FORM 10-Q |
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
ENBRIDGE ENERGY PARTNERS, L.P. (Exact Name of Registrant as Specified in Its Charter) | ||
Delaware | 39-1715850 | |
(State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) |
Large accelerated filer x | Accelerated filer o | |
Non-accelerated filer o | Smaller reporting company o | |
Emerging growth company o |
PART I — FINANCIAL INFORMATION | ||
PART II — OTHER INFORMATION | ||
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Operating revenues: | |||||||||||||||
Transportation and other services | $ | 527 | $ | 596 | $ | 1,586 | $ | 1,745 | |||||||
Transportation and other services - affiliates | 33 | 20 | 103 | 72 | |||||||||||
Total operating revenues (Note 3) | 560 | 616 | 1,689 | 1,817 | |||||||||||
Operating expenses: | |||||||||||||||
Environmental costs, net of recoveries | 4 | 1 | (18 | ) | 15 | ||||||||||
Operating and administrative | 62 | 77 | 198 | 239 | |||||||||||
Operating and administrative - affiliates | 64 | 85 | 195 | 235 | |||||||||||
Power | 83 | 81 | 235 | 221 | |||||||||||
Depreciation and amortization | 111 | 112 | 330 | 329 | |||||||||||
Impairment of long-lived asset (Note 6) | 1 | — | 37 | — | |||||||||||
Gain on sale of assets (Note 6) | (22 | ) | (6 | ) | (22 | ) | (68 | ) | |||||||
Total operating expenses | 303 | 350 | 955 | 971 | |||||||||||
Operating income | 257 | 266 | 734 | 846 | |||||||||||
Interest expense, net | 102 | 104 | 307 | 306 | |||||||||||
Allowance for equity used during construction | 16 | 12 | 48 | 33 | |||||||||||
Income from equity investment in joint venture (Note 7) | 37 | 22 | 93 | 28 | |||||||||||
Other income (expense) | — | — | (1 | ) | 5 | ||||||||||
Income from continuing operations before income taxes | 208 | 196 | 567 | 606 | |||||||||||
Income tax benefit (expense) | (1 | ) | — | (1 | ) | 1 | |||||||||
Income from continuing operations | 207 | 196 | 566 | 607 | |||||||||||
Loss from discontinued operations, net of taxes (Note 6) | — | — | — | (57 | ) | ||||||||||
Net income | 207 | 196 | 566 | 550 | |||||||||||
Noncontrolling interests (Note 10) | (103 | ) | (103 | ) | (293 | ) | (262 | ) | |||||||
Series 1 Preferred unit distributions | — | — | — | (29 | ) | ||||||||||
Accretion of discount on Series 1 Preferred units | — | — | — | (8 | ) | ||||||||||
Net income - controlling interests | $ | 104 | $ | 93 | $ | 273 | $ | 251 | |||||||
Net income allocable to common units and i-units: | |||||||||||||||
Income from continuing operations | $ | 92 | $ | 82 | $ | 237 | $ | 254 | |||||||
Loss from discontinued operations (Note 4) | — | — | — | (38 | ) | ||||||||||
Net income allocable to common units and i-units | $ | 92 | $ | 82 | $ | 237 | $ | 216 | |||||||
Net income per common unit and i-unit (basic and diluted): | |||||||||||||||
Income from continuing operations (Note 4) | $ | 0.21 | $ | 0.19 | $ | 0.55 | $ | 0.65 | |||||||
Loss from discontinued operations (Note 4) | — | — | — | (0.10 | ) | ||||||||||
Net income per common unit and i-unit (Note 4) | $ | 0.21 | $ | 0.19 | $ | 0.55 | $ | 0.55 | |||||||
Weighted average common units and i-units outstanding (basic and diluted) | 431 | 421 | 428 | 392 | |||||||||||
Cash Distributions paid per limited partner unit | $ | 0.350 | $ | 0.350 | $ | 1.050 | $ | 1.283 |
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
Net income | $ | 207 | $ | 196 | $ | 566 | $ | 550 | |||||||
Other comprehensive income, net of tax | |||||||||||||||
Change in cash flow hedges | — | (4 | ) | — | (25 | ) | |||||||||
Reclassification to income on cash flow hedges | 8 | 10 | 28 | 31 | |||||||||||
Other comprehensive income, net of tax | 8 | 6 | 28 | 6 | |||||||||||
Comprehensive income | 215 | 202 | 594 | 556 | |||||||||||
Comprehensive income attributable to noncontrolling interests | (103 | ) | (103 | ) | (293 | ) | (262 | ) | |||||||
Series 1 Preferred unit distributions | — | — | — | (29 | ) | ||||||||||
Accretion of discount on Series 1 Preferred units | — | — | — | (8 | ) | ||||||||||
Comprehensive income attributable to common units and i-units | $ | 112 | $ | 99 | $ | 301 | $ | 257 |
Nine months ended September 30, | |||||||
2018 | 2017 | ||||||
Operating activities: | |||||||
Income from continuing operations | $ | 566 | $ | 607 | |||
Adjustments to reconcile net income to net cash provided by operating activities: | |||||||
Depreciation and amortization | 330 | 329 | |||||
Changes in unrealized loss on derivative instruments, net | 8 | 1 | |||||
Environmental costs, net of recoveries | (23 | ) | 15 | ||||
Distributions from equity investment in joint venture | 93 | 28 | |||||
Income from equity investment in joint venture (Note 7) | (93 | ) | (28 | ) | |||
Gain on sale of assets (Note 6) | (22 | ) | (68 | ) | |||
Allowance for equity used during construction | (48 | ) | (33 | ) | |||
Amortization of debt issuance and hedging costs | 27 | 27 | |||||
Impairment of long-lived asset (Note 6) | 37 | — | |||||
Other | 1 | — | |||||
Changes in operating assets and liabilities | 62 | (319 | ) | ||||
Net cash provided by operating activities | 938 | 559 | |||||
Net cash used in discontinued operations | — | (171 | ) | ||||
Investing activities: | |||||||
Capital expenditures | (467 | ) | (418 | ) | |||
Proceeds from the sale of assets (Note 6) | 15 | 319 | |||||
Proceeds from the sale of Midcoast assets (Note 6) | — | 1,310 | |||||
Equity investment in joint venture | (9 | ) | (1,577 | ) | |||
Distributions from equity investment in joint venture in excess of cumulative earnings | 57 | 12 | |||||
Other | — | (3 | ) | ||||
Net cash used in investing activities | (404 | ) | (357 | ) | |||
Net cash used in discontinued operations | — | (25 | ) | ||||
Financing activities: | |||||||
Redemption of Series 1 Preferred units (Note 11) | — | (1,200 | ) | ||||
Payment of Series 1 Preferred unit dividends (Note 11) | — | (357 | ) | ||||
Net proceeds from Class A common unit issuances (Note 11) | — | 1,225 | |||||
Distributions to partners | (390 | ) | (475 | ) | |||
Repayments to General Partner and affiliates | (157 | ) | (1,706 | ) | |||
