to achieving continued strong financial and operational performance,” said Bob Michaleski, Pembina’s CEO. “Looking back on what we have accomplished as we approach the end of 2013, we have seen an increase in cash flow per share of almost 70 percent in the first nine months of this year compared to the same period of 2012, giving us confidence that the Company is on track to deliver another record year of results. As I prepare to enter retirement at the end of this year and transition my duties as CEO to Mick Dilger, I feel the Company is very well-positioned for the future.”
Mick Dilger added: “Pembina currently has the largest suite of commercially secured and unrisked growth projects on its horizon than at any time in its history. I know we have the right team in place to continue driving long-term and sustainable shareholder value going forward. Both our leadership team and our employees are ready to execute on the numerous growth opportunities in front of us with an unwavering commitment to delivering safe, responsible and reliable services from our existing businesses.”
Third Quarter 2013 Conference Call & Webcast
Pembina will host a conference call on November 4, 2013 at 8 a.m. MT (10 a.m. ET) to discuss details related to the third quarter. The conference call dial-in numbers for Canada and the U.S. are 647-427-7450 or 888-231-8191. A recording of the conference call will be available for replay until November 11, 2013 at 11:59 p.m. ET. To access the replay, please dial either 416-849-0833 or 855-859-2056 and enter the password 64969171.
A live webcast of the conference call can be accessed on Pembina’s website at www.pembina.com under Investor Centre, Presentation & Events, or by entering: http://event.on24.com/r.htm?e=687077&s=1&k=6DC4D1240E58EC3AC8F8E00D3EB13632 in your web browser. Shortly after the call, an audio archive will be posted on the website for a minimum of 90 days.
MANAGEMENT’S DISCUSSION AND ANALYSIS
The following management’s discussion and analysis (“MD&A”) of the financial and operating results of Pembina Pipeline Corporation (“Pembina” or the “Company”) is dated November 1, 2013 and is supplementary to, and should be read in conjunction with, Pembina’s unaudited condensed consolidated interim financial statements for the period ended September 30, 2013 (“Interim Financial Statements”) as well as Pembina’s consolidated audited annual financial statements and MD&A for the year ending December 31, 2012 (the “Consolidated Financial Statements”). All dollar amounts contained in this MD&A are expressed in Canadian dollars unless otherwise noted.
Management is responsible for preparing the MD&A. This MD&A has been reviewed and recommended by the Audit Committee of Pembina’s Board of Directors and approved by its Board of Directors.
This MD&A contains forward-looking statements (see “Forward-Looking Statements & Information”) and refers to financial measures that are not defined by Generally Accepted Accounting Principles (“GAAP”). For more information about the measures which are not defined by GAAP, see “Non-GAAP Measures.”
On April 2, 2012, Pembina completed its acquisition of Provident Energy Ltd. (“Provident”) (the “Acquisition”). The amounts disclosed herein for the comparative nine month period ending September 30, 2012 reflect results of the post-Acquisition Pembina from April 2, 2012 together with results of legacy Pembina alone, excluding Provident, from January 1 through April 1, 2012. The results of the business acquired through the Acquisition are reported as part of the Company’s Midstream business. For further information with respect to the Acquisition, please refer to Note 4 of the Condensed Consolidated Interim Financial Statements for the period ended June 30, 2013.
About Pembina
Calgary-based Pembina Pipeline Corporation is a leading transportation and midstream service provider that has been serving North America’s energy industry for nearly 60 years. Pembina owns and operates pipelines that transport various hydrocarbon liquids including conventional and synthetic crude oil, heavy oil and oil sands products, condensate (diluent) and natural gas liquids produced in western Canada. The Company also owns and operates gas gathering and processing facilities and an oil and natural gas liquids infrastructure and logistics business. With facilities strategically located in western Canada and in natural gas liquids markets in eastern Canada and the U.S., Pembina also offers a full spectrum of midstream and marketing services that spans across its operations. Pembina’s integrated assets and commercial operations enable it to offer services needed by the energy sector along the hydrocarbon value chain.
Pembina is a trusted member of the communities in which it operates and is committed to generating value for its investors by running its businesses in a safe, environmentally responsible manner that is respectful of community stakeholders.
Strategy
Pembina’s goal is to provide highly competitive and reliable returns to investors through monthly dividends on its common shares while enhancing the long-term value of its securities. To achieve this, Pembina’s strategy is to:
Pembina is structured into four businesses: Conventional Pipelines, Oil Sands & Heavy Oil, Gas Services and Midstream, which are described in their respective sections of this MD&A.
Common Abbreviations
The following is a list of abbreviations that may be used in this MD&A:
| Measurement | Other | ||||||
| bpd | barrels per day | AECO | Alberta gas trading price | ||||
| mbpd | thousands of barrels per day | AESO | Alberta Electric Systems Operator | ||||
| mmbbls | millions of barrels | B.C. | British Columbia | ||||
| mboe/d | thousands of barrels of oil equivalent per day | DRIP | Premium Dividend™ and Dividend Reinvestment Plan | ||||
| MMcf/d | millions of cubic feet per day | Frac | Fractionation | ||||
| bcf/d | billions of cubic feet per day | IFRS | International Financial Reporting Standards | ||||
| MW/h | megawatts per hour | NGL | Natural gas liquids | ||||
| GJ | gigajoule | NYSE | New York Stock Exchange | ||||
| km | kilometre | TSX | Toronto Stock Exchange | ||||
| U.S. | United States | ||||||
| WCSB | Western Canadian Sedimentary Basin | ||||||
| WTI | West Texas Intermediate (crude oil benchmark price) | ||||||
Financial & Operating Overview
| 3 Months Ended September 30 |
9 Months Ended September 30 |
||||||||||
| ($ millions, except where noted) | 2013 | 2012 | 2013 | 2012 | |||||||
| Conventional Pipelines throughput (mbpd) | 489.1 | 443.9 | 488.8 | 448.2 | |||||||
| Oil Sands & Heavy Oil contracted capacity, end of period (mbpd) | 880.0 | 870.0 | 880.0 | 870.0 | |||||||
| Gas Services average processed volume (mboe/d) net to Pembina(1) | 48.0 | 45.8 | 48.8 | 45.8 | |||||||
| NGL sales volume (mbpd) | 98.9 | 86.7 | 105.1 | 88.6(3) | |||||||
| Total volume (mbpd) | 1,516.0 | 1,446.4 | 1,522.7 | 1,452.6 | |||||||
| Revenue | 1,300.2 | 815.4 | 3,723.7 | 2,161.8 | |||||||
| Operations | 86.6 | 69.6 | 254.9 | 185.7 | |||||||
| Cost of goods sold, including product purchases | 983.3 | 565.4 | 2,797.1 | 1,506.4 | |||||||
| Realized (loss) gain on commodity-related derivative financial instruments | (4.5) | (2.9) | 1.7 | (15.6) | |||||||
| Operating margin(2) | 225.8 | 177.5 | 673.4 | 454.1 | |||||||
| Depreciation and amortization included in operations | 46.5 | 51.6 | 120.7 | 125.8 | |||||||
| Unrealized (loss) gain on commodity-related derivative financial instruments | (2.1) | (23.0) | 5.1 | 38.3 | |||||||
| Gross profit | 177.2 | 102.9 | 557.8 | 366.6 | |||||||
| Deduct/(add) | |||||||||||
| General and administrative expenses | 29.8 | 26.9 | 88.6 | 70.2 | |||||||
| Acquisition-related and other expenses | 1.5 | 24.2 | |||||||||
| Net finance costs | 36.0 | 33.1 | 111.2 | 79.4 | |||||||
| Share of (profit) loss of investments in equity accounted investee, net of tax | (0.4) | 0.5 | 0.3 | 0.9 | |||||||
| Income tax expense | 40.0 | 10.2 | 101.6 | 48.2 | |||||||
| Earnings for the period | 71.8 | 30.7 | 256.1 | 143.7 | |||||||
| Earnings per share – basic and diluted (dollars) | 0.22 | 0.11 | 0.83 | 0.58 | |||||||
| Adjusted EBITDA(2) | 200.8 | 153.8 | 596.1 | 391.1 | |||||||
| Cash flow from operating activities | 87.3 | 130.9 | 456.5 | 220.3 | |||||||
| Cash flow from operating activities per share (dollars) | 0.28 | 0.45 | 1.50 | 0.89 | |||||||
| Adjusted cash flow from operating activities(2) | 188.7 | 133.2 | 540.1 | 321.5 | |||||||
| Adjusted cash flow from operating activities per share (dollars)(2) | 0.61 | 0.46 | 1.77 | 1.30 | |||||||
| Common share dividends declared | 129.1 | 117.3 | 375.1 | 299.2 | |||||||
| Dividends per common share (dollars) | 0.42 | 0.41 | 1.23 | 1.20 | |||||||
| Capital expenditures | 244.8 | 143.3 | 604.6 | 329.6 | |||||||
| Total enterprise value ($ billions) (2) | 13.3 | 10.6 | 13.3 | 10.6 | |||||||
| Total assets ($ billions) | 8.8 | 8.2 | 8.8 | 8.2 | |||||||
| (1) | Gas Services processing volumes converted to mboe/d from MMcf/d at 6:1 ratio. |
| (2) | Refer to “Non-GAAP Measures.” |
| (3) | Represents per day volumes since the closing of the Acquisition. |
Revenue, net of cost of goods sold, increased 27 percent to $316.9 million during the third quarter of 2013 compared to $250 million during the third quarter of 2012, primarily due to strong performance in each of Pembina’s businesses as discussed in more detail in their respective sections under “Operating Results” below, as well as returns on new capital investments. Year-to-date revenue, net of cost of goods sold, in 2013 was $926.6 million, up 41 percent from the same period last year. This increase was primarily due to improved performance in each of Pembina’s legacy businesses, returns on new capital investments as well as the impact of the Acquisition.
Operating expenses were $86.6 million during the third quarter of 2013 compared to $69.6 million in the third quarter of 2012 and $254.9 million for the nine months ended September 30, 2013 compared to $185.7 million in the same period of the prior year. The increase in operating expenses for the third quarter and first nine months of 2013 was largely due to higher variable costs in each of the Company’s legacy businesses resulting from increased volumes reflecting oil and NGL industry activity as well as additional costs associated with the growth in Pembina’s asset base primarily related to the Acquisition.
Operating margin totalled $225.8 million during the third quarter of 2013, up 27 percent from the same period last year when operating margin totalled $177.5 million. For the nine months ended September 30, 2013 operating margin was $673.4 million compared to $454.1 million for the same period of 2012. These increases were primarily due to strong performance and growth throughout Pembina’s operations, particularly from Midstream and Conventional Pipelines. The year-to-date increase was also attributable to the timing and impact of the Acquisition.
Realized and unrealized gains/losses on commodity-related derivative financial instruments resulting from Pembina’s market risk management program are primarily related to power, frac spread, and product margin derivative financial instruments (see “Market Risk Management Program” and Note 11 to the Interim Financial Statements). Pembina realized losses of $6.6 million and gains of $6.8 million on commodity-related derivative financial instruments for the three and nine months ended September 30, 2013, respectively, reflecting changes in the future NGL, natural gas and power price indices. For the comparative three and nine months ended September 30, 2012, the Company incurred losses of $25.9 million and gains of $22.7 million on commodity-related derivative financial instruments which were largely attributable to the reduction in the future NGL price indices between April 2, 2012 and September 30, 2012.
Depreciation and amortization (operational) decreased to $46.5 million during the third quarter of 2013 compared to $51.6 million during the same period in 2012. The decrease is primarily due to a re-measurement of the decommissioning provision in excess of the carrying amount of the related asset (see Note 6 to the Interim Financial Statements). For the nine months ended September 30, 2013, depreciation and amortization (operational) was $120.7 million, down from $125.8 million for the same period last year for the same reason noted above.
The increases in revenue and operating margin contributed to gross profit of $177.2 million during the third quarter and $557.8 million during the first nine months of 2013 compared to $102.9 million and $366.6 million during the corresponding periods of the prior year.
General and administrative expenses (“G&A”) of $29.8 million were incurred during the third quarter of 2013, up from $26.9 million during the third quarter of 2012 primarily due to the addition of new employees as a result of Pembina’s growth since the prior period and increased share based incentive expenses. G&A for the first nine months of 2013 was $88.6 million compared to $70.2 million for the same period of 2012. The increase for the nine month period was mainly due to the addition of new employees who joined the Company both as a result of the Company’s growth as well as through the Acquisition. In addition, every $1 change in share price is expected to change Pembina’s annual share-based incentive expense by approximately $1 million.
The Company’s earnings increased to $71.8 million ($0.22 per share) during the third quarter of 2013 compared to $30.7 million ($0.11 per share) in the same period of 2012. Earnings were $256.1 million ($0.83 per share) during the first nine months of 2013 compared to $143.7 million ($0.58 per share) during the same period of the prior year (which included significant unrealized gains on commodity derivative financial instruments). These increases were primarily due to improved operating margin offset by increased income tax expense. The year-to-date results were also impacted by the timing of the Acquisition.
Pembina generated adjusted EBITDA of $200.8 million during the third quarter of 2013 compared to $153.8 million during the third quarter of 2012. This increase was largely due to improved results from operating activities in each of Pembina’s businesses and returns on new assets and services. Adjusted EBITDA for the nine month period ended September 30, 2013 was $596.1 million compared to $391.1 million for the same period in 2012 due to strong results in each of Pembina’s legacy businesses, new assets and services having been brought on-stream, and completion of the Acquisition.
Cash flow from operating activities was $87.3 million ($0.28 per share) for the third quarter of 2013 compared to $130.9 million ($0.45 per share) for the same period in 2012. Despite higher EBITDA and earnings, cash flow from operating activities decreased primarily because of increased operating working capital. For the nine months ended September 30, 2013, cash flow from operating activities was $456.5 million ($1.50 per share) compared to $220.3 million ($0.89 per share) during the same period last year. The year-to-date increase was primarily due to improved results from operating activities and the Acquisition.
Adjusted cash flow from operating activities was $188.7 million ($0.61 per share) for the third quarter of 2013 compared to $133.2 million ($0.46 per share) during the third quarter of 2012. This increase was due to increased EBITDA and lower net interest paid. Adjusted cash flow from operating activities was $540.1 million ($1.77 per share) during the first nine months of 2013 compared to $321.5 million ($1.30 share) during the same period of last year, primarily due to stronger operating results, returns on new investments and the impact of the Acquisition.
