HOUSTON, TX--(Marketwired - Nov 1, 2017) - Enbridge Energy Partners, L.P. (
Q3 HIGHLIGHTS
- Third quarter net income was $93.1 million and cash provided by operating activities for the nine month period was $388.8 million
- Third quarter adjusted earnings before interest, taxes and depreciation (EBITDA) and distributable cash flow (DCF) were $426.2 million and $193.6 million, respectively
- Line 3 Replacement Program progressing well; regulatory hearings in the State of Minnesota are under way
- Enbridge Energy Partners, L.P. received an amended Presidential Permit for the expansion of the Alberta Clipper liquids pipeline
Enbridge Energy Partners, L.P. (
Third quarter results were in-line with the Partnership's expectations demonstrating the reliability of the restructured business model. The Lakehead system, which is the most significant contributor to results, provided stable and predictable earnings resulting from the regulated cost of service nature of the business that has limited financial exposure to throughput volatility.
In the Bakken region, demand for transportation on the legacy North Dakota system into Clearbrook, Minnesota remained strong, averaging over 219 kbpd for the third quarter. Results also benefited from a full quarter of contributions from EEP's interest in the Bakken Pipeline System that was placed into service on June 1, 2017.
"Our results for the quarter are right in-line with our expectations," said Mark Maki, President for the Partnership. "This quarter represents the first full quarter following our restructuring to a new lower risk, pure-play business model. With the sale of the natural gas business now closed, the Partnership has returned to its core business of stable liquids pipeline and storage assets. As a result, we are on track to deliver on our previously disclosed guidance," concluded Mr. Maki.
Line 3 Replacement Program The Line 3 Replacement is a critical energy infrastructure program that will support the economy and assure a reliable and cost-effective supply of energy. It will comprise the newest and most advanced pipeline technology and will enhance safety, reliability, and throughput capacity on the Mainline system.
Regulatory permitting is in place in North Dakota and in Wisconsin where construction is well under way. The most significant remaining permitting process for the Line 3 Replacement Program is in Minnesota. The Final Environmental Impact Statement was issued in August and its adequacy determination is expected from the Minnesota Public Utilities Commission ("MPUC") in December. In the parallel Certificate of Need and Route Permit dockets, progress continues according to schedule with public hearings currently under way. The MPUC is expected to issue a decision on the Certificate of Need and Route Permit in the second quarter of 2018. Based on this regulatory process and timeline, Management continues to anticipate an in-service date for the project in the second half of 2019.
In addition, subsequent to quarter-end, EEP received an amended Presidential Permit for the Alberta Clipper (Line 67) expansion project.
Third Quarter 2017 Performance Overview
The Partnership's key financial results for the three and nine months ended September 30, 2017, compared to the same periods in 2016, were as follows:
| Three months ended September 30, | Nine months ended September 30, | |||||||||||||||
| (unaudited; in millions, except per unit amounts) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Net income (loss) (1) | $ | 93.1 | $ | (406.4 | ) | $ | 251.2 | $ | (242.7 | ) | ||||||
| Net income (loss) per unit (basic and diluted) | 0.19 | (1.31 | ) | 0.55 | (1.16 | ) | ||||||||||
| Adjusted EBITDA (2) | $ 426.2 | $ 456.8 | $ 1,237.1 | $ 1,412.3 | ||||||||||||
| Adjusted net income (1) | 109.3 | 89.3 | 243.1 | 338.7 | ||||||||||||
| Adjusted net income per unit (basic and diluted) | $ | 0.24 | $ | 0.09 | $ | 0.54 | $ | 0.48 | ||||||||
(1) Net income and adjusted net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. (2) Includes noncontrolling interests.
Adjusted net income and adjusted EBITDA for the three and nine months ended September 30, 2017, as reported above, eliminate the effect of: (a) non-cash, mark-to-market net gains and losses; and (b) other adjustments. Refer to the Non-GAAP Reconciliations section below for additional details.