Borrowings from General Partner and affiliates | 297 | 1,500 | |||||
Net borrowings (repayments) under credit facilities (Note 8) | 238 | (1,065 | ) | ||||
Net commercial paper borrowings (Note 8) | 19 | 686 | |||||
Repayment of long-term debt (Note 8) | (400 | ) | — | ||||
Acquisition of noncontrolling interest in subsidiary (Note 12) | — | (360 | ) | ||||
Sale of noncontrolling interest in subsidiary (Note 12) | — | 450 | |||||
Contributions from noncontrolling interests | 205 | 1,390 | |||||
Distributions to noncontrolling interests | (364 | ) | (376 | ) | |||
Other | (2 | ) | (1 | ) | |||
Net cash used in financing activities | (554 | ) | (289 | ) | |||
Net cash provided by discontinued operations | — | 229 | |||||
Net decrease in cash and cash equivalents and restricted cash - continuing operations | (20 | ) | (87 | ) | |||
Net increase in cash and cash equivalents and restricted cash - discontinued operations | — | 33 | |||||
Cash disposed as part of the Midcoast sale | — | (51 | ) | ||||
Cash and cash equivalents and restricted cash at beginning of year - continuing operations | 35 | 115 | |||||
Cash and cash equivalents and restricted cash at beginning of year - discontinued operations | — | 18 | |||||
Cash and cash equivalents and restricted cash at end of period - continuing operations | $ | 15 | $ | 28 | |||
Cash and cash equivalents and restricted cash at end of period - discontinued operations | $ | — | $ | — |
September 30, 2018 | December 31, 2017 | ||||||
ASSETS | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 15 | $ | 35 | |||
Receivables, trade and other | 76 | 65 | |||||
Due from General Partner and affiliates | 84 | 101 | |||||
Accrued receivables | 87 | 105 | |||||
Other current assets | 24 | 24 | |||||
286 | 330 | ||||||
Property, plant and equipment, net | 13,104 | 12,896 | |||||
Equity investment in joint venture (Note 7) | 1,517 | 1,565 | |||||
Other assets, net | 43 | 37 | |||||
Total assets | $ | 14,950 | $ | 14,828 | |||
LIABILITIES AND PARTNERS’ CAPITAL | |||||||
Current liabilities: | |||||||
Accounts payable and other | $ | 224 | $ | 173 | |||
Due to General Partner and affiliates | 34 | 48 | |||||
Interest payable | 88 | 85 | |||||
Environmental liabilities | 16 | 23 | |||||
Property and other taxes payable | 83 | 106 | |||||
Current portion of long-term debt | 600 | 500 | |||||
1,045 | 935 | ||||||
Long-term debt | 6,126 | 6,366 | |||||
Loans from General Partner and affiliate | 750 | 610 | |||||
Other long-term liabilities | 244 | 178 | |||||
8,165 | 8,089 | ||||||
Commitments and contingencies (Note 13) | |||||||
Partners’ capital: | |||||||
Class E units (18.1 authorized and issued at September 30, 2018 and December 31, 2017, respectively) | 774 | 774 | |||||
Class A common units (326.5 outstanding at September 30, 2018 and December 31, 2017, respectively) | 491 | 860 | |||||
Class B common units (7.8 authorized and issued at September 30, 2018 and December 31, 2017, respectively) | — | — | |||||
i-units (98.6 and 89.8 authorized and issued at September 30, 2018 and December 31, 2017, respectively) | — | — | |||||
Class F units (1,000 authorized and issued at September 30, 2018 and December 31, 2017, respectively) | 267 | 267 | |||||
General Partner | 321 | 68 | |||||
Accumulated other comprehensive loss | (171 | ) | (199 | ) | |||
Total Enbridge Energy Partners, L.P. partners’ capital | 1,682 | 1,770 | |||||
Noncontrolling interests | 5,103 | 4,969 | |||||
Total Partners’ capital | 6,785 | 6,739 | |||||
Total Liabilities and Partners’ capital | $ | 14,950 | $ | 14,828 |
Nine months ended September 30, | |||||||
2018 | 2017 | ||||||
Series 1 Preferred units: | |||||||
Beginning balance | $ | — | $ | 1,192 | |||
Redemption of preferred units (Note 11) | — | (1,200 | ) | ||||
Net income | — | 29 | |||||
Distribution payable | — | (29 | ) | ||||
Accretion of discount on preferred units | — | 8 | |||||
Ending balance | — | — | |||||
Class D units: | |||||||
Beginning balance | — | 2,518 | |||||
Waiver of Class D units (Note 11) | — | (2,479 | ) | ||||
Distributions | — | (39 | ) | ||||
Ending balance | — | — | |||||
Class E units: | |||||||
Beginning balance | 774 | 778 | |||||
Net income | 19 | 19 | |||||
Distributions | (19 | ) | (23 | ) | |||
Ending balance | 774 | 774 | |||||
Class A common units: | |||||||
Beginning balance | 860 | — | |||||
Net income | (26 | ) | 141 | ||||
Issuance of Class A units (Note 11) | — | 1,200 | |||||
Distributions | (343 | ) | (381 | ) | |||
Sale of noncontrolling interest in subsidiary (Note 12) | — | 29 | |||||
Ending balance | 491 | 989 | |||||
Class B common units: | |||||||
Net income | 8 | 9 | |||||
Sale of noncontrolling interest in subsidiary (Note 12) | — | 1 | |||||
Distributions | (8 | ) | (10 | ) | |||
Ending balance | — | — | |||||
i-units: | |||||||
Net loss | — | (9 | ) | ||||
Sale of noncontrolling interest in subsidiary (Note 12) | — | 9 | |||||
Ending balance | — | — | |||||
Class F units: | |||||||
Beginning balance | 267 | — | |||||
Issuance of Class F units (Note 11) | — | 263 | |||||
Net income | 11 | 11 | |||||
Distributions | (11 | ) | (7 | ) | |||
Ending balance | 267 | 267 |
Nine months ended September 30, | |||||||
2018 | 2017 | ||||||
Incentive distribution units: | |||||||
Beginning balance | — | 495 | |||||
Waiver of incentive distribution units (Note 11) | — | (490 | ) | ||||
Distributions | — | (5 | ) | ||||
Ending balance | — | — | |||||
General Partner: | |||||||
Beginning balance | 68 | (667 | ) | ||||
Net income | 261 | 80 | |||||
Waiver of Class D units and incentive distribution units (Note 11) | — | 2,969 | |||||
Issuance of Class F units (Note 11) | — | (263 | ) | ||||
Contributions | — | 92 | |||||
Sale of Midcoast assets (Note 6) | — | (2,127 | ) | ||||
Distributions | (8 | ) | (9 | ) | |||
Sale of noncontrolling interest in subsidiary (Note 12) | — | 1 | |||||
Ending balance | 321 | 76 | |||||
Accumulated other comprehensive loss: | |||||||
Beginning balance | (199 | ) | (339 | ) | |||
Changes in fair value of derivative financial instruments recognized in other comprehensive income | — | (25 | ) | ||||