Operating Results
| 3 Months Ended September 30 |
9 Months Ended September 30 |
||||||||||||||||
| 2013 | 2012 | 2013 | 2012 | ||||||||||||||
| ($ millions) | Net Revenue(1) |
Operating Margin(1) |
Net Revenue(1) |
Operating Margin(1) |
Net Revenue(1) |
Operating Margin(1) |
Net Revenue(1) |
Operating Margin(1) |
|||||||||
| Conventional Pipelines | 103.1 | 66.3 | 79.0 | 49.4 | 300.4 | 192.4 | 239.6 | 151.3 | |||||||||
| Oil Sands & Heavy Oil | 48.2 | 33.0 | 44.1 | 29.3 | 142.5 | 97.1 | 126.6 | 87.2 | |||||||||
| Gas Services | 31.5 | 20.8 | 23.7 | 16.6 | 87.6 | 56.9 | 65.0 | 44.7 | |||||||||
| Midstream | 134.8 | 104.8 | 103.2 | 81.6 | 396.8 | 324.7 | 224.2(2) | 169.0(2) | |||||||||
| Corporate | (0.7) | 0.9 | 0.6 | (0.7) | 2.3 | 1.9 | |||||||||||
| Total | 316.9 | 225.8 | 250.0 | 177.5 | 926.6 | 673.4 | 655.4 | 454.1 | |||||||||
| (1) | Refer to “Non-GAAP Measures.” | |
| (2) | Includes results from operations generated by the assets acquired from Provident since closing of the acquisition on April 2, 2012. |
Conventional Pipelines
| 3 Months Ended September 30 |
9 Months Ended September 30 |
|||||||||
| ($ millions, except where noted) | 2013 | 2012 | 2013 | 2012 | ||||||
| Average throughput (mbpd) | 489.1 | 443.9 | 488.8 | 448.2 | ||||||
| Revenue | 103.1 | 79.0 | 300.4 | 239.6 | ||||||
| Operations | 37.2 | 30.1 | 110.2 | 87.6 | ||||||
| Realized gain (loss) on commodity-related derivative financial instruments | 0.4 | 0.5 | 2.2 | (0.7) | ||||||
| Operating margin(1) | 66.3 | 49.4 | 192.4 | 151.3 | ||||||
| Depreciation and amortization included in operations | 6.4 | 12.0 | 5.9 | 36.1 | ||||||
| Unrealized gain (loss) on commodity-related derivative financial instruments | 0.1 | (7.1) | 2.4 | (9.8) | ||||||
| Gross profit | 60.0 | 30.3 | 188.9 | 105.4 | ||||||
| Capital expenditures | 78.6 | 34.7 | 198.9 | 99.2 | ||||||
| (1) | Refer to “Non-GAAP Measures.” |
Business Overview
Pembina’s Conventional Pipelines business comprises a well-maintained and strategically located 8,200 km pipeline network that extends across much of Alberta and B.C. It transports approximately half of Alberta’s conventional crude oil production, about thirty percent of the NGL produced in western Canada, and virtually all of the conventional oil and condensate produced in B.C. This business’ primary objectives are to provide safe and reliable transportation services for customers, pursue opportunities for increased throughput and maintain and/or grow sustainable operating margin on invested capital by capturing incremental volumes, expanding its pipeline systems, managing revenue and following a disciplined approach to its operating expenses.
Operational Performance: Throughput
During the third quarter of 2013, Conventional Pipelines’ throughput averaged 489.1 mbpd, consisting of an average of 355.9 mbpd of crude oil and condensate and 133.2 mbpd of NGL. This represents an increase of approximately 10 percent compared to the same period of 2012, when average throughput was 443.9 mbpd. On a year-to-date basis in 2013, throughput averaged 488.8 mbpd compared to 448.2 mbpd for the first nine months of 2012. Higher throughput in the third quarter and first nine months of 2013 resulted from increased oil and gas producer activity in Conventional Pipelines’ service areas, which led to a number of newly connected facilities and increased volumes at existing connections and truck terminals.
Financial Performance
During the third quarter of 2013, Conventional Pipelines generated revenue of $103.1 million compared to $79 million in the same quarter of the previous year. For the first nine months of 2013, revenue was $300.4 million compared to $239.6 million for the same period in 2012. The 31 and 25 percent increases during the respective periods were primarily due to stronger volumes, as noted above, and new connections. Further, a Pembina-owned and operated pipeline system previously captured within the Midstream business was reassigned to Conventional Pipelines, resulting in increased revenue of $5.9 million and $19 million for the third quarter and first nine months of 2013, respectively. This had no impact on the comparability of volumes (discussed above) as the assets are interconnected to existing Conventional Pipelines systems.
During the third quarter, operating expenses increased to $37.2 million in 2013 compared to $30.1 million in 2012. Operating expenses for the nine months ended September 30, 2013 increased to $110.2 million from $87.6 million during the same period of 2012. The quarterly and year-to-date increases were mainly associated with work undertaken to continue to ensure safe and reliable operations at higher throughput levels, such as increased pipeline integrity and geotechnical activities, as well as higher power and labour costs.
Primarily because of higher revenue, operating margin for the third quarter of 2013 was $66.3 million compared to $49.4 million during the third quarter of 2012 and $192.4 million for the first nine months of 2013 compared to $151.3 million for the first nine months of 2012.
For depreciation and amortization included in operations during the third quarter, Conventional Pipelines incurred $6.4 million compared to an expense of $12 million during the third quarter of 2012. The decrease in the comparable period is due to a re-measurement of the decommissioning provision in excess of the carrying amount of the related asset. An expense of $5.9 million was realized for the nine months ended September 30, 2013 compared to an expense of $36.1 million in the first nine months of 2012 with the difference between periods being due to the same factor noted above.
For the three and nine months ended September 30, 2013, gross profit was $60 million and $188.9 million, respectively, compared to $30.3 million and $105.4 million for the same periods of the prior year. These increases were primarily due to higher revenue generated during the quarter and first nine months of the year, for the reasons discussed above.
Capital expenditures for the third quarter and first nine months of 2013 totalled $78.6 million and $198.9 million, respectively, compared to $34.7 million and $99.2 million for the same periods of 2012. The majority of this spending relates to the expansion of certain pipeline assets as described below, as well as the completion of several new connections to bring additional producer volumes on-line.
New Developments
Pembina is pursuing several crude oil, condensate and NGL expansions on its Conventional Pipelines systems to accommodate increased customer demand and address constrained pipeline capacity in several areas of the WCSB.
Subsequent to the quarter end, Pembina has substantially completed construction of its Phase I NGL Expansion, which expanded NGL capacity by 52,000 bpd on the Peace and Northern Pipelines (the “Peace/Northern NGL System”), bringing total capacity on this system to 167,000 bpd by the end of November 2013.
Pembina is also progressing its previously announced Phase II NGL Expansion of its Peace/Northern NGL System, which is expected to increase capacity of the system from 167,000 bpd to 220,000 bpd. Subject to obtaining regulatory and environmental approvals, Pembina expects the Phase II NGL Expansion to be complete in mid-2015.
Construction of the Company’s Phase I Low Vapour Pressure Expansion (“Phase I LVP Expansion”) on its Peace Pipeline between Fox Creek and Edmonton, Alberta, is also substantially complete. This expansion will provide an additional 40,000 bpd of crude oil and condensate capacity on this segment by the end of November, 2013.
In addition, Pembina continues to progress its 55,000 bpd Phase II Low Vapour Pressure Expansion on its Peace Pipeline (the “Phase II LVP Expansion”). Subject to obtaining regulatory and environmental approvals, Pembina expects the Phase II LVP Expansion to be complete in late-2014.
On September 16, 2013, in response to requests from area producers for firm service between Simonette and Fox Creek, Alberta, Pembina announced plans to proceed with a $115 million expansion of its Peace Pipeline System (the “Simonette Pipeline Expansion”). This expansion is expected to initially deliver approximately 40,000 bpd of additional liquids to Pembina’s Fox Creek Terminal from which it will access the Company’s previously announced Phase I and II Peace Pipeline mainline expansions to reach Edmonton area markets. The new pipeline will have a capacity of approximately 150,000 bpd and is expected to be in-service in the third quarter of 2014, subject to the necessary environmental and regulatory approvals.
The Simonette Pipeline Expansion will include approximately 60 km of 16-inch pipeline along the Company’s existing right-of-way, providing service to producers developing the regional Montney and Duvernay formation resource plays. Once complete, Pembina will have three pipelines in the corridor capable of segregating and shipping various grades of crude oil, condensate and NGL.
In conjunction with the Simonette Pipeline Expansion, Pembina is also installing eight clean crude oil and condensate truck unloading risers at its Fox Creek Terminal which the Company anticipates will be in-service in the fourth quarter of 2013. The addition of high-capacity truck unloading facilities will allow producers to access Edmonton area markets through the previously announced Phase I and II Peace Pipeline mainline expansions.
Pembina expects the Simonette Pipeline Expansion to support its potential Phase III Peace Pipeline mainline expansion plans by providing sufficient capacity and operational flexibility within the Simonette to Fox Creek corridor to transport substantially all future volumes nominated through its previously announced Open Season process. The Company continues to progress stakeholder consultation activities and engineering design associated with the Open Season and is in the process of finalizing binding transportation agreements with area producers.
Oil Sands & Heavy Oil
| 3 Months Ended September 30 |
9 Months Ended September 30 |
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| ($ millions, except where noted) | 2013 | 2012 | 2013 | 2012 | |||||||
| Contracted capacity, end of period (mbpd) | 880.0 | 870.0 | 880.0 | 870.0 | |||||||
| Revenue | 48.2 | 44.1 | 142.5 | 126.6 | |||||||
| Operations | 15.2 | 14.8 | 45.4 | 39.4 | |||||||
| Operating margin(1) | 33.0 | 29.3 | 97.1 | 87.2 | |||||||
| Depreciation and amortization included in operations | 5.0 | 5.0 | 14.8 | 14.8 | |||||||
| Gross profit | 28.0 | 24.3 | 82.3 | 72.4 | |||||||
| Capital expenditures | 8.4 | 6.1 | 33.0 | 12.1 | |||||||
| (1) | Refer to “Non-GAAP Measures.” |
Business Overview
Pembina plays an important role in supporting Alberta’s oil sands and heavy oil industry. Pembina is the sole transporter of crude oil for Syncrude Canada Ltd. (via the Syncrude Pipeline) and Canadian Natural Resources Ltd.’s Horizon Oil Sands operation (via the Horizon Pipeline) to delivery points near Edmonton, Alberta. Pembina also owns and operates the Nipisi and Mitsue Pipelines, which provide transportation for producers operating in the Pelican Lake and Peace River heavy oil regions of Alberta, and the Cheecham Lateral, which transports synthetic crude to oil sands producers operating southeast of Fort McMurray, Alberta. The Oil Sands & Heavy Oil business operates approximately 1,650 km of pipeline and has approximately 880 mbpd of capacity under long-term, extendible contracts, which provide for the flow-through of eligible operating expenses to customers. As a result, operating margin from this business is primarily driven by the amount of capital invested and is predominantly not sensitive to fluctuations in operating expenses or actual throughput.
Financial Performance
The Oil Sands & Heavy Oil business realized revenue of $48.2 million in the third quarter of 2013 compared to $44.1 million in the third quarter of 2012. Year-to-date revenue in 2013 was $142.5 million compared to $126.6 million for the same period in 2012. Revenue for the third quarter and first nine months of the year was higher than the comparable periods of the prior year. This was largely because of increased contribution from the Nipisi system resulting from a new pump station being placed in-service, allowing for additional volumes to be transported above contracted levels in the 2013 periods.
Operating expenses were $15.2 million during the third quarter of 2013 compared to $14.8 million during the third quarter of 2012. For the first nine months of 2013, operating expenses were $45.4 million compared to $39.4 million for the same period in 2012. Additional power costs were the main reason for the increase in operating expenses for both the third quarter and first nine months of 2013.
For the three and nine months ended September 30, 2013, operating margin increased to $33 million and $97.1 million compared to $29.3 million and $87.2 million, respectively, during the same periods in 2012. These increases were primarily due to the new pump station on the Nipisi pipeline that enables additional throughput above contracted volumes in the 2013 periods.
Depreciation and amortization included in operations for the third quarter and first nine months of 2013 totalled $5 million and $14.8 million, consistent with the same periods of the prior year.
For the three and nine months ended September 30, 2013, gross profit was $28 million and $82.3 million, higher than gross profit of $24.3 million and $72.4 million, respectively, during the same periods of 2012.
During the first nine months of the year, capital expenditures within the Oil Sands & Heavy Oil business totalled $33 million and were primarily related to the construction of additional pump stations in the Slave Lake, Alberta, area on the Nipisi and Mitsue pipelines. This compares to $12.1 million spent during the same period in 2012, which also related to the Nipisi and Mitsue pipelines.
New Developments
Pembina continues to move forward with work related to its previously announced $35 million engineering support agreement (“ESA”) with KKD Oil Sands Partnership (“KOSP” – a partnership between Statoil Canada Ltd., as managing partner, and PTTEP Canada Ltd.) to progress a potential new oil sands pipeline project (the “Cornerstone Pipeline System”). Provided that the oil sands project itself is sanctioned by KOSP, that satisfactory commercial agreements can be reached and that regulatory and environmental approvals can be obtained thereafter, Pembina expects the Cornerstone Pipeline System could be in-service in mid-2017 at an estimated cost of $850 million based on the preliminary design. The Cornerstone Pipeline System is expected to also provide integration opportunities and synergies for Pembina’s Midstream business, which is expected to be a 50-percent shipper on the diluent pipeline alongside KOSP.
Pembina also completed an additional pump station for the Mitsue condensate pipeline, which brought Mitsue’s capacity from 18,000 bpd to 22,000 bpd.
Gas Services
| 3 Months Ended September 30 |
9 Months Ended September 30 |
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| ($ millions, except where noted) | 2013 | 2012 | 2013 | 2012 | |||||||
| Average processed volume (MMcf/d) net to Pembina(1) | 288.2 | 275.0 | 292.6 | 275.0 | |||||||
| Average processed volume (mboe/d)(2) net to Pembina | 48.0 | 45.8 | 48.8 | 45.8 | |||||||
| Revenue | 31.5 | 23.7 | 87.6 | 65.0 | |||||||
| Operations | 10.7 | 7.1 | 30.7 | 20.3 | |||||||
| Operating margin(3) | 20.8 | 16.6 | 56.9 | 44.7 | |||||||
| Depreciation and amortization included in operations | 5.4 | 3.4 | 12.6 | 10.9 | |||||||
| Gross profit | 15.4 | 13.2 | 44.3 | 33.8 | |||||||
| Capital expenditures | 80.2 | 29.8 | 202.5 | 85.6 | |||||||
| (1) | Volumes at Musreau exclude deep cut processing as those volumes are counted when they are processed through the shallow cut portion of the plant. |
|
| (2) | Average processing volume converted to mboe/d from MMcf/d at a 6:1 ratio. | |
| (3) | Refer to “Non-GAAP Measures.” |
Business Overview
Pembina’s operations include a growing natural gas gathering and processing business, which is strategically positioned in active and emerging NGL-rich plays in the WCSB and integrated with Pembina’s other businesses. Gas Services provides gas gathering, compression, and both shallow and deep cut processing services for its customers, primarily on a fee-for-service basis under long-term contracts. The NGL extracted through these processes are transported on Pembina’s Conventional Pipelines. As of November 2013, operating assets in this business include:
The Cutbank Complex and Saturn I Facility are connected to Pembina’s Peace Pipeline system. The Company continues to progress construction and development of numerous other facilities in its Gas Services business to meet the growing needs of producers in west central Alberta, as discussed in more detail below.
Operational Performance
Average processing volumes, net to Pembina, were 288.2 MMcf/d during the third quarter of 2013, slightly higher than the 275 MMcf/d processed during the third quarter of the previous year. On a year-to-date basis, volumes have increased just over six percent to 292.6 MMcf/d compared to 275 MMcf/d in the first nine months of 2012. These increases are attributable to sustained interest of producers in the surrounding areas and their focus on liquids-rich natural gas, which continues to attract higher commodity pricing relative to dry gas.