Net income for the third quarter of 2017 increased $499.5 million over the same period from the prior year primarily due to the absence of an asset impairment loss of $756.7 million in 2017, as the Sandpiper Project in North Dakota was impaired when the project's regulatory application was withdrawn in the third quarter of 2016. Further contributing to the increase was the absence of losses from our discontinued operations when compared with the corresponding 2016 period as we sold our Midcoast gas gathering and processing business on June 28, 2017, to our General Partner.
Adjusted net income of $109.3 million for the third quarter of 2017 was $20.0 million higher than the same period from the prior year. The increase was predominately attributable to the absence of Series 1 Preferred Units, which were redeemed on April 27, 2017, at the conclusion of our strategic review. Also contributing to the increase was the absence of losses from our Midcoast gas gathering and processing business and equity income from our investment in the Bakken Pipeline System.
| COMPARATIVE EARNINGS STATEMENT | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited; in millions, except per unit amounts) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Operating revenues | $ | 616.4 | $ | 634.6 | $ | 1,817.6 | $ | 1,885.6 | ||||||||
| Operating expenses: | ||||||||||||||||
| Environmental costs, net of recoveries | 1.2 | (8.7 | ) | 15.0 | 8.3 | |||||||||||
| Operating and administrative | 162.6 | 152.0 | 474.0 | 428.0 | ||||||||||||
| Power | 80.1 | 74.3 | 221.0 | 206.8 | ||||||||||||
| Depreciation and amortization | 111.8 | 109.4 | 328.9 | 315.7 | ||||||||||||
| Gain on sale of assets | (5.5 | ) | -- | (67.6 | ) | -- | ||||||||||
| Asset impairment | -- | 756.7 | -- | 757.1 | ||||||||||||
| Operating income (loss) | 266.2 | (449.1 | ) | 846.3 | 169.7 | |||||||||||
| Interest expense, net | (104.1 | ) | (103.4 | ) | (305.8 | ) | (301.2 | ) | ||||||||
| Allowance for equity used during construction | 12.2 | 10.0 | 33.2 | 35.7 | ||||||||||||
| Other income | 21.8 | 0.6 | 33.2 | 0.9 | ||||||||||||
| Income (loss) from continuing operations before income taxes | 196.1 | (541.9 | ) | 606.9 | (94.9 | ) | ||||||||||
| Income tax benefit (expense) | (0.1 | ) | (1.6 | ) | 0.4 | (5.2 | ) | |||||||||
| Income (loss) from continuing operations | 196.0 | (543.5 | ) | 607.3 | (100.1 | ) | ||||||||||
| Loss from discontinued operations, net of tax | -- | (31.1 | ) | (56.8 | ) | (124.4 | ) | |||||||||
| Net income (loss) | 196.0 | (574.6 | ) | 550.5 | (224.5 | ) | ||||||||||
| Less: Net income (loss) attributable to: | ||||||||||||||||
| Noncontrolling interests | 102.9 | (191.9 | ) | 261.8 | (52.8 | ) | ||||||||||
| Series 1 preferred unit distributions | -- | 22.5 | 29.0 | 67.5 | ||||||||||||
| Accretion of discount on Series 1 preferred units | -- | 1.2 | 8.5 | 3.5 | ||||||||||||
| Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. | $ | 93.1 | $ | (406.4 | ) | $ | 251.2 | $ | (242.7 | ) | ||||||
| Net income (loss) allocable to common units and i-units | ||||||||||||||||
| Income from continuing operations | $ | 82.0 | $ | (432.7 | ) | $ | 254.1 | $ | (313.9 | ) | ||||||
| Loss from discontinued operations | -- | (19.9 | ) | (38.0 | ) | (86.9 | ) | |||||||||
| Net income (loss) allocable to common units and i-units | $ | 82.0 | $ | (452.6 | ) | $ | 216.1 | $ | (400.8 | ) | ||||||
| Net income (loss) per common unit and i-unit (basic and diluted) | ||||||||||||||||
| Income from continuing operations | $ | 0.19 | $ | (1.25 | ) | $ | 0.65 | $ | (0.91 | ) | ||||||
| Loss from discontinued operations | -- | (0.06 | ) | (0.10 | ) | (0.25 | ) | |||||||||
| Net income (loss) per common unit and i-unit | $ | 0.19 | $ | (1.31 | ) | $ | 0.55 | $ | (1.16 | ) | ||||||
| Weighted average common units and i-units (basic and diluted) | 421.0 | 349.1 | 391.6 | 347.0 | ||||||||||||
Comparison of Quarterly Results
Following are explanations for significant changes in the Partnership's financial results, comparing the three and nine months ended September 30, 2017 with the same period of 2016. The comparison refers to operating income and adjusted operating income. Adjusted operating income excludes the effect of certain non-cash and other items that the Partnership believes are not indicative of its core operating results (see Non-GAAP Reconciliations section below).