Changes in fair value of derivative financial instruments reclassified to income | 28 | 31 | |||||
Ending balance | (171 | ) | (333 | ) | |||
Noncontrolling interests: | |||||||
Beginning balance | 4,969 | 3,846 | |||||
Capital contributions | 205 | 1,410 | |||||
Sale of noncontrolling interest in subsidiary (Note 12) | — | 411 | |||||
Acquisition of noncontrolling interest in subsidiary (Note 12) | — | (360 | ) | ||||
Sale of Midcoast assets (Note 6) | — | (297 | ) | ||||
Net income | 293 | 262 | |||||
Distributions to noncontrolling interests | (364 | ) | (376 | ) | |||
Ending balance | 5,103 | 4,896 | |||||
Total Partners’ Capital at end of period | $ | 6,785 | $ | 6,669 |
Three months ended September 30, | Nine months ended September 30, | ||||||
2018 | 2018 | ||||||
(in millions) | |||||||
Operating revenues: | |||||||
Transportation | $ | 543 | $ | 1,633 | |||
Storage and other | 21 | 70 | |||||
Total revenues from contracts with customers | 564 | 1,703 | |||||
Other | (4 | ) | (14 | ) | |||
Total revenues | $ | 560 | $ | 1,689 |
Three months ended September 30, | Nine months ended September 30, 2018 | ||||||
2018 | 2018 | ||||||
(in millions) | |||||||
Revenues from products and services transferred over time - crude oil pipeline transportation and storage | $ | 564 | $ | 1,703 |
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(in millions, except per unit amounts) | |||||||||||||||
Continuing operations: | |||||||||||||||
Net income | $ | 207 | $ | 196 | $ | 566 | $ | 607 | |||||||
Noncontrolling interests | (103 | ) | (103 | ) | (293 | ) | (281 | ) | |||||||
Series 1 Preferred unit distributions | — | — | — | (29 | ) | ||||||||||
Accretion of discount on Series 1 Preferred units | — | — | — | (8 | ) | ||||||||||
Net income - continuing operations | 104 | 93 | 273 | 289 | |||||||||||
Distributions: | |||||||||||||||
Incentive distributions to Class F units | (4 | ) | (4 | ) | (11 | ) | (12 | ) | |||||||
Distributed earnings attributed to our General Partner | (3 | ) | (3 | ) | (10 | ) | (9 | ) | |||||||
Distributed earnings attributed to Class E units | (6 | ) | (6 | ) | (19 | ) | (19 | ) | |||||||
Total distributed earnings to our General Partner, Class E and Class F units | (13 | ) | (13 | ) | (40 | ) | (40 | ) | |||||||
Total distributed earnings attributed to our common units and i-units | (152 | ) | (148 | ) | (451 | ) | (441 | ) | |||||||
Total distributed earnings | (165 | ) | (161 | ) | (491 | ) | (481 | ) | |||||||
Overdistributed earnings | $ | (61 | ) | $ | (68 | ) | $ | (218 | ) | $ | (192 | ) | |||
Discontinued operations: | |||||||||||||||
Net loss | $ | — | $ | — | $ | — | $ | (57 | ) | ||||||
Noncontrolling interest | — | — | — | 19 | |||||||||||
Net loss - discontinued operations | $ | — | $ | — | $ | — | $ | (38 | ) | ||||||
Weighted average common units and i-units outstanding | 431 | 421 | 428 | 392 | |||||||||||
Basic and diluted earnings per unit: | |||||||||||||||
Distributed earnings per common unit and i-unit - continuing operations(1) | $ | 0.35 | $ | 0.35 | $ | 1.05 | $ | 1.13 | |||||||
Overdistributed earnings per common unit and i-unit(2) | (0.14 | ) | (0.16 | ) | (0.50 | ) | (0.48 | ) | |||||||
Net income per common unit and i-unit (basic and diluted) - continuing operations(3) | 0.21 | 0.19 | 0.55 | 0.65 | |||||||||||
Net loss per common unit and i-unit (basic and diluted) - discontinued operations(3) | — | — | — | (0.10 | ) | ||||||||||
Net income per common unit and i-unit (basic and diluted) | $ | 0.21 | $ | 0.19 | $ | 0.55 | $ | 0.55 |
(1) | Represents the total distributed earnings to common units and i-units divided by the weighted average number of common units and i-units outstanding for the period. |
(2) | Represents the common units’ and i-units’ share (98%) of distributions in excess of earnings divided by the weighted average number of common units and i-units outstanding for the period and overdistributed earnings allocated to the common units and i-units based on the distribution waterfall that is outlined in our partnership agreement. |
(3) | For the three and nine months ended September 30, 2018, 18.1 million anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per share. For the three months ended September 30, 2017, 18.1 million anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per share. For the nine months ended September 30, 2017, 43.2 million anti-dilutive Preferred units and 18.1 million anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit and 66.1 million of Class D units were excluded from the if-converted method of calculating diluted earnings per unit as the General Partner irrevocably waived all of its rights associated with the Class D units effective April 27, 2017. |
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(in millions) | |||||||||||||||
Net regulatory (liability) asset balance at beginning of period | $ | (34 | ) | $ | (24 | ) | $ | 3 | $ | 12 | |||||
Prior period true-up | — | — | 4 | (5 | ) | ||||||||||
Current period (over) under recovery revenue adjustments | (13 | ) | 29 | (50 | ) | 2 | |||||||||
Amortization of prior year regulatory asset | (2 | ) | (1 | ) | (6 | ) | (5 | ) | |||||||
Net regulatory (liability) asset balance at end of period | $ | (49 | ) | $ | 4 | $ | (49 | ) | $ | 4 |
Nine months ended September 30, | |||
2017 | |||
(in millions) | |||
Operating revenues | $ | 1,161 | |
Operating expenses: | |||
Commodity costs | 1,011 | ||
Operating and administrative | 133 | ||
Depreciation and amortization | 74 | ||
1,218 | |||
Operating loss | (57 | ) | |
Interest expense, net | 17 | ||
Other income | 18 | ||
Loss before income taxes | (56 | ) | |
Income tax expense | (1 | ) | |
Loss from discontinued operations, net of taxes | $ | (57 | ) |
Ownership Interest | September 30, 2018 | December 31, 2017 | |||
(in millions) | |||||
MarEn Bakken Company LLC | 75% | $1,517 | $1,565 |
Maturity Dates(1) | Total Facilities(2) | Draws(3) | Available | ||||
(in millions) | |||||||
Enbridge Energy Partners, L.P. | 2019 – 2022 | $2,450 | $1,710 | $740 |