Financial Performance
Gas Services contributed $31.5 million of revenue during the third quarter of 2013, 33 percent higher than the $23.7 million generated in the third quarter of 2012. For the first nine months of the year, revenue was $87.6 million compared to $65 million in the same period of 2012. These increases primarily reflect higher processing fees and operating recoveries at the Company’s Musreau shallow and deep cut facilities. Revenue was also higher as a result of the Company investing additional capital in these facilities to meet producer demand. The Musreau deep cut facility and shallow cut expansion were brought on line early in September of 2012 and have operated throughout 2013.
During the third quarter of 2013, operating expenses were $10.7 million compared to $7.1 million in the third quarter of 2012. Year-to-date operating expenses totalled $30.7 million, up from $20.3 million during the same period of the prior year. The quarterly and year-to-date increases were mainly due to additional electrical power, operating labour and maintenance cost associated with the higher volumes and increased activity at the expanded Cutbank Complex.
Gas Services realized operating margin of $20.8 million in the third quarter and $56.9 million in the first nine months of 2013 compared to $16.6 million and $44.7 million, respectively, during the same periods of the prior year. These increases in operating margin are the result of the higher volumes at the Cutbank Complex and the collection of additional fees for capital invested.
For the three months ended September 30, 2013, gross profit was $15.4 million compared to $13.2 million in the same period of 2012. On a year-to-date basis, gross profit was $44.3 million compared to $33.8 million during the first nine months of 2012. These increases reflect higher operating margin during the period.
For the nine months ended September 30, capital expenditures within Gas Services totalled $202.5 million in 2013 compared to $85.6 million in 2012. This increase in spending was to progress the Saturn I, Saturn II, Musreau II, Musreau field facilities and Resthaven facilities, some of which are discussed below.
New Developments
Pembina’s Gas Services business is progressing four new facilities and associated infrastructure:
Saturn I
Pembina has completed and commissioned its Saturn I Facility (200 MMcf/d deep cut processing plant) and associated pipelines and infrastructure. The facility, which has the capacity to extract up to 13.5 mbpd of NGL, was fully operational as of late-October 2013.
Resthaven
Pembina is progressing construction of the Resthaven facility and expects to bring the facility and associated pipelines into service in the third quarter of 2014. Once operational, the Company expects the Resthaven facility will have the capacity to extract up to 13 mbpd of NGL.
Saturn II
Saturn II will leverage the engineering work completed for the Saturn I Facility and is expected to be in-service by late 2015. Pembina has received the required regulatory and environmental approvals and is progressing construction of the facility. The Company expects the Saturn II facility will have the capacity to extract approximately 13.5 mbpd of NGL, which will be transported on the same liquids pipeline lateral Pembina constructed for the Saturn I Facility.
Musreau II
On August 9, 2013, Pembina announced that it is pursuing Musreau II, a new 100 MMcf/d shallow cut gas plant with associated NGL and gas gathering pipelines near its existing Musreau facility (part of the greater Cutbank Complex). Musreau II is underpinned by long-term take-or-pay agreements with area producers. The facility is designed to handle propane-plus (C3+) and is expected to yield approximately 4.2 mbpd of NGL for transportation on Pembina’s Conventional Pipelines. Construction is underway and Pembina expects Musreau II to be in-service in the first quarter of 2015.
Summary
Pembina expects the expansions detailed above to bring the Company’s Gas Services processing capacity to approximately 1.2 bcf/d (net) by the end of 2015. This includes ethane-plus extraction capacity of approximately 735 MMcf/d (net). The volumes from Pembina’s existing assets and those under development would be processed largely on a contracted, fee-for-service basis and are expected to result in a total of approximately 55 mbpd of NGL to be transported for toll revenue on Pembina’s Conventional Pipelines once the projects are complete.
Midstream
| 3 Months Ended September 30 |
9 Months Ended September 30(1) |
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| ($ millions, except where noted) | 2013 | 2012 | 2013 | 2012 | ||||||
| Revenue | 1,129.6 | 674.8 | 3,230.5 | 1,743.7 | ||||||
| Operations | 25.1 | 18.2 | 71.6 | 40.3 | ||||||
| Cost of goods sold, including product purchases | 994.8 | 571.6 | 2,833.7 | 1,519.5 | ||||||
| Realized loss on commodity-related derivative financial instruments | 4.9 | 3.4 | 0.5 | 14.9 | ||||||
| Operating margin(2) | 104.8 | 81.6 | 324.7 | 169.0 | ||||||
| Depreciation and amortization included in operations | 29.7 | 31.2 | 87.4 | 64.0 | ||||||
| Unrealized (loss) gain on commodity-related derivative financial instruments | (2.2) | (15.9) | 2.7 | 48.1 | ||||||
| Gross profit | 72.9 | 34.5 | 240.0 | 153.1 | ||||||
| Capital expenditures | 76.7 | 70.7 | 166.5 | 126.6 | ||||||
| (1) | Share of profit from equity accounted investees not included in these results. | |
| (2) | Refer to “Non-GAAP Measures.” |
Business Overview
Pembina offers customers a comprehensive suite of midstream products and services through its Midstream business as follows:
The financial performance of NGL midstream can be affected by the seasonal demand for propane. Inventory generally builds over the second and third quarters of the year and is sold in the fourth quarter and the first quarter of the following year during the winter heating season.
Financial Performance
In the Midstream business, revenue, net of cost of goods sold, grew to $134.8 million during the third quarter of 2013 from $103.2 million during the third quarter of 2012. For the most part, the increase is due to a historically more balanced propane market driven by lower inventories in North America in the 2013 period compared to 2012. Year-to-date revenue, net of cost of goods sold, was $396.8 million in 2013 compared to $224.2 million in 2012. This increase was primarily due to nine months of results generated by the NGL assets in 2013 compared to the 2012 period, which only captured six months of results due to the timing of the Acquisition, along with improved propane pricing, stronger margins and increased storage opportunities for crude oil and condensate in the first quarter of 2013.
Operating expenses during the third quarter and first nine months of 2013 were $25.1 million and $71.6 million, respectively, compared to $18.2 million and $40.3 million in the comparable periods of 2012. Operating expenses were higher due to the increase in Midstream’s asset base since the Acquisition.
Operating margin was $104.8 million during the third quarter of 2013 and $324.7 million during the first nine months of the year compared to $81.6 million and $169 million in the respective periods of 2012. These increases primarily relate to growth in revenue, as discussed above.
The Company’s crude oil midstream third quarter operating margin increased to $28.7 million in 2013 compared to $27.2 million in 2012. This increase was primarily due to Midstream’s ability to capitalize on differentials related to specific commodities during the quarter, increased activities and services at PNT and at Pembina’s truck and full-service terminals. However, these positive contributions were offset by increased operating expenses associated with Three Star Trucking and various initiatives supporting pipeline interconnectivity. For the first nine months of the year, crude oil midstream operating margin totalled $99.5 million compared to $87.4 million during the same period of the prior year. The year-to-date increase was primarily due to strong first quarter 2013 results driven by higher volumes and increased activity on Pembina’s pipeline systems, robust demand for midstream services, wider margins, as well as increased throughput at the crude oil Midstream truck terminals.
Operating margin for Pembina’s NGL midstream activities was $76 million for the third quarter of 2013, including a $3.8 million realized loss on commodity-related derivative financial instruments (see “Market Risk Management Program”) compared to $54.4 million for the third quarter of 2012, including a $3.8 million realized loss on commodity-related derivative financial instruments. For the nine months ended September 30, 2013, operating margin for NGL midstream was $225.2 million, including a $2.8 million realized gain on commodity-related derivative financial instruments compared to $81.6 million, which included a realized loss on commodity-related derivative financial instruments of $15 million, for the same period of 2012.
NGL sales volumes, which were driven by higher sales in propane, butane and condensate during the third quarter of 2013, were 98.9 mbpd, a 14 percent increase compared to the third quarter of 2012.
Operating margin from Redwater West during the third quarter of 2013, excluding realized losses from commodity-related derivative financial instruments, was $60.9 million compared to $46.6 million in the third quarter of 2012. The increase was primarily driven by a stronger year-over-year market for propane. Overall, Redwater West NGL sales volumes averaged 59.4 mbpd in the third quarter of 2013 compared to 52.9 mbpd in the third quarter of 2012.
Operating margin from Empress East during the third quarter of 2013, excluding realized losses from commodity-related derivative financial instruments, was $18.9 million compared to $11.6 million in the same quarter in 2012. Similar to Redwater West, the strengthened third quarter results for Empress East is primarily due to a stronger year-over-year propane market. Operating margin also improved due to lower inventory acquisition costs at Empress, which were primarily driven by lower extraction premiums. Overall, Empress East NGL sales volumes averaged 39.5 mbpd in the third quarter of 2013 compared to 33.8 mbpd in the third quarter of 2012.
Depreciation and amortization included in operations during the third quarter of 2013 totalled $29.7 million compared to $31.2 million during the same period of the prior year. The decrease primarily reflects a reassignment of assets previously in the Midstream business to Conventional Pipelines, as previously discussed. Year-to-date depreciation and amortization included in operations totalled $87.4 million, up from $64 million during the first nine months of 2012. The year-to-date increases reflect the additional Midstream assets in this business since the closing of the Acquisition.
In the third quarter of 2013, unrealized losses on commodity-related derivative financial instruments were $2.2 million compared to $15.9 million for the three months ended September 30, 2012. For the first nine months of the year, unrealized gains on commodity-related derivative financial instruments were $2.7 million compared to $48.1 million in the same period of the prior year. The significant change in unrealized losses and gains on commodity-related derivative financial instruments which were recognized in the three and nine month periods ended September 30, 2012, respectively, reflected the reduction in the future NGL price indices between April 2, 2012 and September 30, 2012.
For the three and nine months ended September 30, 2013, gross profit in this business was $72.9 million and $240 million compared to $34.5 million and $153.1 million during the same periods in 2012 due to the factors impacting revenue, operating expenses, depreciation and amortization (operational) and unrealized gain (loss) on commodity-related derivative financial instruments noted above.
For the nine months ended September 30, 2013, capital expenditures within the Midstream business totalled $166.5 million compared to $126.6 million during the same period of 2012 and were primarily related to cavern development and associated infrastructure.
New Developments
Market demand for products and services in the Midstream space is strong for both crude oil and NGL. The capital being deployed in the Midstream business is primarily directed towards fee-for-service projects.
On September 3, 2013, Pembina announced the acquisition of a $20 million site in the Alberta Industrial Heartland featuring existing rail access and utility infrastructure to support the future development of rail, terminalling and storage facilities (the “Heartland Hub”). The Heartland Hub is a further build-out of PNT, servicing crude oil and diluent customers for terminalling, storage and rail.
At the same time, Pembina announced entering into a multi-year, fee-for-service agreement with a major North American refiner for provision of rail loading services for up to 40,000 bpd of various crude oil grades at the Company’s Redwater facility.
Regarding Pembina’s previously announced RFS II project (a second 73,000 bpd fractionator at Pembina’s Redwater site), the Company completed land clearing during the third quarter, began washing the feed cavern for the fractionator, ordered all long-lead equipment and is progressing with construction.
On July 31, 2013, the Company also announced plans to spend approximately $25 million to upsize certain facilities associated with RFS II to accommodate further expansion and the potential development of a third fractionator (“RFS III”) at a later date at its Redwater site. Pembina has not yet entered into commercial agreements for RFS III, but believes there is strong market demand for additional fractionation capacity beyond what will be available after completing RFS II. With the addition of RFS II, which is expected to come into service in the fourth quarter of 2015, the Company’s ethane-plus fractionation capacity at Redwater will double to 146,000 bpd. Should RFS III proceed, the facility would leverage engineering and design work completed for both the original Redwater fractionator and RFS II.
Pembina is also continuing to investigate offshore propane export opportunities that would allow it to leverage its existing assets and provide a substantial incremental market for Canadian producers impacted by weak western Canadian pricing.
Market Risk Management Program
Pembina is exposed to frac spread risk, which is the difference between the selling price for propane-plus liquids and the purchase cost of natural gas required to produce respective NGL products. Pembina has a risk management program and uses derivative financial instruments to mitigate frac spread risk, when possible, to safeguard a base level of operating cash flow that covers the input cost of natural gas. Pembina has entered into derivative financial swap contracts to partially protect the frac spread and product margin, and to manage exposure to power costs, interest rates and foreign exchange rates.
Pembina’s credit policy mitigates risk of non-performance by counterparties of its derivative financial instruments. Activities undertaken to reduce risk include: regularly monitoring counterparty exposure to approved credit limits; financial reviews of all active counterparties; entering into International Swap Dealers Association agreements; and, obtaining financial assurances where warranted. In addition, Pembina has a diversified base of available counterparties.
Management continues to actively monitor commodity price risk and mitigate its impact through financial risk management activities. For more information on financial instruments and financial risk management, see Note 11 to the Interim Financial Statements.
Non-Operating Expenses
G&A
Pembina incurred G&A (including corporate depreciation and amortization) of $29.8 million during the third quarter of 2013, up from $26.9 million during the third quarter of 2012 primarily due to the addition of new employees as a result of Pembina’s growth since the prior period and increased share based incentive expenses. G&A for the first nine months of 2013 was $88.6 million compared to $70.2 million for the same period of 2012. The increase for the nine month period was mainly due to the same reasons as detailed above as well as the addition of new employees who joined the Company through the Acquisition. In addition, every $1 change in share price is expected to change Pembina’s annual share-based incentive expense by approximately $1 million.
Depreciation & Amortization (operational)
Depreciation and amortization (operational) decreased to $46.5 million during the third quarter of 2013 compared to $51.6 million during the same period in 2012. For the nine months ended September 30, 2013, depreciation and amortization (operational) was $120.7 million, down from $125.8 million for the same period last year. The variances during the quarter and year-to-date compared to the same periods of last year are primarily due to a re-measurement of the decommissioning provision in excess of the carrying amount of the related asset offset by depreciation from new assets.
Net Finance Costs
Net finance costs in the third quarter of 2013 were $36 million compared to $33.1 million in the third quarter of 2012. This slight increase is primarily due to a loss on revaluation of the conversion feature of the convertible debentures, offset by lower interest expense on loans and borrowings. Year-to-date net finance costs in 2013 totalled $111.2 million, up from $79.4 million in the same period of 2012. The increase is primarily due to the same reason detailed above.
Income Tax Expense
Income tax expense was $40 million for the third quarter of 2013, including current taxes of $6.2 million and deferred taxes of $33.8 million, compared to current taxes of $0.9 million and deferred taxes of $9.3 million in the same period of 2012. Year-to-date income tax expense in 2013 totalled $101.6 million, up from $48.2 million in the same period of 2012. The current taxes arose during the quarter primarily as a result of certain Pembina subsidiary corporation’s taxable income exceeding their losses available for carry-over. Deferred income tax expense arises from the difference between the accounting and tax basis of assets and liabilities.