| Operating Income (Loss) | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited; in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Liquids | $ | 267.9 | $ | (446.8 | ) | $ | 855.4 | $ | 179.1 | |||||||
| Other | (1.7 | ) | (2.3 | ) | (9.1 | ) | (9.4 | ) | ||||||||
| Operating income (loss) | $ | 266.2 | $ | (449.1 | ) | $ | 846.3 | $ | 169.7 | |||||||
| Adjusted Operating Income (Loss) | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited; in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Liquids | $ | 282.1 | $ | 304.0 | $ | 827.8 | $ | 945.3 | ||||||||
| Other | (1.7 | ) | (2.3 | ) | (9.1 | ) | (9.4 | ) | ||||||||
| Adjusted operating income | $ | 280.4 | $ | 301.7 | $ | 818.7 | $ | 935.9 | ||||||||
Liquids Third quarter operating income for the Liquids segment increased $714.7 million to $267.9 million over the comparable period in 2016. This increase was predominately attributable to the absence of a one-time impairment loss in 2016, due to the withdrawal of our regulatory application on the Sandpiper Project during the third quarter of 2016.
The increase in operating income for the Liquids segment was partially offset by lower operating revenues from the North Dakota system primarily due to the expiration of Phase 5 and Phase 6 expansion surcharges and lower spot volumes on the Bakken Pipeline, which is a component of the North Dakota system that delivers volume into the Cromer, Manitoba area. In addition, operating income excludes margins from the Ozark Pipeline system which was sold on March 1, 2017.
Third quarter adjusted operating income for the Liquids segment decreased $21.9 million to $282.1 million over the comparable period in 2016 due to the same operating factors described above, which exclude the impact of a one-time impairment loss on the Sandpiper Project, gains on sale of assets and the impact of non-cash, mark-to market gains and losses.
| Liquids Systems Volumes | Three months ended September 30, | Nine months ended September 30, | ||||||||||
| (thousand barrels per day) | 2017 | 2016 | 2017 | 2016 | ||||||||
| Lakehead | 2,620 | 2,495 | 2,657 | 2,558 | ||||||||
| Mid-Continent | -- | 217 | 33 | 200 | ||||||||
| North Dakota | 303 | 363 | 330 | 382 | ||||||||
| Total | 2,923 | 3,075 | 3,020 | 3,140 | ||||||||
Discontinued Operations
| Discontinued Operations | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited; in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Net loss from discontinued operations | $ | -- | $ | (31.1 | ) | $ | (56.8 | ) | $ | (124.4 | ) | |||||
| Adjusted net loss from discontinued operations | $ | -- | $ | (17.8 | ) | $ | (66.5 | ) | $ | (46.6 | ) | |||||
Third quarter losses from discontinued operations decreased $31.1 million over the comparable period in 2016. This decrease was attributable to the absence of losses from the Natural Gas segment for the three months ended September 30, 2017, resulting from the sale of our Midcoast gas and processing business to our General Partner on June 28, 2017.