(1) | Includes $185 million of commitments that expire in 2020. $175 million of commitments expired on September 26, 2018. |
(2) | Includes our $1.8 billion multi-year revolving credit facility (Credit Facility) and our $625 million credit agreement (364-Day Credit Facility), together (the Credit Facilities). |
(3) | Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility and excludes our unsecured revolving 364-day credit agreement with EUS (the EUS 364-day Credit Facility). |
September 30, | |||||||
2018 | 2017 | ||||||
(in millions) | |||||||
Balance at beginning of year | $ | 106 | $ | 98 | |||
Liabilities incurred | 87 | — | |||||
Accretion expense | 4 | 5 | |||||
Liabilities settled | (5 | ) | — | ||||
Revision in estimate | — | 3 | |||||
Balance at end of year | $ | 192 | $ | 106 |
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(in millions) | |||||||||||||||
Eastern Access | $ | 27 | $ | 37 | $ | 88 | $ | 114 | |||||||
U.S. Mainline Expansion | 28 | 39 | 90 | 108 | |||||||||||
North Dakota Pipeline Company | 9 | 3 | 9 | 19 | |||||||||||
U.S. Line 3 Replacement Program | 11 | 8 | 36 | 19 | |||||||||||
Enbridge Holdings (DakTex) L.L.C. | 28 | 16 | 70 | 21 | |||||||||||
Midcoast Energy Partners, L.P. - discontinued operations | — | — | — | (19 | ) | ||||||||||
Total | $ | 103 | $ | 103 | $ | 293 | $ | 262 |
Distribution Declaration Date | Distribution Payment Date | Amount Paid to EEP | Amount Paid to noncontrolling Interest | Total DakTex Distribution | ||||||||||
(in millions) | ||||||||||||||
September 27, 2018 | September 27, 2018 | $ | 13 | $ | 41 | $ | 54 | |||||||
June 28, 2018 | June 28, 2018 | $ | 11 | $ | 35 | $ | 46 | |||||||
April 6, 2018 | April 6, 2018 | 12 | 38 | 50 | ||||||||||
$ | 36 | $ | 114 | $ | 150 |
Distribution Declaration Date | Distribution Payment Date | Amount Paid to EEP | Amount Paid to noncontrolling Interest | Total Series EA Distribution | ||||||||||
(in millions) | ||||||||||||||
July 25, 2018 | August 14, 2018 | $ | 26 | $ | 38 | $ | 64 | |||||||
April 27, 2018 | May 15, 2018 | 32 | 47 | 79 | ||||||||||
January 31, 2018 | February 14, 2018 | 34 | 50 | 84 | ||||||||||
$ | 92 | $ | 135 | $ | 227 |
Distribution Declaration Date | Distribution Payment Date | Amount Paid to EEP | Amount Paid to noncontrolling Interest | Total Series ME Distribution | ||||||||||
(in millions) | ||||||||||||||
July 25, 2018 | August 14, 2018 | $ | 11 | $ | 31 | $ | 42 | |||||||
April 27, 2018 | May 15, 2018 | 13 | 40 | 53 | ||||||||||
January 31, 2018 | February 14, 2018 | 15 | 44 | 59 | ||||||||||
$ | 39 | $ | 115 | $ | 154 |
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(in millions) | |||||||||||||||
Operating revenues | $ | 560 | $ | 616 | $ | 1,689 | $ | 1,817 | |||||||
Operating expenses: | |||||||||||||||
Environmental costs, net of recoveries | 4 | 1 | (18 | ) | 15 | ||||||||||
Operating and administrative | 62 | 77 | 198 | 239 | |||||||||||
Operating and administrative - affiliates | 64 | 85 | 195 | 235 | |||||||||||
Power | 83 | 81 | 235 | 221 | |||||||||||
Depreciation and amortization | 111 | 112 | 330 | 329 | |||||||||||
Impairment of long-lived asset | 1 | — | 37 | — | |||||||||||
Gain on sale of assets | (22 | ) | (6 | ) | (22 | ) | (68 | ) | |||||||
303 | 350 | 955 | 971 | ||||||||||||
Operating income | 257 | 266 | 734 | 846 | |||||||||||
Interest expense, net | 102 | 104 | 307 | 306 | |||||||||||
Allowance for equity used during construction | 16 | 12 | 48 | 33 | |||||||||||
Income from equity investment in joint venture | 37 | 22 | 93 | 28 | |||||||||||
Other income (expense) | — | — | (1 | ) | 5 | ||||||||||
Income from continuing operations before income taxes | 208 | 196 | 567 | 606 | |||||||||||
Income tax benefit (expense) | (1 | ) | — | (1 | ) | 1 | |||||||||
Income from continuing operations | 207 | 196 | 566 | 607 | |||||||||||
Loss from discontinued operations, net of taxes | — | — | — | (57 | ) | ||||||||||
Net income | 207 | 196 | 566 | 550 | |||||||||||
Noncontrolling interests | (103 | ) | (103 | ) | (293 | ) | (262 | ) | |||||||
Series 1 Preferred unit distributions | — | — | — | (29 | ) | ||||||||||
Accretion of discount on Series 1 Preferred units | — | — | — | (8 | ) | ||||||||||
Net income - controlling interests | $ | 104 | $ | 93 | $ | 273 | $ | 251 |
• | Lower Lakehead System revenues driven by the regulatory impact of the U.S. Tax Reform and the change in FERC income tax policy which no longer permits recovery of an income tax allowance in cost of service rates. |
• | An increase in operating revenue due to increased flow-through of recoverable power costs attributable to higher throughput and an increase in the index toll effective July 1, 2018. |
• | Lower Lakehead System operating expenses driven by higher oil measurement gains and the timing of operating expenses; and |
• | A higher gain on the disposition from the sale of unnecessary materials related to the Sandpiper Project. |
• | Higher volumes on the Bakken Pipeline System resulting in higher earnings from our investment in the Bakken Pipeline System. |
• | Lower Lakehead System revenues driven by the change in FERC income tax policy of approximately $65 million and the regulatory impact from the U.S. Tax Reform of approximately $60 million; and |
• | Lower operating revenues from our Mid-Continent System as a result of the sale of the Ozark Pipeline in March 2017. |
• | Higher operating revenue due to increased flow-through of recoverable power costs resulting from higher throughput on the Lakehead System; and |
• | An increase in the Lakehead System index toll effective July 1, 2018. |
• | An impairment charge of $37 million in 2018 related to our Line 10 crude oil pipeline, a component of the Lakehead System. The impairment charge results from the classification of Line 10 as held for sale and the subsequent measurement at the lower of carrying value and fair value less cost to sell; and |
• | Higher flow-through power costs resulting from higher throughput on the Lakehead System. |
• | Lower Lakehead System operating expenses driven by higher oil measurement gains and the timing of operating expenses; |