Liquidity & Capital Resources
| ($ millions) | September 30, 2013 | December 31, 2012 | |||||||||
| Working capital | (190.9)(3) | 62.8 | |||||||||
| Variable rate debt(1)(2) | |||||||||||
| Bank debt | 30.0 | 525.0 | |||||||||
| Total variable rate debt outstanding (average rate of 3.45%) | 30.0 | 525.0 | |||||||||
| Fixed rate debt(1) | |||||||||||
| Senior unsecured notes | 642.0 | 642.0 | |||||||||
| Senior unsecured term debt | 75.0 | 75.0 | |||||||||
| Senior unsecured medium-term notes | 900.0 | 700.0 | |||||||||
| Subsidiary debt | 8.9 | 9.3 | |||||||||
| Total fixed rate debt outstanding (average of 4.99%) | 1,625.9 | 1,426.3 | |||||||||
| Convertible debentures(1) | 642.4 | 644.3 | |||||||||
| Finance lease liability | 7.9 | 5.8 | |||||||||
| Total debt and debentures outstanding | 2,306.2 | 2,601.4 | |||||||||
| Cash and unutilized debt facilities | 1,515.5 | 1,032.3 | |||||||||
| (1) | Face value. | |
| (2) | Pembina maintains derivative financial instruments to manage exposure to variable interest rates. See “Market Risk Management Program.” |
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| (3) | As at September 30, 2013, working capital includes $261.8 million (December 31, 2012: $11.7 million) associated with the current portion of loans and borrowings. |
Pembina anticipates cash flow from operating activities will be more than sufficient to meet its short-term operating obligations and fund its targeted dividend level. In the short-term, Pembina expects to source funds required for capital projects from cash and cash equivalents and unutilized debt facilities totalling $1,515.5 million as at September 30, 2013. In addition, based on its successful access to financing in the debt and equity markets over the past several years, Pembina believes it would continue to have access to funds at attractive rates, if and when required. Management remains satisfied that the leverage employed in Pembina’s capital structure is sufficient and appropriate given the characteristics and operations of the underlying asset base.
Management may make adjustments to Pembina’s capital structure as a result of changes in economic conditions or the risk characteristics of the underlying assets. To maintain or modify Pembina’s capital structure in the future, Pembina may renegotiate new debt terms, repay existing debt, seek new borrowing and/or issue additional equity.
Pembina’s credit facilities at September 30, 2013 consisted of an unsecured $1.5 billion revolving credit facility due March 2018 and an operating facility of $30 million due July 2014. Borrowings on the revolving credit facility and the operating facility bear interest at prime lending rates plus nil percent to 1.25 percent or Bankers’ Acceptances rates plus 1.00 percent to 2.25 percent. Margins on the credit facilities are based on the credit rating of Pembina’s senior unsecured debt. There are no repayments due over the term of these facilities. As at September 30, 2013, Pembina had $30 million drawn on bank debt, $0.1 million in letters of credit and $15.5 million in cash, leaving $1,515.5 million of unutilized debt facilities on the $1,530 million of established bank facilities. Pembina also had an additional $14.1 million in letters of credit issued in a separate demand letter of credit facility. At September 30, 2013, Pembina had loans and borrowing (excluding amortization, letters of credit and finance lease liabilities) of $1,655.9 million. Pembina’s senior debt to total capital at September 30, 2013 was 23 percent.
On July 26, 2013, Pembina closed its offering of 10,000,000 cumulative redeemable rate reset class A preferred shares, series 1 (the “Series 1 Preferred Shares”) at a price of $25.00 per share. Pembina used proceeds from this offering to partially fund capital projects, repay amounts outstanding on the credit facility, and for other general corporate purposes of the Company. The Series 1 Preferred Shares began trading on the Toronto Stock Exchange on July 26, 2013 under the symbol PPL.PR.A.
Subsequent to the end of the third quarter, on October 2, 2013, Pembina closed its offering of 6,000,000 cumulative redeemable rate reset class A preferred shares, series 3 (the “Series 3 Preferred Shares”) at a price of $25.00 per share. Pembina used proceeds from this offering to partially fund capital projects and for general corporate purposes of the Company. The Series 3 Preferred Shares began trading on the Toronto Stock Exchange on October 2, 2013 under the symbol PPL.PR.C.
Credit Ratings
The following information with respect to Pembina’s credit ratings is provided as it relates to Pembina’s financing costs and liquidity. Specifically, credit ratings affect Pembina’s ability to obtain short-term and long-term financing and the cost of such financing. A reduction in the current ratings on Pembina’s debt by its rating agencies, particularly a downgrade below investment grade ratings, could adversely affect Pembina’s cost of financing and its access to sources of liquidity and capital. In addition, changes in credit ratings may affect Pembina’s ability, and the associated costs, to enter into normal course derivative or hedging transactions. Credit ratings are intended to provide investors with an independent measure of credit quality of any issues of securities. The credit ratings assigned by the rating agencies are not recommendations to purchase, hold or sell the securities nor do the ratings comment on market price or suitability for a particular investor. Any rating may not remain in effect for a given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgement circumstances so warrant.
DBRS rates Pembina’s senior unsecured notes ‘BBB’ and Series 1 and Series 3 Preferred Shares Pfd-3. S&P’s long-term corporate credit rating on Pembina is ‘BBB’ and its rating of the Series 1 and Series 3 Preferred Shares is P-3.
Capital Expenditures
| 3 Months Ended September 30 |
9 Months Ended September 30 |
||||||||||||||||
| ($ millions) | 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Development capital | |||||||||||||||||
| Conventional Pipelines | 78.6 | 34.7 | 198.9 | 99.2 | |||||||||||||
| Oil Sands & Heavy Oil | 8.4 | 6.1 | 33.0 | 12.1 | |||||||||||||
| Gas Services | 80.2 | 29.8 | 202.5 | 85.6 | |||||||||||||
| Midstream | 76.7 | 70.7 | 166.5 | 126.6 | |||||||||||||
| Corporate/other projects | 0.9 | 2.0 | 3.7 | 6.1 | |||||||||||||
| Total development capital | 244.8 | 143.3 | 604.6 | 329.6 | |||||||||||||
For the three months ended September 30, 2013, capital expenditures were $244.8 million compared to $143.3 million spent in the same three months of 2012. During the first nine months of 2013, capital expenditures were $604.6 million compared to $329.6 million during the same nine month period in 2012.
The majority of the capital expenditures in the third quarter and first nine months of 2013 were in Pembina’s Conventional Pipelines, Gas Services and Midstream businesses. Conventional Pipelines incurred capital to progress its phase I and phase II crude oil, condensate and NGL expansions and on various new connections. Gas Services’ capital was primarily deployed to complete the Saturn I Facility and progress the Resthaven Facility. Midstream’s capital expenditures were mainly directed towards cavern development and related infrastructure as well as RFS II.
Contractual Obligations at September 30, 2013
| ($ millions) | Payments Due By Period | ||||||||||||||||
| Contractual Obligations | Total | Less than 1 year |
1 – 3 years | 3 – 5 years | After 5 years |
||||||||||||
| Operating and finance leases | 307.9 | 30.8 | 65.7 | 62.2 | 149.2 | ||||||||||||
| Loans and borrowings(1) | 2,379.1 | 335.1 | 131.2 | 161.3 | 1,751.5 | ||||||||||||
| Convertible debentures(1) | 871.5 | 39.2 | 78.9 | 242.3 | 511.1 | ||||||||||||
| Construction commitments | 1,187.4 | 811.2 | 376.2 | ||||||||||||||
| Provisions(2) | 293.4 | 0.1 | 5.6 | 27.5 | 260.2 | ||||||||||||
| Total contractual obligations(3) | 5,039.3 | 1,216.4 | 657.6 | 493.3 | 2,672.0 | ||||||||||||
| (1) | Excluding deferred financing costs. |
| (2) | Includes discounted constructive and legal obligations included in the decommissioning provision. |
| (3) | Excluding expansion rights and obligations associated with existing contracts and which have not yet been triggered. |
Pembina is, subject to certain conditions, contractually committed to the construction and operation of: the Saturn II, Resthaven and Musreau II facilities; RFS II; and the previously mentioned crude oil and NGL Conventional Pipeline expansions. See “Forward-Looking Statements & Information.”
Changes in Accounting Principles and Practices
The following new standards, interpretations, amendments and improvements to existing standards issued by the International Accounting Standard Board or International Financial Reporting Interpretations Committee were adopted as of January 1, 2013 without any material impact to Pembina’s Financial Statements: IFRS 7 Financial Instruments: Disclosures, IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosure of Interests in Other Entities, IFRS 13 Fair Value Measurement, and IAS 19 Employee Future Benefits.
Controls and Procedures
Changes in internal control over financial reporting
Pembina’s Management is responsible for establishing and maintaining disclosure controls and procedures (“DC&P”) and internal control over financial reporting (“ICFR”), as those terms are defined in National Instrument 52-109 “Certification of Disclosure in Issuers’ Annual and Interim Filings.” The objective of this instrument is to improve the quality, reliability and transparency of information that is filed or submitted under securities legislation.
The Chief Executive Officer and the Chief Financial Officer have designed, with the assistance of Pembina employees, DC&P and ICFR to provide reasonable assurance that material information relating to Pembina’s business is made known to them, is reported on a timely basis, financial reporting is reliable, and financial statements prepared for external purposes are in accordance with GAAP.
During the third quarter of 2013, there were no changes made to Pembina’s ICFR that materially affected, or are reasonably likely to materially affect, its ICFR.
Trading Activity and Total Enterprise Value(1)
| As at and for the 3 months ended |
|||||||||||||
| ($ millions, except where noted) | October 30 , 2013(2) | September 30, 2013 | September 30, 2012 | ||||||||||
| Trading volume and value | |||||||||||||
| Total volume (millions of shares) | 11.2 | 31.8 | 32.5 | ||||||||||
| Average daily volume (shares) | 532,719 | 504,905 | 524,256 | ||||||||||
| Value traded | 377.4 | 1,039.0 | 876.4 | ||||||||||
| Shares outstanding (millions of shares) | 313.0 | 312.1 | 290.5 | ||||||||||
| Closing share price (dollars) | 34.75 | 34.14 | 27.60 | ||||||||||
| Market value | |||||||||||||
| Common shares | 10,875.5 | 10,654.6 | 8,018.0 | ||||||||||
| Series 1 Preferred Shares (PPL.PR.A) | 239.0(3) | 237.5 (4) | |||||||||||
| Series 3 Preferred Shares (PPL.PR.C) | 146.0(5) | ||||||||||||
| 5.75% convertible debentures (PPL.DB.C) | 372.5(6) | 367.7 (7) | 329.0(8) | ||||||||||
| 5.75% convertible debentures (PPL.DB.E) | 239.7(9) | 234.7(10) | 202.2(11) | ||||||||||
| 5.75% convertible debentures (PPL.DB.F) | 210.0(12) | 206.7(13) | 190.3(14) | ||||||||||
| Market capitalization | 12,082.7 | 11,701.2 | 8,739.5 | ||||||||||
| Senior debt | 1,617.0 | 1,647.0 | 1,832.0 | ||||||||||
| Total enterprise value(15) | 13,699.7 | 13,348.2 | 10,571.5 | ||||||||||
| (1) | Trading information in this table reflects the activity of Pembina securities on the TSX only. |
| (2) | Based on 21 trading days from October 1, 2013 to October 30, 2013, inclusive. |
| (3) | 10 million preferred shares outstanding at a market price of $23.90 at October 30, 2013. |
| (4) | 10 million preferred shares outstanding at a market price of $23.75 at September 30, 2013. |
| (5) | 6 million preferred shares outstanding at a market price of $24.34 at October 30, 2013. |
| (6) | $298.9 million principal amount outstanding at a market price of $124.60 at October 30, 2013 and with a conversion price of $28.55. |
| (7) | $299 million principal amount outstanding at a market price of $123.00 at September 30, 2013 and with a conversion price of $28.55. |
| (8) | $299.7 million principal amount outstanding at a market price of $109.76 at September 29, 2012 and with a conversion price of $28.55. |
| (9) | $171.2 million principal amount outstanding at a market price of $140.00 at October 30, 2013 and with a conversion price of $24.94. |
| (10) | $171.3 million principal amount outstanding at a market price of $137.00 at September 30, 2013 and with a conversion price of $24.94. |
| (11) | $172.2 million principal outstanding at a market price of $117.48 at September 29, 2012 and with a conversion price of $24.94. |
| (12) | $172 million principal amount outstanding at a market price of $122.05 at October 30, 2013 and with a conversion price of $29.53. |
| (13) | $172.1 million principal amount outstanding at a market price of $120.11 at September 30, 2013 and with a conversion price of $29.53. |
| (14) | $172.4 million principal outstanding at a market price of $110.37 at September 29, 2012 with a conversion price of $29.53. |
| (15) | Refer to “Non-GAAP Measures.” |
As indicated in the previous table, Pembina’s total enterprise value was $13.3 billion at September 30, 2013 compared to $10.6 billion at September 30, 2012. The Company’s issued and outstanding shares rose to 312.1 million by the end of the third quarter 2013, compared to 290.5 million in the same period of 2012, primarily due to common shares issued under a bought deal financing which closed in the first quarter of 2013 and common shares issued under the DRIP.
Common Share Dividends
Pembina announced on August 9, 2013, that it increased its monthly dividend rate by 3.7 percent from $0.135 per common share per month (or $1.62 annualized) to $0.14 per common share per month (or $1.68 annualized) effective as of the August 25, 2013 record date, payable September 13, 2013. Pembina is committed to providing increased shareholder returns over time by providing stable dividends and, where appropriate, further increases in Pembina’s dividend, subject to compliance with applicable laws and the approval of Pembina’s Board of Directors. Pembina has a history of delivering common share dividend increases once supportable over the long-term by the underlying fundamentals of Pembina’s businesses as a result of, among other things, accretive growth projects or acquisitions (see “Forward-Looking Statements & Information”).
Dividends are payable if, as, and when declared by Pembina’s Board of Directors. The amount and frequency of dividends declared and payable is at the discretion of the Board of Directors, which will consider earnings, capital requirements, the financial condition of Pembina and other relevant factors.
Eligible Canadian investors may benefit from an enhanced dividend tax credit afforded to the receipt of dividends, depending on individual circumstances. Dividends paid to eligible U.S. investors should qualify for the reduced rate of tax applicable to long-term capital gains but investors are encouraged to seek independent tax advice in this regard.
Preferred Share Dividends
The holders of Series 1 Preferred Shares will be entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share, payable quarterly on the 1st day of March, June, September and December, if, as and when declared by the Board of Directors of Pembina, yielding 4.25 per cent per annum, for the initial fixed rate period to but excluding December 1, 2018. The dividend rate will reset on December 1, 2018 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.47 per cent. The Series 1 Preferred Shares are redeemable by Pembina, at its option, on December 1, 2018 and on December 1 of every fifth year thereafter at a price of $25.00 per share plus accrued and unpaid dividends.
The holders of Series 1 Preferred Shares will have the right to convert their shares into cumulative redeemable floating rate class A preferred shares, series 2 (the “Series 2 Preferred Shares”), subject to certain conditions, on December 1, 2018 and on December 1 of every fifth year thereafter. The holders of Series 2 Preferred Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the Board of Directors of Pembina, at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 2.47 per cent.
The holders of Series 3 Preferred Shares will be entitled to receive fixed cumulative dividends at an annual rate of $1.1750 per share, payable quarterly on the 1st day of March, June, September and December, if, as and when declared by the Board of Directors of Pembina, yielding 4.70 per cent per annum, for the initial fixed rate period to but excluding March 1, 2019. The dividend rate will reset on March 1, 2019 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.60 per cent. The Series 3 Preferred Shares are redeemable by Pembina, at its option, on March 1, 2019 and on March 1 of every fifth year thereafter at a price of $25.00 per share plus accrued and unpaid dividends.