Third quarter adjusted loss from discontinued operations decreased $17.8 million over the comparable period in 2016 due to the same operating factors described above.
| Natural Gas Throughput | Three months ended September 30, | Nine months ended September 30, | ||||||||||
| (MMBtu per day) | 2017 | 2016 | 2017 | 2016 | ||||||||
| East Texas | -- | 894,000 | 877,000 | 924,000 | ||||||||
| Anadarko | -- | 606,000 | 514,000 | 632,000 | ||||||||
| North Texas | -- | 192,000 | 174,000 | 202,000 | ||||||||
| Total | -- | 1,692,000 | 1,565,000 | 1,758,000 | ||||||||
| NGL Production | Three months ended September 30, | Nine months ended September 30, | ||||||||||
| (Barrels per day) | 2017 | 2016 | 2017 | 2016 | ||||||||
| Total System Production | -- | 67,588 | 63,389 | 70,932 | ||||||||
Conference Call Details
The Partnership will host a joint conference call and webcast at 9:00 a.m. Eastern Time (7 a.m. Mountain Time) on November 2, 2017, with Enbridge Inc. (
The conference call format will include prepared remarks from the executive team followed by a question and answer session for the analyst and investor community only. Enbridge's media and investor relations teams will be available after the call for any additional questions.
Non-GAAP Reconciliations
Reconciliations of forward looking non-GAAP financial measures to comparable GAAP measures are not available due to the challenges with estimating some of the items, particularly with estimating non-cash unrealized derivative fair value losses and gains, which are subject to market variability and therefore a reconciliation is not available without unreasonable effort.
Adjusted Net Income and Adjusted Operating Income
Adjusted net income for the Partnership and adjusted operating income for the principal business segments are provided to illustrate trends in income excluding non-cash unrealized derivative fair value losses and gains and other items that Management believes are not indicative of the Partnership's core operating results. The derivative non-cash losses and gains result from marking to market certain financial derivatives used by the Partnership for hedging purposes that do not qualify for hedge accounting treatment in accordance with the authoritative accounting guidance as prescribed under generally accepted accounting principles in the United States. Non-GAAP measures no longer include make-up rights and option premium amortization adjustments. These changes were made on a prospective basis beginning with the second quarter of 2016 and are not material for historical periods presented.
| Adjusted Net Income | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited; in millions, except per unit amounts) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. | $ | 93.1 | $ | (406.4 | ) | $ | 251.2 | $ | (242.7 | ) | ||||||
| Noncash derivative fair value (gains) losses: | ||||||||||||||||
| -Liquids | 1.7 | 0.2 | (1.0 | ) | 7.0 | |||||||||||
| -Natural Gas ( included in Discontinued Operations) | -- | 11.1 | (12.0 | ) | 66.6 | |||||||||||
| -Other | 0.3 | -- | 2.2 | 3.4 | ||||||||||||
| Accretion of discount on Series 1 preferred units | -- | 1.2 | 8.5 | 3.5 | ||||||||||||
| Make-up rights adjustment | -- | -- | -- | 1.0 | ||||||||||||
| Line 2 hydrotest expenses, net of recoveries | -- | (2.0 | ) | -- | (10.3 | ) | ||||||||||
| Line 6A and 6B incident expenses, net of recoveries | -- | (10.0 | ) | -- | 6.0 | |||||||||||
| Option premium amortization | -- | -- | -- | 0.9 | ||||||||||||
| Sandpiper Project wind down costs | 0.4 | 3.7 | 4.3 | 3.7 | ||||||||||||
| Gain on sale of assets | (3.4 | ) | 1.6 | (35.7 | ) | 1.6 | ||||||||||
| Severance costs | -- | 0.6 | 7.6 | 0.6 | ||||||||||||
| Asset impairment | -- | 489.3 | -- | 497.4 | ||||||||||||
| Integration costs | 17.2 | -- | 18.0 | -- | ||||||||||||
| Adjusted net income | $ | 109.3 | $ | 89.3 | $ | 243.1 | $ | 338.7 | ||||||||
| Less: Allocations to general partner | 12.2 | 56.1 | 34.9 | 169.7 | ||||||||||||
| Adjusted net income allocable to common units and i-units | $ | 97.1 | $ | 33.2 | $ | 208.2 | $ | 169.0 | ||||||||
| Weighted average common units and i-units outstanding | 421.0 | 349.1 | 391.6 | 347.0 | ||||||||||||