• | A lower gain on disposition from the sale of unnecessary materials related to the Sandpiper Project; and |
• | A reduction in net environmental accruals predominately attributable to Line 6B. |
• | A full year of equity earnings from our interest in the Bakken Pipeline System, which was placed into service on June 1, 2017; and |
• | Higher volumes on the Bakken Pipeline System resulting in higher earnings from our investment in the Bakken Pipeline System. |
• | The sale of our interest in our Midcoast gas gathering and processing business resulting in the absence of losses attributable to NCI; |
• | Equity earnings from our investment in the Bakken Pipeline System, which was placed into service on June 1, 2017, of which 75% of the earnings are attributable to NCI; and |
• | The allocation of credits in relation to both the interest component and the cost of equity component of allowance for funds used during construction related to contributions made by our General Partner in relation to the U.S. L3R Program, of which 99% is attributable to NCI under the terms of our joint funding arrangement. |
• | Lower income attributable to interests in Eastern Access and U.S. Mainline expansion, due to lower allocatable income as a result of the FERC income tax policy and U.S. Tax Reform. |
Three months ended September 30, | Nine months ended September 30, | ||||||||||||||
2018 | 2017 | 2018 | 2017 | ||||||||||||
(in millions) | |||||||||||||||
Operating Results: | |||||||||||||||
Operating revenues | $ | 560 | $ | 616 | $ | 1,689 | $ | 1,817 | |||||||
Operating expenses: | |||||||||||||||
Environmental costs, net of recoveries | (4 | ) | (1 | ) | 18 | (15 | ) | ||||||||
Operating and administrative | (125 | ) | (161 | ) | (383 | ) | (465 | ) | |||||||
Power | (83 | ) | (81 | ) | (235 | ) | (221 | ) | |||||||
Impairment of long-lived asset | (1 | ) | — | (37 | ) | — | |||||||||
Gain on sale of assets | 22 | 6 | 22 | 68 | |||||||||||
Allowance for equity used during construction | 16 | 12 | 48 | 33 | |||||||||||
Income from equity investment in joint venture | 37 | 22 | 93 | 28 | |||||||||||
EBITDA | $ | 422 | $ | 413 | $ | 1,215 | $ | 1,245 | |||||||
Operating Statistics: | |||||||||||||||
Lakehead System: | |||||||||||||||
United States(1) | 2,073 | 1,982 | 2,109 | 2,008 | |||||||||||
Canada(1) | 654 | 638 | 647 | 649 | |||||||||||
Total Lakehead System delivery volumes(1) | 2,727 | 2,620 | 2,756 | 2,657 | |||||||||||
Barrel miles (billions) | 196 | 188 | 582 | 563 | |||||||||||
Average haul (miles) | 783 | 782 | 774 | 776 | |||||||||||
Mid-Continent System delivery volumes(1) | — | — | — | 33 | |||||||||||
Bakken Assets: | |||||||||||||||
North Dakota System to Clearbrook(1) | 220 | 219 | 218 | 214 | |||||||||||
Bakken System to Cromer(1) | 58 | 84 | 56 | 116 | |||||||||||
Total Bakken Assets delivery volumes(1) | 278 | 303 | 274 | 330 | |||||||||||
Total Liquids segment delivery volumes(1) | 3,005 | 2,923 | 3,030 | 3,020 |
(1) | Average Bpd in thousands. |
• | Higher volumes on the Bakken Pipeline System resulting in higher earnings from our investment in the Bakken Pipeline System; |
• | An increase in the Lakehead System index toll effective July 1, 2018; |
• | Lower operating expenses on the Lakehead System due to higher oil measurement gains and the timing of operating expenses; and |
• | A higher gain on the disposition from the sale of unnecessary materials related to the Sandpiper Project. |
• | Lower Lakehead System EBITDA driven by the regulatory impact of the U.S. Tax Reform and the FERC income tax policy to no longer permit recovery of an income tax allowance in cost of service rates. |
• | Lower Lakehead System EBITDA driven by the change in FERC income tax policy which no longer permits recovery of an income tax allowance in cost of service rates and a lower tax rate pursuant to U.S. Tax Reform; |
• | An impairment charge of $37 million in 2018 related to our Line 10 crude oil pipeline, a component of the Lakehead System, resulting from the classification as held for sale and the subsequent measurement at the lower of its carrying value or fair value less cost to sell; |
• | Lower transportation revenues due to the sale of the Ozark Pipeline on March 1, 2017; and |
• | A lower gain on disposition from the sale of unnecessary materials related to the Sandpiper Project. |
• | Higher volumes on the Bakken Pipeline System resulting in higher earnings from our investment in the Bakken Pipeline System; |
• | Lower operating expenses on our Lakehead System due to higher oil measurement gains and the timing of operating expenses; and |
• | A reduction in net environmental accruals predominately attributable to Line 6B. |
Ownership Interest | Estimated Capital Costs(1) | Expenditures to Date(2) | Status | Expected In-Service Date | |||||
Lakehead System Mainline Expansion - Line 61(3)(4) | 25% | $0.4 billion | $0.4 billion | Substantially complete | 2H - 2019 | ||||
U.S. Line 3 Replacement Program(5) | 1% | $2.9 billion | $0.9 billion | Pre- construction(6) | 2H - 2019 |
(1) | These amounts are estimates and are subject to upward or downward adjustment based on various factors. |
(2) | Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to September 30, 2018. |
(3) | Jointly funded 25% by us and 75% by our General Partner under the Mainline Expansion joint funding arrangement. Estimated capital costs are presented at 100% before our General Partner’s contributions. |
(4) | Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program. |
(5) | Jointly funded 1% by us and 99% by our General Partner under the Line 3 Replacement joint funding arrangement. Estimated capital costs are presented at 100% before our General Partner's contributions. |
(6) | Construction of the Wisconsin portion of the project is complete as noted below. The remaining portion of the project is in pre-construction status. |
• | U.S. L3R PROGRAM - The Wisconsin portion of the U.S. L3R Program is in service. For additional updates on the project, refer to Growth Projects – Regulatory Matters – U.S. L3R Program, |
September 30, 2018 | |||
(in millions) | |||