The holders of Series 3 Preferred Shares will have the right to convert their shares into cumulative redeemable floating rate class A preferred shares, series 4 (the “Series 4 Preferred Shares”), subject to certain conditions, on March 1, 2019 and on March 1 of every fifth year thereafter. The holders of Series 4 Preferred Shares will be entitled to receive quarterly floating rate cumulative dividends, as and when declared by the Board of Directors of Pembina, at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 2.60 per cent.
DRIP
Eligible Pembina shareholders have the opportunity to receive, by reinvesting the cash dividends declared payable by Pembina on their common shares, either (i) additional common shares at a discounted subscription price equal to 95 percent of the Average Market Price (as defined in the DRIP), pursuant to the “Dividend Reinvestment Component” of the DRIP, or (ii) a premium cash payment (the “Premium Dividend™”) equal to 102 percent of the amount of reinvested dividends, pursuant to the “Premium Dividend™ Component” of the DRIP. Additional information about the terms and conditions of the DRIP can be found at www.pembina.com.
Participation in the DRIP for the third quarter of 2013 was approximately 57 percent of common shares outstanding for proceeds of approximately $73.3 million.
As of the April 25, 2013 record date, Pembina has made its DRIP available to its U.S. shareholders. U.S. shareholders are only permitted to participate in the Dividend Reinvestment Component of Pembina’s DRIP. Only Canadian resident shareholders are currently permitted to participate in the Premium Dividend™ Component of the DRIP. Shareholders who elect to enroll in the full Dividend Reinvestment Component are notified that the sale of the common shares issued on reinvestment is being made pursuant to a registration statement on Form F-3 filed by Pembina with the U.S. Securities and Exchange Commission (“SEC”).
Risk Factors
Management has identified the primary risk factors that could potentially have a material impact on the financial results and operations of Pembina. Such risk factors are presented in Pembina’s MD&A for the year ended December 31, 2012 and in Pembina’s Annual Information Form (“AIF”) for the year ended December 31, 2012. Pembina’s MD&A and AIF are available at www.pembina.com, in Canada under Pembina’s company profile on www.sedar.com and in the U.S. under the Company’s profile at www.sec.gov.
Selected Quarterly Operating Information
| 2013 | 2012 | 2011 | ||||||||||||||||||||||||||
| Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | ||||||||||||||||||||
| Average volume (mbpd unless stated otherwise) |
||||||||||||||||||||||||||||
| Conventional Pipelines throughput | 489.1 | 483.7 | 493.7 | 480.2 | 443.9 | 433.9 | 466.9 | 422.8 | 430.4 | |||||||||||||||||||
| Oil Sands & Heavy Oil contracted capacity, end of period |
880.0 | 870.0 | 870.0 | 870.0 | 870.0 | 870.0 | 870.0 | 870.0 | 775.0 | |||||||||||||||||||
| Gas Services processing (mboe/d)(1) | 48.0 | 48.4 | 49.9 | 46.0 | 45.8 | 47.5 | 44.1 | 45.3 | 43.6 | |||||||||||||||||||
| NGL sales volume (mboe/d) | 98.9 | 93.8 | 122.9 | 115.8 | 86.7 | 90.4 | ||||||||||||||||||||||
| (1) | Net to Pembina. Converted to mboe/d from MMcf/d at a 6:1 ratio. |
Selected Quarterly Financial Information
| 2013 | 2012 | 2011 | ||||||||||||||||||||||||
| ($ millions, except where noted) | Q3 | Q2 | Q1 | Q4 | Q3 | Q2 | Q1 | Q4 | Q3 | |||||||||||||||||
| Revenue | 1,300.2 | 1,175.0 | 1,248.5 | 1,265.6 | 815.4 | 870.9 | 475.5 | 468.1 | 300.6 | |||||||||||||||||
| Operations | 86.6 | 91.1 | 77.2 | 85.9 | 69.6 | 67.7 | 48.4 | 55.1 | 54.4 | |||||||||||||||||
| Cost of goods sold, including product purchases |
983.3 | 880.2 | 933.6 | 968.6 | 565.4 | 641.9 | 299.1 | 308.0 | 145.8 | |||||||||||||||||
| Realized gain (loss) on commodity-related derivative financial instruments |
(4.5) | 4.1 | 2.1 | 11.0 | (2.9) | (12.4) | (0.3) | 0.9 | 3.2 | |||||||||||||||||
| Operating margin(1) | 225.8 | 207.8 | 239.8 | 222.1 | 177.5 | 148.9 | 127.7 | 105.9 | 103.6 | |||||||||||||||||
| Depreciation and amortization included in operations |
46.5 | 32.4 | 41.8 | 47.8 | 51.6 | 52.5 | 21.7 | 19.6 | 17.8 | |||||||||||||||||
| Unrealized gain (loss) on commodity-related derivative financial instruments |
(2.1) | 1.4 | 5.8 | (2.2) | (23.0) | 64.8 | (3.5) | 0.9 | 0.7 | |||||||||||||||||
| Gross profit | 177.2 | 176.8 | 203.8 | 172.1 | 102.9 | 161.2 | 102.5 | 87.2 | 86.5 | |||||||||||||||||
| Adjusted EBITDA(1) | 200.8 | 185.1 | 210.2 | 199.0 | 153.8 | 125.9 | 111.4 | 88.2 | 89.9 | |||||||||||||||||
| Cash flow from operating activities | 87.3 | 140.2 | 229.0 | 139.5 | 130.9 | 24.1 | 65.3 | 73.8 | 87.7 | |||||||||||||||||
| Cash flow from operating activities per common share ($ per share) |
0.28 | 0.45 | 0.77 | 0.48 | 0.45 | 0.08 | 0.39 | 0.44 | 0.52 | |||||||||||||||||
| Adjusted cash flow from operating activities(1) | 188.7 | 144.0 | 207.4 | 172.3 | 133.2 | 89.5 | 98.8 | 66.0 | 82.0 | |||||||||||||||||
| Adjusted cash flow from operating activities per common share(1)($ per share) |
0.61 | 0.47 | 0.70 | 0.59 | 0.46 | 0.31 | 0.59 | 0.39 | 0.49 | |||||||||||||||||
| Earnings for the period | 71.8 | 93.8 | 90.5 | 81.3 | 30.7 | 80.4 | 32.6 | 45.0 | 30.1 | |||||||||||||||||
| Basic and diluted earnings per common share ($ per share) |
0.22 | 0.30 | 0.30 | 0.28 | 0.11 | 0.28 | 0.19 | 0.27 | 0.18 | |||||||||||||||||
| Common shares outstanding (millions): | ||||||||||||||||||||||||||
| Weighted average (basic) | 310.8 | 308.3 | 295.9 | 291.9 | 289.2 | 285.3 | 168.3 | 167.4 | 167.6 | |||||||||||||||||
| Weighted average (diluted) | 311.7 | 309.2 | 296.7 | 292.5 | 289.7 | 286.0 | 168.9 | 168.2 | 168.2 | |||||||||||||||||
| End of period | 312.1 | 309.5 | 307.0 | 293.2 | 290.5 | 287.8 | 169.0 | 167.9 | 167.7 | |||||||||||||||||
| Common share dividends declared | 129.1 | 125.0 | 121.0 | 118.4 | 117.3 | 116.2 | 65.7 | 65.4 | 65.4 | |||||||||||||||||
| Dividends per common share ($ per share) | 0.415 | 0.405 | 0.405 | 0.405 | 0.405 | 0.405 | 0.390 | 0.390 | 0.390 | |||||||||||||||||
| (1) | Refer to “Non-GAAP measures.” |
During the periods in the previous table, Pembina’s results were influenced by the following factors and trends:
Additional Information
Additional information about Pembina and legacy Provident filed with Canadian securities commissions and the SEC, including quarterly and annual reports, AIFs (filed with the SEC under Form 40-F), Management Information Circulars and financial statements can be found online at www.sedar.com, www.sec.gov and Pembina’s website at www.pembina.com.
Non-GAAP Measures
Throughout this MD&A, Pembina has used the following terms that are not defined by GAAP but are used by Management to evaluate performance of Pembina and its business. Since Non-GAAP financial measures do not have a standardized meaning prescribed by GAAP and are therefore unlikely to be comparable to similar measures presented by other companies, securities regulations require that Non-GAAP financial measures are clearly defined, qualified and reconciled to their nearest GAAP measure. Except as otherwise indicated, these Non-GAAP measures are calculated and disclosed on a consistent basis from period to period. Specific adjusting items may only be relevant in certain periods.
Net revenue
Net revenue is total revenue less cost of goods sold including product purchases.
| 3 Months Ended September 30 |
9 Months Ended September 30 |
|||||||||||||||||
| ($ millions) | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
| Total revenue | 1,300.2 | 815.4 | 3,723.7 | 2,161.8 | ||||||||||||||
| Cost of goods sold | 983.3 | 565.4 | 2,797.1 | 1,506.4 | ||||||||||||||
| Net revenue | 316.9 | 250.0 | 926.6 | 655.4 | ||||||||||||||
Earnings before interest, taxes, depreciation and amortization (“EBITDA”)
EBITDA is commonly used by Management, investors and creditors in the calculation of ratios for assessing leverage and financial performance and is calculated as results from operating activities plus share of profit from equity accounted investees (before tax) plus depreciation and amortization (included in operations and general and administrative expense) and unrealized gains or losses on commodity-related derivative financial instruments.
Adjusted EBITDA is EBITDA excluding acquisition-related expenses in connection with the Acquisition.
| 3 Months Ended September 30 |
9 Months Ended September 30 |
||||||||||
| ($ millions, except per share amounts) | 2013 | 2012 | 2013 | 2012 | |||||||
| Results from operating activities | 147.4 | 74.5 | 469.2 | 272.2 | |||||||
| Share of profit from equity accounted investees (before tax, depreciation and amortization) |
2.7 | 1.4 | 6.1 | 4.2 | |||||||
| Depreciation and amortization | 48.6 | 53.2 | 126.5 | 129.9 | |||||||
| Unrealized loss (gain) on commodity-related derivative financial instruments |
2.1 | 23.0 | (5.1) | (38.3) | |||||||
| EBITDA | 200.8 | 152.1 | 596.7 | 368.0 | |||||||
| Add: | |||||||||||
| Acquisition-related expenses (recovery) | 1.7 | (0.6) | 23.1 | ||||||||
| Adjusted EBITDA | 200.8 | 153.8 | 596.1 | 391.1 | |||||||
| EBITDA per common share – basic (dollars) | 0.65 | 0.53 | 1.96 | 1.49 | |||||||
| Adjusted EBITDA per common share – basic (dollars) | 0.65 | 0.53 | 1.95 | 1.58 | |||||||
Adjusted cash flow from operating activities
Adjusted cash flow from operating activities is commonly used by Management for assessing financial performance each reporting period and is calculated as cash flow from operating activities plus the change in non-cash working capital and excluding acquisition-related expenses.
| 3 Months Ended September 30 |
9 Months Ended September 30 |
|||||||||
| ($ millions, except per share amounts) | 2013 | 2012 | 2013 | 2012 | ||||||
| Cash flow from operating activities | 87.3 | 130.9 | 456.5 | 220.3 | ||||||
| Add (deduct): | ||||||||||
| Change in non-cash operating working capital | 101.4 | 0.6 | 84.2 | 78.1 | ||||||
| Acquisition-related expenses (recovery) | 1.7 | (0.6) | 23.1 | |||||||
| Adjusted cash flow from operating activities | 188.7 | 133.2 | 540.1 | 321.5 | ||||||
| Cash flow from operating activities per common share – basic (dollars) | 0.28 | 0.45 | 1.50 | 0.89 | ||||||
| Adjusted cash flow from operating activities per common share – basic (dollars) | 0.61 | 0.46 | 1.77 | 1.30 | ||||||
Operating margin
Operating margin is commonly used by Management for assessing financial performance and is calculated as gross profit before depreciation and amortization included in operations and unrealized gain/loss on commodity-related derivative financial instruments.
Reconciliation of operating margin to gross profit:
| 3 Months Ended September 30 |
9 Months Ended September 30 |
||||||||||
| ($ millions) | 2013 | 2012 | 2013 | 2012 | |||||||
| Revenue | 1,300.2 | 815.4 | 3,723.7 | 2,161.8 | |||||||
| Cost of sales: | |||||||||||
| Operations | 86.6 | 69.6 | 254.9 | 185.7 | |||||||
| Cost of goods sold, including product purchases | 983.3 | 565.4 | 2,797.1 | 1,506.4 | |||||||
| Realized (loss) gain on commodity-related derivative financial instruments | (4.5) | (2.9) | 1.7 | (15.6) | |||||||
| Operating margin | 225.8 | 177.5 | 673.4 | 454.1 | |||||||
| Depreciation and amortization included in operations | 46.5 | 51.6 | 120.7 | 125.8 | |||||||
| Unrealized (loss) gain on commodity-related derivative financial instruments | (2.1) | (23.0) | 5.1 | 38.3 | |||||||
| Gross profit | 177.2 | 102.9 | 557.8 | 366.6 | |||||||
Total enterprise value
Total enterprise value, in combination with other measures, is used by Management and the investment community to assess the overall market value of the business. Total enterprise value is calculated based on the market value of common shares, preferred shares and convertible debentures at a specific date plus senior debt.
Management believes these supplemental Non-GAAP measures facilitate the understanding of Pembina’s results from operations, leverage, liquidity and financial positions. Investors should be cautioned that net revenue, EBITDA, adjusted EBITDA, adjusted cash flow from operating activities, operating margin and total enterprise value should not be construed as alternatives to net earnings, cash flow from operating activities or other measures of financial results determined in accordance with GAAP as an indicator of Pembina’s performance. Furthermore, these Non-GAAP measures may not be comparable to similar measures presented by other issuers.
Forward-Looking Statements & Information
In the interest of providing our securityholders and potential investors with information regarding Pembina, including Management’s assessment of our future plans and operations, certain statements contained in this MD&A constitute forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of the “safe harbour” provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “should”, “could”, “believe”, “plan”, “intend”, “design”, “target”, “undertake”, “view”, “indicate”, “maintain”, “explore”, “entail”, “schedule”, “objective”, “strategy”, “likely”, “potential”, “envision”, “aim”, “outlook”, “propose”, “goal”, “would”, and similar expressions suggesting future events or future performance.
By their nature, such forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. Pembina believes the expectations reflected in those forward-looking statements are reasonable but no assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this MD&A should not be unduly relied upon. These statements speak only as of the date of the MD&A.