| Adjusted net income per common unit and i-unit (basic and diluted) | $ | 0.24 | $ | 0.09 | $ | 0.54 | $ | 0.48 | ||||||||
| Adjusted Net Income Per common unit and i-unit | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Net income (loss) per common unit and i-unit (basic and diluted) interests in Enbridge Energy Partners, L.P. | $ | 0.19 | $ | (1.31 | ) | $ | 0.55 | $ | (1.16 | ) | ||||||
| Noncash derivative fair value (gains) losses: | ||||||||||||||||
| -Liquids | 0.01 | -- | -- | 0.02 | ||||||||||||
| -Natural Gas (included in Discontinued Operations) | -- | 0.03 | (0.03 | ) | 0.17 | |||||||||||
| -Other | -- | -- | 0.01 | 0.01 | ||||||||||||
| Accretion of discount on Series 1 preferred units | -- | -- | 0.02 | 0.01 | ||||||||||||
| Make-up rights adjustment | -- | -- | -- | -- | ||||||||||||
| Line 2 hydrotest expenses, net of recoveries | -- | (0.01 | ) | -- | (0.03 | ) | ||||||||||
| Line 6A and 6B incident expenses, net of recoveries | -- | (0.03 | ) | -- | 0.02 | |||||||||||
| Option premium amortization | -- | -- | -- | -- | ||||||||||||
| Sandpiper Project wind down costs | -- | 0.01 | 0.01 | 0.01 | ||||||||||||
| Gain on sale of assets | (0.01 | ) | -- | (0.09 | ) | -- | ||||||||||
| Severance costs | -- | -- | 0.02 | -- | ||||||||||||
| Asset impairment | -- | 1.40 | -- | 1.43 | ||||||||||||
| Integration costs | 0.05 | -- | 0.05 | -- | ||||||||||||
| Adjusted net income per common unit and i-unit (basic and diluted) | $ | 0.24 | $ | 0.09 | $ | 0.54 | $ | 0.48 | ||||||||
| Weighted average common units and i-units outstanding | 421.0 | 349.1 | 391.6 | 347.0 | ||||||||||||
| Liquids | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited; in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Operating income (loss) | $ | 267.9 | $ | (446.8 | ) | $ | 855.4 | $ | 179.1 | |||||||
| Noncash derivative fair value (gains) losses | 1.7 | 0.2 | (1.0 | ) | 7.0 | |||||||||||
| Make-up rights adjustment | -- | -- | -- | 0.9 | ||||||||||||
| Line 2 hydrotest expenses, net of recoveries | -- | (2.0 | ) | -- | (10.3 | ) | ||||||||||
| Line 6A and 6B incident expenses, net of recoveries | -- | (10.0 | ) | -- | 6.0 | |||||||||||
| Gain on sale of assets | (5.5 | ) | -- | (57.0 | ) | -- | ||||||||||
| Sandpiper Project wind down costs | 0.8 | 5.9 | 7.1 | 5.9 | ||||||||||||
| Severance costs | -- | -- | 5.5 | -- | ||||||||||||
| Integration costs | 17.2 | -- | 17.8 | -- | ||||||||||||
| Asset impairment | -- | 756.7 | -- | 756.7 | ||||||||||||
| Adjusted operating income | $ | 282.1 | $ | 304.0 | $ | 827.8 | $ | 945.3 | ||||||||
| Discontinued Operations | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited; in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Net loss from discontinued operations | $ | -- | $ | (31.1 | ) | $ | (56.8 | ) | $ | (124.4 | ) | |||||
| Noncash derivative fair value (gains) losses | -- | 11.1 | (12.0 | ) | 66.6 | |||||||||||
| Option premium amortization (1) | -- | -- | -- | 0.9 | ||||||||||||
| Loss on sale of non-core assets | -- | 1.6 | -- | 1.6 | ||||||||||||
| Severance costs | -- | 0.6 | 2.1 | 0.6 | ||||||||||||
| Integration costs | -- | -- | 0.2 | -- | ||||||||||||
| Asset impairment | -- | -- | -- | 8.1 | ||||||||||||
| Adjusted net loss from discontinued operations | $ | -- | $ | (17.8 | ) | $ | (66.5 | ) | $ | (46.6 | ) | |||||
| (1) | Adjusted operating income no longer includes option premium amortization adjustments due to recent SEC interpretations. These changes will be made on a prospective basis and are not material for historical periods presented. |
Adjusted EBITDA and Distributable Cash Flow
Adjusted EBITDA (adjusted earnings before interest, taxes, depreciation and amortization) is used as a supplemental financial measurement to manage the performance of the entity. Distributable cash flow is used as a supplemental financial measurement to assess liquidity and the ability to generate cash sufficient to pay interest costs and make cash distributions to unitholders. The following reconciliations of net income to adjusted EBITDA and net cash provided by operating activities to distributable cash flow are provided because adjusted EBITDA and distributable cash flow are not financial measures recognized under generally accepted accounting principles.