Cash and cash equivalents | $ | 15 | |
Total capacity under the Credit Facilities | 2,450 | ||
Total capacity under the EUS 364-day Credit Facility | 750 | ||
Less: Amounts outstanding under the Credit Facilities | 388 | ||
Amounts outstanding under the EUS 364-day Credit Facility | 750 | ||
Principal amount of commercial paper outstanding | 1,322 | ||
Letters of credit outstanding | 4 | ||
Total | $ | 751 |
Distribution Declaration Date | Record Date | Distribution Payment Date | Distribution per Unit | Cash Available for Distribution | Amount of Distribution of i-units to i-unit Holders | Retained from General Partner(1) | Distribution of Cash | |||||||||||||||||
(in millions, except per unit amounts) | ||||||||||||||||||||||||
July 25, 2018 | August 7, 2018 | August 14, 2018 | $ | 0.35 | $ | 164 | $ | 33 | $ | 1 | $ | 130 | ||||||||||||
April 27, 2018 | May 8, 2018 | May 15, 2018 | $ | 0.35 | $ | 163 | $ | 32 | $ | 1 | $ | 130 | ||||||||||||
January 31, 2018 | February 7, 2018 | February 14, 2018 | $ | 0.35 | $ | 162 | $ | 31 | $ | 1 | $ | 130 |
(1) | We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us. |
Nine months ended September 30, | |||||||
2018 | 2017 | ||||||
(in millions) | |||||||
Total cash provided by (used in): | |||||||
Operating activities | $ | 938 | $ | 559 | |||
Investing activities | (404 | ) | (357 | ) | |||
Financing activities | (554 | ) | (289 | ) | |||
Net increase (decrease) in cash and cash equivalents and restricted cash | (20 | ) | (87 | ) | |||
Cash and cash equivalents and restricted cash at beginning of year | 35 | 115 | |||||
Cash and cash equivalents and restricted cash at end of period | $ | 15 | $ | 28 |
• | Repayments on long-term debt of $400 million; |
• | Lower contributions from NCI of $1.2 billion as we received funds of $1.1 billion in the second quarter of 2017 from our General Partner, as a result of the finalization of the joint funding arrangement, which resulted in our investment in the Bakken Pipeline System to be 75% owned by our General Partner and 25% by us; and |
• | The absence of cash inflows of $450 million received from the sale of our 99% interest in the U.S. L3R Project to our General Partner during the first quarter of 2017. |
• | Net borrowings on sources of short-term financing of $636 million; and |
• | Net borrowings of $346 million under the EUS 364-day Credit Facility; |
• | The absence of cash used in the acquisition of an additional 15% interest in the Eastern Access Projects of $360 million during the first half of 2017; |
• | The absence of cash used in the payment on Series 1 Preferred unit dividends of $357 million during the first half of 2017; and |
• | Decrease in distribution to partners of $85 million due to a reduction in our quarterly distribution from $0.583 per unit to $0.35 per unit in the first quarter of 2017. |
• | the parties may be liable for expenses to one another under the terms and conditions of the Merger Agreement; and |
• | there may be negative reactions from the financial markets due to the fact that current prices of our Class A common units may reflect a market assumption that the Proposed Merger will be completed. |
• | changes in Enbridge's or our business, operations and prospects; |
• | changes in market assessments of Enbridge's or our business, operations and prospects; |
• | changes in market assessments of the likelihood that the Proposed Merger will be completed; |
• | interest rates, commodity prices, general market, industry and economic conditions and other factors generally affecting the price of Enbridge common shares or our common units; and |
• | federal, state and local legislation, governmental regulation and legal developments in the businesses in which Enbridge and we operate. |
Exhibit Number | Description | |
101.INS* | XBRL Instance Document. | |
101.SCH* | XBRL Taxonomy Extension Schema Document. | |
101.CAL* | XBRL Taxonomy Extension Calculation Linkbase Document. | |
101.DEF* | XBRL Taxonomy Extension Definition Linkbase Document. | |
101.LAB* | XBRL Taxonomy Extension Label Linkbase Document. | |
101.PRE* | XBRL Taxonomy Extension Presentation Linkbase Document. |
Enbridge Energy Partners, L.P. (Registrant) | ||
By: | Enbridge Energy Management, L.L.C. as delegate of the General Partner | |
Date: November 1, 2018 | By: | /s/ Mark A. Maki |
Mark A. Maki President (Principal Executive Officer) | ||
Date: November 1, 2018 | By: | /s/ Christopher J. Johnston |
Christopher J. Johnston Vice President, Finance (Principal Financial Officer) |
1. | I have reviewed this Quarterly Report on Form 10-Q of Enbridge Energy Partners, L.P.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions) |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
By: /s/ Mark A. Maki | ||
Date: November 1, 2018 | Mark A. Maki President (Principal Executive Officer) Enbridge Energy Management, L.L.C. (as delegate of the General Partner) |
1. | I have reviewed this Quarterly Report on Form 10-Q of Enbridge Energy Partners, L.P.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
d) | Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions) |
a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
By: /s/ Christopher J. Johnston | ||
Date: November 1, 2018 | Christopher J. Johnston Vice President, Finance (Principal Financial Officer) Enbridge Energy Management, L.L.C. (as delegate of the General Partner) |
By: /s/ Mark A. Maki | ||
Date: November 1, 2018 | Mark A. Maki President (Principal Executive Officer) Enbridge Energy Management, L.L.C. (as delegate of the General Partner) |
By:/s/ Christopher J. Johnston | ||
Date: November 1, 2018 | Christopher J. Johnston Vice President, Finance (Principal Financial Officer) Enbridge Energy Management, L.L.C. (as delegate of the General Partner) |
Document And Entity Information - shares |
9 Months Ended | |
---|---|---|
Sep. 30, 2018 |
Oct. 30, 2018 |
|
Document And Entity Information [Abstract] | ||
Entity Registrant Name | ENBRIDGE ENERGY PARTNERS LP | |