In particular, this MD&A contains forward-looking statements, including certain financial outlook, pertaining to the following:
Various factors or assumptions are typically applied by Pembina in drawing conclusions or making the forecasts, projections, predictions or estimations set out in forward-looking statements based on information currently available to Pembina. These factors and assumptions include, but are not limited to:
The actual results of Pembina could differ materially from those anticipated in these forward-looking statements as a result of the material risk factors set forth below:
These factors should not be construed as exhaustive. Unless required by law, Pembina does not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Any forward-looking statements contained herein are expressly qualified by this cautionary statement.
| CONDENSED CONSOLIDATED INTERIM STATEMENT OF FINANCIAL POSITION (unaudited) |
|||||||||||||||
| ($ millions) | Note | September 30 2013 |
December 31 2012 |
||||||||||||
| Assets | |||||||||||||||
| Current assets | |||||||||||||||
| Cash and cash equivalents | 15.5 | 27.3 | |||||||||||||
| Trade receivables and other | 395.5 | 331.7 | |||||||||||||
| Derivative financial instruments | 11 | 5.2 | 7.6 | ||||||||||||
| Inventory | 143.9 | 108.1 | |||||||||||||
| 560.1 | 474.7 | ||||||||||||||
| Non-current assets | |||||||||||||||
| Property, plant and equipment | 4 | 5,482.8 | 5,014.5 | ||||||||||||
| Intangible assets and goodwill | 2,577.0 | 2,622.7 | |||||||||||||
| Investments in equity accounted investees | 164.9 | 161.2 | |||||||||||||
| Derivative financial instruments | 11 | 0.7 | 0.3 | ||||||||||||
| Other receivables | 3.1 | ||||||||||||||
| Deferred tax assets | 17.0 | 7.7 | |||||||||||||
| 8,242.4 | 7,809.5 | ||||||||||||||
| Total Assets | 8,802.5 | 8,284.2 | |||||||||||||
| Liabilities and Shareholders’ Equity | |||||||||||||||
| Current liabilities | |||||||||||||||
| Trade payables and accrued liabilities | 433.6 | 344.7 | |||||||||||||
| Dividends payable | 43.7 | 39.6 | |||||||||||||
| Loans and borrowings | 5 | 261.8 | 11.7 | ||||||||||||
| Derivative financial instruments | 11 | 11.9 | 15.9 | ||||||||||||
| 751.0 | 411.9 | ||||||||||||||
| Non-current liabilities | |||||||||||||||
| Loans and borrowings | 5 | 1,388.0 | 1,932.8 | ||||||||||||
| Convertible debentures | 612.1 | 610.0 | |||||||||||||
| Derivative financial instruments | 11 | 83.2 | 51.8 | ||||||||||||
| Employee benefits | 28.0 | 28.6 | |||||||||||||
| Share-based payments | 13.0 | 17.2 | |||||||||||||
| Deferred revenue | 4.4 | 3.1 | |||||||||||||
| Provisions | 6 | 293.3 | 361.2 | ||||||||||||
| Deferred tax liabilities | 675.2 | 592.2 | |||||||||||||
| 3,097.2 | 3,596.9 | ||||||||||||||
| Total Liabilities | 3,848.2 | 4,008.8 | |||||||||||||
| Shareholders’ Equity | |||||||||||||||
| Equity attributable to shareholders of the Company: | |||||||||||||||
| Common share capital | 7 | 5,877.5 | 5,324.0 | ||||||||||||
| Preferred share capital | 8 | 244.4 | |||||||||||||
| Deficit | (1,146.7) | (1,027.7) | |||||||||||||
| Accumulated other comprehensive income | (26.1) | (26.1) | |||||||||||||
| 4,949.1 | 4,270.2 | ||||||||||||||
| Non-controlling interest | 5.2 | 5.2 | |||||||||||||
| Total Equity | 4,954.3 | 4,275.4 | |||||||||||||
| Total Liabilities and Shareholders’ Equity | 8,802.5 | 8,284.2 | |||||||||||||
| See accompanying notes to the condensed consolidated interim financial statements | |||||||||||||||
| CONDENSED CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE INCOME (unaudited) |
|||||||||||||||||||
| 3 Months Ended September 30 |
9 Months Ended September 30 |
||||||||||||||||||
| ($ millions, except per share amounts) | Note | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
| Revenue | 1,300.2 | 815.4 | 3,723.7 | 2,161.8 | |||||||||||||||
| Cost of sales | 1,116.4 | 686.6 | 3,172.7 | 1,817.9 | |||||||||||||||
| (Loss) gain on commodity-related derivative financial instruments | 11 | (6.6) | (25.9) | 6.8 | 22.7 | ||||||||||||||
| Gross profit | 177.2 | 102.9 | 557.8 | 366.6 | |||||||||||||||
| General and administrative | 29.8 | 26.9 | 88.6 | 70.2 | |||||||||||||||
| Acquisition-related and other expenses | 1.5 | 24.2 | |||||||||||||||||
| 29.8 | 28.4 | 88.6 | 94.4 | ||||||||||||||||
| Results from operating activities | 147.4 | 74.5 | 469.2 | 272.2 | |||||||||||||||
| Finance income | (3.5) | (6.9) | (12.2) | (9.2) | |||||||||||||||
| Finance costs | 39.5 | 40.0 | 123.4 | 88.6 | |||||||||||||||
| Net finance costs | 9 | 36.0 | 33.1 | 111.2 | 79.4 | ||||||||||||||
| Earnings before income tax and equity accounted investees | 111.4 | 41.4 | 358.0 | 192.8 | |||||||||||||||
| Share of (profit) loss of investments in equity accounted investees, net of tax | (0.4) | 0.5 | 0.3 | 0.9 | |||||||||||||||
| Current tax expense | 6.2 | 0.9 | 18.7 | 0.3 | |||||||||||||||
| Deferred tax expense | 33.8 | 9.3 | 82.9 | 47.9 | |||||||||||||||
| Income tax expense | 40.0 | 10.2 | 101.6 | 48.2 | |||||||||||||||
| Earnings and total comprehensive income for the period | 71.8 | 30.7 | 256.1 | 143.7 | |||||||||||||||
| Earnings and total comprehensive income (loss) attributable to: | |||||||||||||||||||
| Shareholders of the Company | 71.9 | 30.6 | 256.1 | 143.5 | |||||||||||||||
| Non-controlling interest | (0.1) | 0.1 | 0.2 | ||||||||||||||||
| 71.8 | 30.7 | 256.1 | 143.7 | ||||||||||||||||
| Basic and diluted earnings per share attributable to shareholders of the Company (dollars) |
0.22 | 0.11 | 0.83 | 0.58 | |||||||||||||||
| See accompanying notes to the condensed consolidated interim financial statements | |||||||||||||||||||
| CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN EQUITY (unaudited) |
|||||||||||||||||||||||
| Attributable to Shareholders of the Company | |||||||||||||||||||||||
| ($ millions) | Note | Common Shares |
Preferred Shares |
Deficit | Accumulated Other Comprehensive Income |
Total | Non-controlling Interest |
Total Equity |
|||||||||||||||
| December 31, 2012 | 5,324.0 | (1,027.7) | (26.1) | 4,270.2 | 5.2 | 4,275.4 | |||||||||||||||||
| Earnings and total comprehensive income for the period |
256.1 | 256.1 | 256.1 | ||||||||||||||||||||
| Transactions with shareholders of the Company |
|||||||||||||||||||||||
| Common shares issued, net of issue costs | 7 | 334.6 | 334.6 | 334.6 | |||||||||||||||||||
| Share-based payment transactions | 7 | 12.1 | 12.1 | 12.1 | |||||||||||||||||||
| Dividends declared | 7 | (375.1) | (375.1) | (375.1) | |||||||||||||||||||
| Preferred shares issued, net of issue costs | 8 | 244.4 | 244.4 | 244.4 | |||||||||||||||||||
| Dividend reinvestment plan | 7 | 210.8 | 210.8 | 210.8 | |||||||||||||||||||
| Debenture conversions and other | 7 | (4.0) | (4.0) | (4.0) | |||||||||||||||||||
| Total transactions with shareholders of the Company |
553.5 | 244.4 | (375.1) | 422.8 | 422.8 | ||||||||||||||||||
| September 30, 2013 | 5,877.5 | 244.4 | (1,146.7) | (26.1) | 4,949.1 | 5.2 | 4,954.3 | ||||||||||||||||
| December 31, 2011 | 1,811.7 | (834.9) | (15.2) | 961.6 | 961.6 | ||||||||||||||||||
| Earnings and total comprehensive income for the period |
143.4 | 143.4 | 0.3 | 143.7 | |||||||||||||||||||
| Transactions with shareholders of the Company |
|||||||||||||||||||||||
| Share-based payment transactions | 5.9 | 5.9 | 5.9 | ||||||||||||||||||||
| Debenture conversions and other | 0.4 | 0.4 | 0.4 | ||||||||||||||||||||
| Dividends declared | (299.2) | (299.2) | (299.2) | ||||||||||||||||||||
| Common shares issued on acquisition | 3,284.0 | 3,284.0 | 3,284.0 | ||||||||||||||||||||
| Dividend reinvestment plan | 151.1 | 151.1 | 151.1 | ||||||||||||||||||||
| Total transactions with shareholders of the Company |
3,441.4 | (299.2) | 3,142.2 | 3,142.2 | |||||||||||||||||||
| Non-controlling interest assumed on acquisition |
5.0 | 5.0 | |||||||||||||||||||||
| September 30, 2012 | 5,253.1 | (990.7) | (15.2) | 4,247.2 | 5.3 | 4,252.5 | |||||||||||||||||
| See accompanying notes to the condensed consolidated interim financial statements | |||||||||||||||||||||||
| CONDENSED CONSOLIDATED INTERIM STATEMENT OF CASH FLOWS (unaudited) |
||||||||||||||||||
| 3 Months Ended September 30 |
9 Months Ended September 30 |
|||||||||||||||||
| ($ millions) | Note | 2013 | 2012 | 2013 | 2012 | |||||||||||||
| Cash provided by (used in): | ||||||||||||||||||
| Operating activities: | ||||||||||||||||||
| Earnings for the period | 71.8 | 30.7 | 256.1 | 143.7 | ||||||||||||||
| Adjustments for: | ||||||||||||||||||
| Depreciation and amortization | 48.6 | 53.2 | 126.5 | 129.9 | ||||||||||||||
| Unrealized loss (gain) on commodity-related derivative financial instruments | 11 | 2.1 | 23.0 | (5.1) | (38.3) | |||||||||||||
| Net finance costs | 9 | 36.0 | 33.1 | 111.2 | 79.4 | |||||||||||||
| Share of (profit) loss of investments in equity accounted investees, net of tax | (0.4) | 0.5 | 0.3 | 0.9 | ||||||||||||||
| Deferred income tax expense | 33.8 | 9.3 | 82.9 | 47.9 | ||||||||||||||
| Share-based payments expense | 8.2 | 5.3 | 23.0 | 11.6 | ||||||||||||||
| Employee future benefits expense | 2.9 | 1.9 | 8.2 | 5.2 | ||||||||||||||
| Other | 0.1 | (0.4) | 0.7 | 0.1 | ||||||||||||||
| Changes in non-cash working capital | (101.4) | (0.6) | (84.2) | (78.1) | ||||||||||||||
| Payments from equity accounted investees | 5.4 | 1.5 | 14.6 | 9.2 | ||||||||||||||
| Decommissioning liability expenditures | (0.3) | (0.5) | (0.6) | (2.9) | ||||||||||||||
| Employer future benefit contributions | (3.1) | (2.5) | (9.4) | (7.5) | ||||||||||||||
| Net interest paid | (16.4) | (23.6) | (67.7) | (80.8) | ||||||||||||||
| Cash flow from operating activities | 87.3 | 130.9 | 456.5 | 220.3 | ||||||||||||||
| Financing activities: | ||||||||||||||||||
| Bank borrowings | 40.0 | 80.0 | 120.0 | 346.9 | ||||||||||||||
| Repayment of loans and borrowings | (115.9) | (0.8) | (617.8) | (60.8) | ||||||||||||||
| Issuance of debt | 200.0 | |||||||||||||||||
| Issuance of common shares | 345.2 | |||||||||||||||||
| Common share issue costs | (14.1) | |||||||||||||||||
| Issuance of preferred shares | 8 | 250.0 | 250.0 | |||||||||||||||
| Preferred share issue costs | (7.5) | (7.5) | ||||||||||||||||
| Financing fees | (0.1) | (3.0) | (5.1) | |||||||||||||||
| Exercise of stock options | 5.1 | 1.8 | 10.2 | 4.4 | ||||||||||||||
| Dividends paid (net of shares issued under the dividend reinvestment plan) | (53.8) | (50.8) | (160.1) | (130.7) | ||||||||||||||
| Cash flow from financing activities | 117.8 | 30.2 | 122.9 | 154.7 | ||||||||||||||
| Investing activities: | ||||||||||||||||||
| Capital expenditures | (244.8) | (143.3) | (604.6) | (329.6) | ||||||||||||||
| Changes in non-cash investing working capital and other | 47.8 | 4.6 | 23.9 | (28.2) | ||||||||||||||
| Contributions to equity accounted investees | (2.4) | (10.5) | ||||||||||||||||
| Cash acquired on acquisition | 8.9 | |||||||||||||||||
| Cash flow used in investing activities | (199.4) | (138.7) | (591.2) | (348.9) | ||||||||||||||
| Change in cash | 5.7 | 22.4 | (11.8) | 26.1 | ||||||||||||||
| Cash (bank indebtedness), beginning of period | 9.8 | 3.0 | 27.3 | (0.7) | ||||||||||||||
| Cash and cash equivalents, end of period | 15.5 | 25.4 | 15.5 | 25.4 | ||||||||||||||
| See accompanying notes to the condensed consolidated interim financial statements | ||||||||||||||||||
NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
1. REPORTING ENTITY
Pembina Pipeline Corporation (“Pembina” or the “Company”) is an energy transportation and service provider domiciled in Canada. The condensed consolidated unaudited interim financial statements (“Interim Financial Statements”) include the accounts of the Company, its subsidiary companies, partnerships and any interests in associates and jointly controlled entities as at and for the nine months ended September 30, 2013. These Interim Financial Statements and the notes thereto have been prepared in accordance with IAS 34 – Interim Financial Reporting. They do not include all of the information required for full annual financial statements and should be read in conjunction with the consolidated financial statements of the Company as at and for the year ended December 31, 2012. The interim financial statements were authorized for issue by the Board of Directors on November 1, 2013.
Pembina owns or has interests in pipelines that transport conventional crude oil, condensate and natural gas liquids (“NGL”), oil sands and heavy oil pipelines, gas gathering and processing facilities, and an NGL infrastructure and logistics business. Facilities are located in Canada and in the U.S. Pembina also offers midstream services that span across its operations.
The comparative statement of financial position as at December 31, 2012 was reclassified to present deferred tax assets of $7.7 million from one tax jurisdiction separate from deferred tax liabilities of another tax jurisdiction.
2. SIGNIFICANT ACCOUNTING POLICIES
The accounting policies are set out in the December 31, 2012 financial statements. Those policies have been applied consistently to all periods presented in these Interim Financial Statements.
New standards
The following new standards, interpretations, amendments and improvements to existing standards issued by the International Accounting Standard Board or International Financial Reporting Interpretations Committee were adopted as of January 1, 2013 without any material impact to Pembina’s Financial Statements: IFRS 7 Financial Instruments: Disclosures, IFRS 10 Consolidated Financial Statements, IFRS 11 Joint Arrangements, IFRS 12 Disclosure of interests in Other Entities, IFRS 13 Fair Value Measurement, and IAS 19 Employee Future Benefits.
3. DETERMINATION OF FAIR VALUES
A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and/or disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.
i) Property, plant and equipment
The fair value of property, plant and equipment recognized as a result of a business combination is based on market values when available and depreciated replacement cost when appropriate. Depreciated replacement cost reflects adjustments for physical deterioration as well as functional and economic obsolescence.
ii) Intangible assets
The fair value of intangible assets acquired in a business combination is determined using the multi-period excess earnings method, whereby the subject asset is valued after deducting a fair return on all other assets that are part of creating the related cash flows.