| Adjusted EBITDA | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited; in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. | $ | 93.1 | $ | (406.4 | ) | $ | 251.2 | $ | (242.7 | ) | ||||||
| Net income attributable to noncontrolling interest | 102.9 | (191.9 | ) | 261.8 | (52.8 | ) | ||||||||||
| Series 1 preferred unit distributions | -- | 22.5 | 29.0 | 67.5 | ||||||||||||
| Accretion of discount on Series 1 preferred units | -- | 1.2 | 8.5 | 3.5 | ||||||||||||
| Interest expense, income tax expense, and depreciation | ||||||||||||||||
| and amortization - discontinued operations | -- | 48.7 | 92.9 | 146.2 | ||||||||||||
| Interest expense, net | 104.1 | 103.4 | 305.8 | 301.2 | ||||||||||||
| Income tax expense (benefit) | 0.1 | 1.6 | (0.4 | ) | 5.2 | |||||||||||
| Depreciation and amortization | 111.8 | 109.4 | 328.9 | 315.7 | ||||||||||||
| Noncash derivative fair value (gains) losses | 1.7 | 14.8 | (16.9 | ) | 94.5 | |||||||||||
| Make-up rights adjustment | -- | -- | -- | 1.0 | ||||||||||||
| Line 2 hydrotest expense, net of recoveries | -- | (2.0 | ) | -- | (10.3 | ) | ||||||||||
| Line 6A and 6B incident expenses, net of recoveries | -- | (10.0 | ) | -- | 6.0 | |||||||||||
| Option premium amortization | -- | -- | -- | 1.2 | ||||||||||||
| Loss on sale of non-core assets | -- | 2.1 | -- | 2.1 | ||||||||||||
| Gain on sale of assets | (5.5 | ) | -- | (57.0 | ) | -- | ||||||||||
| Sandpiper project wind down costs | 0.8 | 5.9 | 7.1 | 5.9 | ||||||||||||
| Severance costs | -- | 0.8 | 8.2 | 0.8 | ||||||||||||
| Integration costs | 17.2 | -- | 18.0 | -- | ||||||||||||
| Asset impairment | -- | 756.7 | -- | 756.7 | ||||||||||||
| Asset impairment - discontinued operations | -- | -- | -- | 10.6 | ||||||||||||
| Adjusted EBITDA | $ | 426.2 | $ | 456.8 | $ | 1,237.1 | $ | 1,412.3 | ||||||||
| Distributable Cash Flow | Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
| (unaudited; in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
| Total net cash provided by operating activities | $ | 345.1 | $ | 414.6 | $ | 388.8 | $ | 961.1 | ||||||||
| Changes in operating assets and liabilities, | ||||||||||||||||
| net of cash acquired | (35.2 | ) | (73.3 | ) | 511.8 | 120.7 | ||||||||||
| Allowance for equity used during construction (1) | -- | 10.1 | -- | 35.7 | ||||||||||||
| Option premium amortization | -- | -- | -- | 1.2 | ||||||||||||
| Line 2 hydrotest expense, net of recoveries | -- | (2.0 | ) | -- | (10.3 | ) | ||||||||||
| Distributions in excess of equity earnings | 3.2 | 3.0 | 3.3 | 5.7 | ||||||||||||
| Maintenance capital expenditures | (10.4 | ) | (15.8 | ) | (26.2 | ) | (35.5 | ) | ||||||||
| Noncontrolling interests | (115.9 | ) | (119.1 | ) | (307.0 | ) | (345.4 | ) | ||||||||
| Gain on sale of assets | -- | -- | 10.6 | -- | ||||||||||||
| Distribution support agreement (2) | -- | (2.4 | ) | -- | (3.8 | ) | ||||||||||
| Other | 6.8 | (0.4 | ) | (7.5 | ) | (7.5 | ) | |||||||||
| Distributable cash flow | $ | 193.6 | $ | 214.7 | $ | 573.8 | $ | 721.9 | ||||||||
| (1) | Distributable cash flow excludes allowance for equity used during construction beginning Q1 2017. |
| (2) | Distribution agreement in place with MEP to support 1.0x coverage of the then declared distribution with a term through 2017, and no requirement for MEP to reimburse EEP for adjusted distributions. |
Forward-Looking Statements