The fair value of other intangible assets is based on the discounted cash flows expected to be derived from the use and eventual sale of the assets.
iii) Derivatives
Fair value of derivatives, with the exception of a put option, are estimated by reference to independent monthly forward settlement prices, interest rate yield curves, currency rates, quoted market prices per share and volatility rates at the period ends.
The fair value of the put option is based on a contracted calculation of a multiple of earnings, adjusted for associated capital expenditures and debt based on management estimates (see Note 11 “Financial Instruments and Financial Risk Management”).
Fair values reflect the credit risk of the instrument and include adjustments to take account of the credit risk of the Company entity and counterparty when appropriate.
iv) Non-derivative financial assets and liabilities
Fair value, which is determined for disclosure purposes, is calculated based on the present value of future principal and interest cash flows, discounted at the market rate of interest at the reporting date. In respect of the convertible debentures, the fair value is determined by the market price of the convertible debenture on the reporting date. For finance leases the market rate of interest is determined by reference to similar lease agreements. For disclosure purposes, carrying value is a reasonable approximation for fair value for cash and cash equivalents, trade receivables and other, trade payables and accrued liabilities, finance lease liabilities and dividends payable.
v) Share-based payment transactions
The fair value of the employee share options is measured using the Black-Scholes formula. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option holder behaviour), expected dividends, expected forfeitures and the risk-free interest rate (based on government bonds). Service and non-market performance conditions attached to the transactions are not taken into account in determining fair value.
The fair value of the long-term share unit award incentive plan and associated distribution units are measured based on the reporting date market price of the Company’s shares. Expected dividends are not taken into account in determining fair value as they are issued as additional distribution share units.
4. PROPERTY, PLANT AND EQUIPMENT
| ($ millions) | Land and Land Rights |
Pipelines | Facilities and Equipment |
Linefill and Other |
Assets Under Construction |
Total | |||||||||||||||
| Cost | |||||||||||||||||||||
| Balance at December 31, 2012 | 88.0 | 2,593.7 | 2,072.2 | 506.6 | 751.8 | 6,012.3 | |||||||||||||||
| Additions | 0.2 | 87.3 | 71.3 | 9.3 | 433.5 | 601.6 | |||||||||||||||
| Change in decommissioning provision | (23.4) | (22.8) | (46.2) | ||||||||||||||||||
| Capitalized interest | 5.4 | 3.1 | 17.1 | 25.6 | |||||||||||||||||
| Transfers | 9.6 | 64.3 | 277.9 | 40.8 | (392.6) | ||||||||||||||||
| Disposals and other | (0.1) | (0.6) | 3.1 | 2.4 | |||||||||||||||||
| Balance at September 30, 2013 | 97.8 | 2,727.2 | 2,401.1 | 559.8 | 809.8 | 6,595.7 | |||||||||||||||
| Accumulated Depreciation | |||||||||||||||||||||
| Balance at December 31, 2012 | 4.4 | 776.7 | 171.9 | 44.8 | 997.8 | ||||||||||||||||
| Depreciation | 0.2 | 43.8 | 53.3 | 18.3 | 115.6 | ||||||||||||||||
| Disposals and other | (0.1) | (0.6) | 0.2 | (0.5) | |||||||||||||||||
| Balance at September 30, 2013 | 4.6 | 820.4 | 224.6 | 63.3 | 1,112.9 | ||||||||||||||||
| Carrying amounts | |||||||||||||||||||||
| December 31, 2012 | 83.6 | 1,817.0 | 1,900.3 | 461.8 | 751.8 | 5,014.5 | |||||||||||||||
| September 30, 2013 | 93.2 | 1,906.8 | 2,176.5 | 496.5 | 809.8 | 5,482.8 |
Commitments
At September 30, 2013, the Company had contractual commitments for the acquisition and or construction of property, plant and equipment of $1,187.4 million (December 31, 2012: $362.8 million).
5. LOANS AND BORROWINGS
This note provides information about the contractual terms of the Company’s interest-bearing loans and borrowings, which are measured at amortized cost.
Carrying value terms and debt repayment schedule
Terms and conditions of outstanding loans were as follows:
| ($ millions) | Carrying amount | ||||||||||||||||
| Available facilities at September 30, 2013 |
Nominal interest rate |
Year of maturity |
September 30, 2013 |
December 31, 2012 |
|||||||||||||
| Operating facility(1) | 30.0 | prime + 0.45 or BA(2) + 1.45 |
2014 | ||||||||||||||
| Revolving unsecured credit facility | 1,500.0 | prime + 0.45 or BA(2) + 1.45 |
2018 | 25.6 | 520.7 | ||||||||||||
| Senior unsecured notes – Series A | 175.0 | 5.99 | 2014 | 174.8 | 174.7 | ||||||||||||
| Senior unsecured notes – Series C | 200.0 | 5.58 | 2021 | 197.2 | 197.0 | ||||||||||||
| Senior unsecured notes – Series D | 267.0 | 5.91 | 2019 | 265.8 | 265.6 | ||||||||||||
| Senior unsecured term facility | 75.0 | 6.16 | 2014 | 74.9 | 74.8 | ||||||||||||
| Senior unsecured medium-term notes 1 | 250.0 | 4.89 | 2021 | 248.8 | 248.7 | ||||||||||||
| Senior unsecured medium-term notes 2 | 450.0 | 3.77 | 2022 | 447.9 | 447.9 | ||||||||||||
| Senior unsecured medium-term notes 3 | 200.0 | 4.75 | 2043 | 198.0 | |||||||||||||
| Subsidiary debt | 8.9 | 4.92 | 2014 | 8.9 | 9.3 | ||||||||||||
| Finance lease liabilities | 7.9 | 5.8 | |||||||||||||||
| Total interest bearing liabilities | 3,155.9 | 1,649.8 | 1,944.5 | ||||||||||||||
| Less current portion | (261.8) | (11.7) | |||||||||||||||
| Total non-current | 1,388.0 | 1,932.8 | |||||||||||||||
| (1) Operating facility expected to be renewed on an annual basis. |
| (2) Bankers’ Acceptance. |
Pembina’s $1.5 billion revolving unsecured credit facility was extended by one year from March 2017 to March 2018 and the $30 million operating facility was also extended by one year from July 2013 to July 2014.
6. PROVISIONS
| ($ millions) | Total | |
| Balance at December 31, 2012(1) | 361.7 | |
| Unwinding of discount rate | 6.5 | |
| Decommissioning liabilities settled during the period | (0.6) | |
| Change in rates | (74.1) | |
| Change in estimates and other | (0.1) | |
| Total | 293.4 | |
| Less current portion (included in accrued liabilities) | (0.1) | |
| Balance at September 30, 2013 | 293.3 | |
| (1) Includes current portion of $0.5 million (included in accrued liabilities). |
The Company applied a 2 percent inflation rate per annum (December 31, 2012: 2 percent) and a risk-free rate of 3.07 percent (December 31, 2012: 2.36 percent) to calculate the present value of the decommissioning provision. The remeasured decommissioning provision decreased property, plant and equipment and decommissioning provision liability. Of the re-measurement reduction of the decommissioning provision, $28 million was in excess of the carrying amount of the related asset and is recognized as a credit to depreciation expense.
7. COMMON SHARES
| ($ millions, except share amounts) | Number of Common Shares |
Common Share Capital |
|||||||||||||
| Balance December 31, 2012 | 293,226,473 | 5,324.0 | |||||||||||||
| Common shares issued, net of issue costs | 11,206,750 | 334.6 | |||||||||||||
| Share-based payment transactions | 522,119 | 12.1 | |||||||||||||
| Dividend reinvestment plan | 7,057,256 | 210.8 | |||||||||||||
| Debenture conversions and other | 71,037 | (4.0) | |||||||||||||
| Balance September 30, 2013 | 312,083,635(1) | 5,877.5 |
| (1) | Weighted average number of common shares outstanding for the three months ended September 30, 2013 is 310.8 million (September 30, 2012: 289.2 million). On a fully diluted basis, the weighted average number of common shares outstanding for the three months ended September 30, 2013 is 311.7 million (September 30, 2012: 289.7 million). Weighted average number of common shares outstanding for the nine months ended September 30, 2013 is 305.0 million (September 30, 2012: 247.8 million). On a fully diluted basis, the weighted average number of common shares outstanding for the nine months ended September 30, 2013 is 305.9 million (September 30, 2012: 248.4 million). |
On March 21, 2013, Pembina closed a bought deal offering of 11,206,750 shares at a price of $30.80 per share for aggregate gross proceeds of $345.2 million ($334.6 million, net of issue costs).
Dividends
The following dividends were declared by the Company:
| 9 Months Ended September 30 ($ millions, except per share amounts) | 2013 | 2012 | ||||||||||
| $1.23 per qualifying common share (2012: $1.20) | 375.1 | 299.2 |
On October 9, 2013, Pembina announced that the Board of Directors declared a dividend for October of $0.14 per qualifying common share ($1.68 annualized) in the total amount of $43.8 million.
8. PREFERRED SHARES
| ($ millions, except share amounts) | Number of Preferred Shares |
Preferred Share Capital |
||||||||||
| Preferred shares issued, net of issue costs | 10,000,000 | 244.4 | ||||||||||
| Balance September 30, 2013 | 10,000,000 | 244.4 |
On July 26, 2013, Pembina issued 10,000,000 cumulative redeemable 5-year rate reset Class A Preferred shares, Series 1 (“Series 1 Preferred Shares”) at a price of $25.00 per Series 1 Preferred Share for aggregate proceeds of $250 million. The holders of Series 1 Preferred Shares are entitled to receive fixed cumulative dividends at an annual rate of $1.0625 per share when declared by the Board of Directors. The dividend rate will reset on December 1, 2018 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.47 percent. The Series 1 Preferred Shares are redeemable by the Company at the Company’s option on December 1, 2018 and on December 1 of every fifth year thereafter.
Holders of the Series 1 Preferred Shares have the right to convert all or any part of their shares into cumulative redeemable floating rate Class A Preferred shares, Series 2 (“Series 2 Preferred Shares”), subject to certain conditions, on December 1, 2018 and on December 1 of every fifth year thereafter. Holders of Series 2 Preferred Shares will be entitled to receive cumulative quarterly floating dividends at a rate equal to the sum of the then 90-day Government of Canada Treasury Bill yield plus 2.47 percent, if, as and when declared by the Board of Directors of Pembina.
Dividends
On October 9, 2013, Pembina announced that the Board of Directors declared a dividend of $0.3726 per share for the period commencing July 26, 2013 to November 30, 2013, on the Series 1 Preferred Shares and a dividend of $0.1932 per share for the period commencing October 2, 2013 to November 30, 2013, on Pembina’s cumulative redeemable rate reset class A Preferred Shares, Series 3 (the “Series 3 Preferred Shares”) which were issued on October 2, 2013 (see Note 12). These initial dividends are payable on December 1, 2013 to shareholders of record at the close of business on November 1, 2013.
9. NET FINANCE COSTS
| 3 Months Ended September 30 |
9 Months Ended September 30 |
|||||||||||||||||
| ($ millions) | 2013 | 2012 | 2013 | 2012 | ||||||||||||||
| Interest income from: | ||||||||||||||||||
| Related parties | (0.2) | |||||||||||||||||
| Bank deposits and other | (0.5) | (0.4) | (5.1) | (0.7) | ||||||||||||||
| Interest expense on financial liabilities measured at amortized cost: | ||||||||||||||||||
| Loans and borrowings | 11.6 | 19.1 | 41.5 | 52.9 | ||||||||||||||
| Convertible debentures | 10.6 | 10.6 | 31.8 | 25.8 | ||||||||||||||
| Finance leases | 0.4 | 0.1 | 1.1 | 0.3 | ||||||||||||||
| Unwinding of discount | 2.3 | 3.3 | 6.5 | 9.1 | ||||||||||||||
| Gain in fair value of non-commodity-related derivative financial instruments | (3.0) | (6.5) | (7.1) | (4.1) | ||||||||||||||
| Loss (gain) revaluation of conversion feature of convertible debentures | 13.6 | 6.7 | 41.7 | (4.2) | ||||||||||||||
| Foreign exchange losses | 1.0 | 0.2 | 0.8 | 0.5 | ||||||||||||||
| Net finance costs | 36.0 | 33.1 | 111.2 | 79.4 | ||||||||||||||
10. OPERATING SEGMENTS
| 3 Months Ended September 30, 2013 ($ millions) | Conventional Pipelines(1) |
Oil Sands & Heavy Oil |
Gas Services |
Midstream(2) | Corporate & Intersegment Eliminations |
Total | ||||||||||||
| Revenue: | ||||||||||||||||||
| Pipeline transportation | 103.1 | 48.2 | (12.1) | 139.2 | ||||||||||||||
| Midstream services | 1,129.6 | (0.1) | 1,129.5 | |||||||||||||||
| Gas Services | 31.5 | 31.5 | ||||||||||||||||
| Total revenue | 103.1 | 48.2 | 31.5 | 1,129.6 | (12.2) | 1,300.2 | ||||||||||||
| Operations | 37.2 | 15.2 | 10.7 | 25.1 | (1.6) | 86.6 | ||||||||||||
| Cost of goods sold(3) | 994.8 | (11.5) | 983.3 | |||||||||||||||
| Realized gain (loss) on commodity-related derivative financial instruments | 0.4 | (4.9) | (4.5) | |||||||||||||||
| Operating margin | 66.3 | 33.0 | 20.8 | 104.8 | 0.9 | 225.8 | ||||||||||||
| Depreciation and amortization (operational) | 6.4 | 5.0 | 5.4 | 29.7 | 46.5 | |||||||||||||
| Unrealized gain (loss) on commodity-related derivative financial instruments | 0.1 | (2.2) | (2.1) | |||||||||||||||
| Gross profit | 60.0 | 28.0 | 15.4 | 72.9 | 0.9 | 177.2 | ||||||||||||
| Depreciation included in general and administrative | 2.1 | 2.1 | ||||||||||||||||
| Other general and administrative | 1.2 | 0.8 | 0.5 | 5.5 | 19.7 | 27.7 | ||||||||||||
| Acquisition-related and other expenses (income) | 0.2 | (0.2) | ||||||||||||||||
| Results from operating activities | 58.6 | 27.4 | 14.9 | 67.4 | (20.9) | 147.4 | ||||||||||||
| Net finance costs | 1.0 | 0.3 | 0.2 | (0.8) | 35.3 | 36.0 | ||||||||||||
| Earnings (loss) before tax and equity accounted investees | 57.6 | 27.1 | 14.7 | 68.2 | (56.2) | 111.4 | ||||||||||||
| Share of profit of investments in equity accounted investees, net of tax | 0.4 | 0.4 | ||||||||||||||||
| Capital expenditures | 78.6 | 8.4 | 80.2 | 76.7 | 0.9 | 244.8 | ||||||||||||
| 3 Months Ended September 30, 2012 ($ millions) | ||||||||||||||||||
| Revenue: | ||||||||||||||||||
| Pipeline transportation | 79.0 | 44.1 | (6.2) | 116.9 | ||||||||||||||
| Midstream services | 674.8 | 674.8 | ||||||||||||||||
| Gas Services | 23.7 | 23.7 | ||||||||||||||||
| Total revenue | 79.0 | 44.1 | 23.7 | 674.8 | (6.2) | 815.4 | ||||||||||||
| Operations | 30.1 | 14.8 | 7.1 | 18.2 | (0.6) | 69.6 | ||||||||||||
| Cost of goods sold(3) | 571.6 | (6.2) | 565.4 | |||||||||||||||
| Realized gain (loss) on commodity-related derivative financial instruments | 0.5 | (3.4) | (2.9) | |||||||||||||||
| Operating margin | 49.4 | 29.3 | 16.6 | 81.6 | 0.6 | 177.5 | ||||||||||||
| Depreciation and amortization (operational) | 12.0 | 5.0 | 3.4 | 31.2 | 51.6 | |||||||||||||
| Unrealized gain (loss) on commodity-related derivative financial instruments | (7.1) | (15.9) | (23.0) | |||||||||||||||
| Gross profit | 30.3 | 24.3 | 13.2 | 34.5 | 0.6 | 102.9 | ||||||||||||
| Depreciation included in general and administrative | 1.6 | 1.6 | ||||||||||||||||
| Other general and administrative | 1.9 | 0.5 | 1.0 | 4.4 | 17.5 | 25.3 | ||||||||||||
| Acquisition-related and other expenses (income) | 0.1 | 1.4 | 1.5 | |||||||||||||||
| Results from operating activities | 28.4 | 23.8 | 12.2 | 30.0 | (19.9) | 74.5 | ||||||||||||
| Net finance costs | 1.4 | 0.5 | (1.3) | (2.6) | 35.1 | 33.1 | ||||||||||||
| Earnings (loss) before tax and equity accounted investees | 27.0 | 23.3 | 13.5 | 32.6 | (55.0) | 41.4 | ||||||||||||
| Share of loss of investments in equity accounted investees, net of tax | 0.5 | 0.5 | ||||||||||||||||
| Capital expenditures | 34.7 | 6.1 | 29.8 | 70.7 | 2.0 | 143.3 | ||||||||||||
| (1) | 5.2 percent of Conventional Pipelines revenue is under regulated tolling arrangements (6.1 percent for quarter ending September 30, 2012). | |
| (2) | Midstream services revenue includes $24.9 million associated with U.S. midstream sales ($21.8 million for quarter ending September 30, 2012). | |
| (3) | Including product purchases. |
| 9 Months Ended September 30, 2013 ($ millions) | Conventional Pipelines(1) |
Oil Sands & Heavy Oil |
Gas Services |
Midstream(2) | Corporate & Intersegment Eliminations |
Total | ||||||||||||
| Revenue: | ||||||||||||||||||
| Pipeline transportation | 300.4 | 142.5 | (37.2) | 405.7 | ||||||||||||||
| Midstream services | 3,230.5 | (0.1) | 3,230.4 | |||||||||||||||
| Gas Services | 87.6 | 87.6 | ||||||||||||||||
| Total revenue | 300.4 | 142.5 | 87.6 | 3,230.5 | (37.3) | 3,723.7 | ||||||||||||
| Operations | 110.2 | 45.4 | 30.7 | 71.6 | (3.0) | 254.9 | ||||||||||||
| Cost of goods sold(3) | 2,833.7 | (36.6) | 2,797.1 | |||||||||||||||
| Realized gain (loss) on commodity-related derivative financial instruments | 2.2 | (0.5) | 1.7 | |||||||||||||||
| Operating margin | 192.4 | 97.1 | 56.9 | 324.7 | 2.3 | 673.4 | ||||||||||||
| Depreciation and amortization (operational) | 5.9 | 14.8 | 12.6 | 87.4 | 120.7 | |||||||||||||
| Unrealized gain (loss) on commodity-related derivative financial instruments | 2.4 | 2.7 | 5.1 | |||||||||||||||
| Gross profit | 188.9 | 82.3 | 44.3 | 240.0 | 2.3 | 557.8 | ||||||||||||
| Depreciation included in general and administrative | 5.8 | 5.8 | ||||||||||||||||
| Other general and administrative | 5.4 | 2.0 | 3.2 | 17.2 | 55.0 | 82.8 | ||||||||||||
| Acquisition-related and other expenses (income) | 0.8 | (0.3) | 0.1 | (0.6) | ||||||||||||||
| Results from operating activities | 182.7 | 80.6 | 41.1 | 222.7 | (57.9) | 469.2 | ||||||||||||
| Net finance costs | 3.0 | 0.9 | 0.5 | (2.7) | 109.5 | 111.2 | ||||||||||||
| Earnings (loss) before tax and equity accounted investees | 179.7 | 79.7 | 40.6 | 225.4 | (167.4) | 358.0 | ||||||||||||
| Share of loss of investments in equity accounted investees, net of tax | 0.3 | 0.3 | ||||||||||||||||
| Capital expenditures | 198.9 | 33.0 | 202.5 | 166.5 | 3.7 | 604.6 | ||||||||||||
| 9 Months Ended September 30, 2012 ($ millions) | ||||||||||||||||||
| Revenue: | ||||||||||||||||||
| Pipeline transportation | 239.6 | 126.6 | (13.1) | 353.1 | ||||||||||||||
| Midstream services | 1,743.7 | 1,743.7 | ||||||||||||||||
| Gas Services | 65.0 | 65.0 | ||||||||||||||||
| Total revenue | 239.6 | 126.6 | 65.0 | 1,743.7 | (13.1) | 2,161.8 | ||||||||||||
| Operations | 87.6 | 39.4 | 20.3 | 40.3 | (1.9) | 185.7 | ||||||||||||
| Cost of goods sold(3) | 1,519.5 | (13.1) | 1,506.4 | |||||||||||||||
| Realized gain (loss) on commodity-related derivative financial instruments | (0.7) | (14.9) | (15.6) | |||||||||||||||
| Operating margin | 151.3 | 87.2 | 44.7 | 169.0 | 1.9 | 454.1 | ||||||||||||
| Depreciation and amortization (operational) | 36.1 | 14.8 | 10.9 | 64.0 | 125.8 | |||||||||||||
| Unrealized gain (loss) on commodity-related derivative financial instruments | (9.8) | 48.1 | 38.3 | |||||||||||||||
| Gross profit | 105.4 | 72.4 | 33.8 | 153.1 | 1.9 | 366.6 | ||||||||||||
| Depreciation included in general and administrative | 4.1 | 4.1 | ||||||||||||||||
| Other general and administrative | 5.0 | 1.3 | 3.0 | 11.2 | 45.6 | 66.1 | ||||||||||||
| Acquisition-related and other expenses (income) | 0.9 | 0.4 | 0.2 | 22.7 | 24.2 | |||||||||||||
| Results from operating activities | 99.5 | 70.7 | 30.8 | 141.7 | (70.5) | 272.2 | ||||||||||||
| Net finance costs | 4.8 | 1.5 | 0.8 | 1.6 | 70.7 | 79.4 | ||||||||||||
| Earnings (loss) before tax and equity accounted investees | 94.7 | 69.2 | 30.0 | 140.1 | (141.2) | 192.8 | ||||||||||||
| Share of loss of investments in equity accounted investees, net of tax | 0.9 | 0.9 | ||||||||||||||||
| Capital expenditures | 99.2 | 12.1 | 85.6 | 126.6 | 6.1 | 329.6 | ||||||||||||
| (1) | 4.8 percent of Conventional Pipelines revenue is under regulated tolling arrangements (5.1 percent for quarter ending September 30, 2012). | ||
| (2) | Midstream services revenue includes $93.1 million associated with U.S. midstream sales ($50.5 million for nine months ending September 30, 2012). | ||
| (3) | Including product purchases. |
Certain comparative general and administrative expenses have been restated to be consistent with the current allocations applied.
11. FINANCIAL INSTRUMENTS AND FINANCIAL RISK MANAGEMENT
Fair values
The fair values of financial assets and liabilities, together with the carrying amounts shown in the statement of financial position, are as follows:
| September 30, 2013 | December 31, 2012 | |||||
| ($ millions) | Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
||
| Financial assets carried at fair value | ||||||
| Derivative financial instruments | 5.9 | 5.9 | 7.9 | 7.9 | ||
| Financial liabilities carried at fair value | ||||||
| Derivative financial instruments | 95.1 | 95.1 | 67.7 | 67.7 | ||
| Financial liabilities carried at amortized cost | ||||||
| Loans and borrowings | 1,649.8 | 1,740.7 | 1,944.5 | 2,089.7 | ||
| Convertible debentures | 612.1(1) | 809.1 | 610.0(1) | 725.0 | ||
| 2,261.9 | 2,549.8 | 2,554.5 | 2,814.7 | |||
| (1) | Carrying amount excludes conversion feature of convertible debentures. |
The basis for determining fair values is disclosed in Note 3.
Fair value hierarchy
The fair value of financial instruments carried at fair value is classified according to the following hierarchy based on the amount of observable inputs used to value the instruments.
Level 1: Unadjusted quoted prices are available in active markets for identical assets or liabilities as the reporting date. Pembina uses Level 1 inputs for the disclosed fair value measurements of the convertible debentures.
Level 2: Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices). Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter physical forwards and options, including those that have prices similar to quoted market prices. Pembina obtains quoted market prices for commodities, future power contracts, interest rates and foreign exchange rates from information sources including banks, Bloomberg Terminals and Natural Gas Exchange (NGX). With the exception of items described in Level 1 and 3, all of Pembina’s financial instruments carried at fair value are valued using Level 2 inputs.
Level 3: Valuations in this level require the most significant judgments and consist primarily of unobservable or non-market based inputs. Level 3 inputs include longer-term transactions, transactions in less active markets or transactions at locations for which pricing information is not available. In these instances, internally developed methodologies are used to determine fair value. The redemption liability related to acquisition of subsidiary is classified as a Level 3 instrument, as the fair value is determined by using inputs that are not based on observable market data. The liability represents a put option, held by the non-controlling interest of Three Star Trucking Ltd. (“Three Star”), to sell the remaining one-third of the business to Pembina after the third anniversary of the original acquisition date (October 3, 2014). The put price to be paid by the Company for the residual interest upon exercise is based on a multiple of Three Star’s earnings during the three year period prior to exercise, adjusted for associated capital expenditures and debt based on management estimates. These estimates are subject to measurement uncertainty and the effect on the financial statements of future periods could be material.
Financial instruments classified as Level 3
| ($ millions) | 2013 | ||||||
| Redemption liability, January 1, 2013 | 5.3 | ||||||
| Gain on revaluation | (1.9) | ||||||
| Redemption liability, September 30, 2013 | 3.4 | ||||||
The following table is a summary of the net derivative financial instrument liability:
| ($ millions) | September 30 2013 |
December 31 2012 |
|||||
| Frac spread related | (2.0) | (3.1) | |||||
| Product margin | (1.3) | (1.1) | |||||
| Corporate | |||||||
| Power | (2.9) | (7.1) | |||||
| Interest rate | (8.1) | (14.3) | |||||
| Foreign exchange | (0.4) | 0.7 | |||||
| Other derivative financial instruments | |||||||
| Conversion feature of convertible debentures | (71.1) | (29.6) | |||||
| Redemption liability related to acquisition of subsidiary | (3.4) | (5.3) | |||||
| Net derivative financial instruments liability | (89.2) | (59.8) | |||||
| Commodity-Related Derivative Financial Instruments | 3 Months Ended September 30 |
9 Months Ended September 30 |
||||
| ($ millions) | 2013 | 2012 | 2013 | 2012 | ||
| Realized (loss) gain on commodity-related derivative financial instruments | ||||||
| Frac spread related | (2.0) | (3.2) | (1.0) | (10.2) | ||
| Product margin | (3.3) | (0.4) | (1.2) | (4.4) | ||
| Power | 0.8 | 0.7 | 3.9 | (1.0) | ||
| Realized (loss) gain on commodity-related derivative financial instruments | (4.5) | (2.9) | 1.7 | (15.6) | ||
| Unrealized (loss) gain on commodity-related derivative financial instruments | (2.1) | (23.0) | 5.1 | 38.3 | ||
| (Loss) gain on commodity-related derivative financial instruments | (6.6) | (25.9) | 6.8 | 22.7 | ||
For non-commodity-related derivative financial instruments see Note 9, Net Finance Costs.
Sensitivity analysis
The following table shows the impact on earnings if the underlying risk variables of the derivative financial instruments changed by a specified amount, with other variables held constant.
| As at September 30, 2013 ($ millions) | + Change | – Change | |||||||||
| Frac spread related | |||||||||||
| Natural gas | (AECO +/- $1.00 per GJ) | 7.5 | (7.5) | ||||||||
| NGL (includes propane, butane, condensate) | (Belvieu +/- U.S. $0.10 per gal) | (5.7) | 5.7 | ||||||||
| Foreign exchange (U.S.$ vs. Cdn$) | (FX rate +/- $0.05) | (3.5) | 3.5 | ||||||||
| Product margin | |||||||||||
| Crude oil | (WTI +/- $5.00 per bbl) | (6.6) | 6.6 | ||||||||
| NGL (includes condensate) | (Belvieu +/- U.S. $0.10 per gal) | 4.8 | (4.8) | ||||||||
| Corporate | |||||||||||
| Interest rate | (Rate +/- 50 basis points) | 2.6 | (2.6) | ||||||||
| Power | (AESO +/- $5.00 per MW/h) | 4.3 | (4.3) | ||||||||
| Conversion feature of convertible debentures | (Pembina share price +/- $0.50 per share) | (3.5) | 3.4 | ||||||||
12. SUBSEQUENT EVENTS
On October 2, 2013, Pembina closed its offering of 6,000,000 cumulative redeemable rate reset Class A Preferred shares, Series 3 (the “Series 3 Preferred Shares”) at a price of $25.00 per share for aggregate proceeds of $150 million. The holders of Series 3 Preferred Shares are entitled to receive fixed cumulative dividends at an annual rate of $1.1750 per share, if, as and when declared by the Board of Directors. The dividend rate will reset on March 1, 2019 and every five years thereafter at a rate equal to the sum of the then five-year Government of Canada bond yield plus 2.60 percent. The Series 3 Preferred Shares are redeemable by the Company at its option on March 1, 2019 and on March 1 of every fifth year thereafter.
Holders of the Series 3 Preferred Shares have the right to convert their shares into cumulative redeemable floating rate Class A Preferred shares, Series 4 (“Series 4 Preferred Shares”), subject to certain conditions, on March 1, 2019 and on March 1 of every fifth year thereafter. Holders of Series 4 Preferred Shares will be entitled to receive a cumulative quarterly floating dividend at a rate equal to the sum of the then 90-day Government of Canada Treasury Bill yield plus 2.60 percent, if, as and when declared by the Board of Directors of Pembina.
Proceeds from the offering were used to partially fund capital projects and for other general corporate purposes of the Company. The Series 3 Preferred Shares began trading on the Toronto Stock Exchange on October 2, 2013 under the symbol PPL.PR.C.
CORPORATE INFORMATION
HEAD OFFICE
Pembina Pipeline Corporation
Suite 3800, 525 – 8th Avenue S.W.
Calgary, Alberta T2P 1G1
AUDITORS
KPMG LLP
Chartered 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
TSX listing symbols for:
Common shares: PPL
Preferred shares: PPL.PR.A, PPL.PR.C
Convertible debentures: PPL.DB.C, PPL.DB.E, PPL.DB.F
NYSE listing symbol for:
Common shares: PBA
SOURCE Pembina Pipeline Corporation
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