This news release includes forward-looking statements, which are statements that frequently use words such as "anticipate," "believe," "consider," "continue," "could," "estimate," "evaluate," "expect," "explore," "forecast," "intend," "may," "opportunity," "plan," "position," "projection," "should," "strategy," "target," "will" and similar words. Although the Partnership believes that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Any forward-looking statement made by the Partnership in this release speaks only as of the date on which it is made, and the Partnership undertakes no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond the Partnership's ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) the effectiveness of the various actions the Partnership has announced resulting from its strategic review process; (2) changes in the demand for the supply of, forecast data for, and price trends related to crude oil, liquid petroleum, including the rate of development of the Alberta Oil Sands; (3) the Partnership's ability to successfully complete and finance expansion projects; (4) the effects of competition, in particular, by other pipeline systems; (5) shut-downs or cutbacks at the Partnership's facilities or refineries, petrochemical plants, utilities or other businesses for which the Partnership transports products or to whom it sell products; (6) hazards and operating risks that may not be covered fully by insurance, including those related to Line 6B and any additional fines and penalties and injunctive relief assessed in connection with the crude oil release on that line; (7) changes in or challenges to the Partnership's tariff rates; (8) changes in laws or regulations to which the Partnership is subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; and (9) permitting at federal, state and local level or renewals of rights of way. Any statements regarding sponsor expectations or intentions are based on information communicated to the Partnership by Enbridge Inc., but there can be no assurance that these expectations or intentions will not change in the future.
Except to the extent required by law, we assume no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Reference should also be made to the Partnership's filings with the U.S. Securities and Exchange Commission (the "SEC"), including its most recently filed Annual Report on Form 10-K and any subsequently filed Quarterly Reports on Form 10-Q or current reports on Form 8-K for additional factors that may affect results. These filings are available to the public over the Internet at the SEC's website ( www.sec.gov ) and at the Partnership's website.
About Enbridge Energy Partners, L.P.
Enbridge Energy Partners, L.P. owns and operates a diversified portfolio of crude oil transportation systems in the United States. Its principal crude oil system is the largest pipeline transporter of growing oil production from western Canada and the North Dakota Bakken formation. The system's deliveries to refining centers and connected carriers in the United States account for approximately 23 percent of total U.S. oil imports. Enbridge Energy Partners, L.P. is traded on the New York stock exchange under the symbol EEP; information about the company is available on its website at www.enbridgepartners.com .
About Enbridge Energy Management, L.L.C.
Enbridge Energy Management, L.L.C. manages the business and affairs of the Partnership, and its sole asset is an approximate 19.5 percent limited partner interest in the Partnership. Enbridge Energy Company, Inc., an indirect wholly owned subsidiary of Enbridge Inc. of Calgary, Alberta, Canada (
FOR FURTHER INFORMATION PLEASE CONTACT: Enbridge Energy Partners, L.P. Media Michael Barnes Toll Free: (888) 992-0997 Email: michael.barnes@enbridge.com Investment Community Adam McKnight (403) 266-7922 or Toll Free: (800) 481-2804 Email: adam.mcknight@enbridge.com