Entity Central Index Key | 0000880285 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2018 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Trading Symbol | EEP | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 326,517,110 | |
Document Fiscal Year Focus | 2018 | |
Document Fiscal Period Focus | Q3 |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Statement of Comprehensive Income [Abstract] | ||||
Net income | $ 207 | $ 196 | $ 566 | $ 550 |
Other comprehensive income, net of tax | ||||
Change in cash flow hedges | 0 | (4) | 0 | (25) |
Reclassification to income on cash flow hedges | 8 | 10 | 28 | 31 |
Other comprehensive income, net of tax | 8 | 6 | 28 | 6 |
Comprehensive income | 215 | 202 | 594 | 556 |
Comprehensive income attributable to noncontrolling interests | (103) | (103) | (293) | (262) |
Series 1 Preferred unit distributions | 0 | 0 | 0 | (29) |
Accretion of discount on Series 1 Preferred units | 0 | 0 | 0 | (8) |
Comprehensive income attributable to common units and i-units | $ 112 | $ 99 | $ 301 | $ 257 |
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Class E Units [Member] | ||
Common units, authorized (in shares) | 18,100,000 | 18,100,000 |
Common units, issued (in shares) | 18,100,000 | 18,100,000 |
Class A Common Units [Member] | ||
Common units, outstanding (in shares) | 326,500,000 | 326,500,000 |
Class B Common Units [Member] | ||
Common units, authorized (in shares) | 7,800,000 | 7,800,000 |
Common units, issued (in shares) | 7,800,000 | 7,800,000 |
i-Units [Member] | ||
Common units, authorized (in shares) | 98,600,000 | 89,800,000 |
Common units, issued (in shares) | 98,600,000 | 89,800,000 |
Class F Units [Member] | ||
Common units, authorized (in shares) | 1,000 | 1,000 |
Common units, issued (in shares) | 1,000 | 1,000 |
GENERAL |
9 Months Ended |
---|---|
Sep. 30, 2018 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
GENERAL | 1. GENERAL The terms “we,” “our,” “us” and “Enbridge Energy Partners” as used in this report refer collectively to Enbridge Energy Partners, L.P. and its subsidiaries unless the context suggests otherwise. Those terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge Energy Partners. Nature of Operations We, together with our consolidated subsidiaries, provide crude oil and liquid petroleum gathering, transportation and storage services. In June 2017, we sold all of our ownership interest in our Midcoast gas gathering and processing business to our General Partner (the Midcoast Sale), which is an indirect wholly-owned subsidiary of Enbridge Inc. (Enbridge) The sale of this ownership interest represented a strategic shift in our business and met the criteria for classification as discontinued operations, which resulted in the results of operations, cash flows and financial position of our natural gas business for the prior periods being reflected as discontinued operations. For further information refer to Note 6 - Asset Held for Sale, Dispositions and Discontinued Operations. Basis of Presentation The accompanying unaudited interim consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP), for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. They do not include all the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with our annual consolidated financial statements and notes presented in our Annual Report on Form 10-K for the year ended December 31, 2017. In the opinion of management, the interim consolidated financial statements contain all adjustments, consisting only of normal recurring adjustments, necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended December 31, 2017, except for the adoption of new standards. Our operations and earnings for interim periods can be affected by seasonal fluctuations in the supply of and the demand for crude oil, as well as other factors such as the timing and completion of our construction projects, the effect of environmental costs and related insurance recoveries on our Lakehead System, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value and may not be indicative of annual results. |
CHANGES IN ACCOUNTING POLICIES |
9 Months Ended |
---|---|
Sep. 30, 2018 | |
Accounting Policies [Abstract] | |
CHANGES IN ACCOUNTING POLICY | 2. CHANGES IN ACCOUNTING POLICIES Adoption of New Standards Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset upon sale or partial sale and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions so that an in-scope partial sale results in the recognition of a full gain or loss. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in our consolidated statements of cash flows to include restricted cash and restricted cash equivalents with cash and cash equivalents. Simplifying Cash Flow Classification Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the statements of cash flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements. Revenues from Contracts with Customers Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not yet completed at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments, as well as additional disclosures. The adoption of this new standard did not have a material impact on our consolidated financial statements, see Note 3 - Revenue for further details. Future Accounting Policy Changes Amended Guidance on Cloud Computing Arrangements In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally ASU 2018-15 specifies that an entity would apply Accounting Standard Codification (ASC) 350-40 to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs to be the same as that of the prepayment of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements. Disclosure Effectiveness In August 2018, the Financial Accounting Standards Board issued amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements. ASU 2018-13 was issued to modify the disclosure requirements in ASC 820, Fair Value Measurement. The amendments in ASU 2018-13 eliminate and modify some disclosures, while also adding new disclosures for fair value measurements. This update is effective January 1, 2020; however, entities are permitted to early adopt the eliminated or modified disclosures. We are currently assessing the impact of the new standard on our consolidated financial statements. Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the objective of better aligning an organization's risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on the consolidated financial statements. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements. Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients also permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under ASC 840 continue to meet the definition of initial direct costs under the new guidance. Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements. In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also provides a practical expedient which allows lessors to combine associated lease and nonlease components within a contract when certain conditions are met. We intend to adopt the new transition option in connection with the adoption of the new lease requirements; however, we continue to evaluate the lessor practical expedient to combine lease and nonlease components. We have substantially completed the process of identifying existing lease contracts and are currently performing detailed evaluations of our leases under the new accounting requirements. We believe the most significant change to our financial statements will be the recognition of lease liabilities and right-of-use assets in our consolidated statements of financial position for operating leases. We continue to assess the necessary changes to accounting and business processes in order to implement the recognition and disclosure requirements of the new lease standard. |
REVENUE |
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Revenue from Contract with Customer [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
REVENUE | 3. REVENUE Revenues from Contracts with Customers Major Products and Services
Recognition and Measurement of Revenue
Payment terms Payments are received monthly from customers under long-term transportation contracts. Contract balances Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional. Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights. We had Receivables balances of $255 million and $218 million at January 1, 2018 and September 30, 2018, respectively. At September 30, 2018, we had no material contract assets and $3 million in contract liabilities. Revenues to be Recognized from Unfulfilled Performance Obligations Total revenues from performance obligations expected to be fulfilled in future periods is $537 million, of which $32 million and $128 million are expected to be recognized during the remaining three months ending December 31, 2018 and for the year ended December 31, 2019, respectively. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers. Those revenues are not included in the amounts for revenues to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above. Significant Judgments made in Recognizing Revenues Judgment is required in estimating variable consideration for volumetric transportation and sales contracts. We estimate variable consideration for these contracts as the most likely amount based on actual volumes transported and delivered when those quantities are determined at the conclusion of each month using metered volumes and actual average monthly index prices for commodity sales contracts. |
NET INCOME PER LIMITED PARTNER UNIT |
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Earnings Per Share [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
NET INCOME PER LIMITED PARTNER UNIT | 4. NET INCOME PER LIMITED PARTNER UNIT We determined basic and diluted net income per limited partner unit as follows:
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REGULATORY MATTERS |
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Regulatory Assets and Liabilities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
REGULATORY MATTERS | 5. REGULATORY MATTERS Regulatory Accounting Our over and under recovery revenue adjustments and net regulatory asset amortization are as follows:
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ASSET HELD FOR SALE, DISPOSITIONS AND DISCONTINUED OPERATIONS |
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Discontinued Operations and Disposal Groups [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
ASSET HELD FOR SALE, DISPOSITIONS AND DISCONTINUED OPERATIONS | 6. ASSET HELD FOR SALE, DISPOSITIONS AND DISCONTINUED OPERATIONS Asset Held for Sale In the first quarter of 2018, we satisfied the conditions as set out in our agreements for the sale of our Line 10 crude oil pipeline, a component of our Lakehead System. Line 10 originates near Hamilton, Ontario and terminates at West Seneca, New York. We own the United States portion of Line 10, while a subsidiary of the indirect parent of our General Partner, Enbridge owns the Canadian portion. We expect to close the sale of Line 10 within one year, subject to regulatory approval and certain closing conditions. As such, during the first quarter of 2018, we classified our portion of Line 10 assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $37 million included within “Impairment of long-lived asset” on our consolidated statements of income for the nine months ended September 30, 2018. The remaining held for sale assets and liabilities were not material. Dispositions In July 2018, we entered into an agreement to sell to a third party unnecessary materials related to the Sandpiper Project for cash proceeds of approximately $30 million, of which we received approximately $15 million during the three months ended September 30, 2018 with the remaining balance being held in an escrow account as of September 30, 2018. The remaining balance will be released from escrow once the purchaser takes possession of all the purchased materials. Under the terms of the agreement, title was transferred to the purchaser in late September 2018 when payment of the remaining balance was deposited in the escrow account. As a result, we recorded a gain on disposition of $22 million net of selling costs, included in "Gain on sale of assets" on our consolidated statements of income. During the nine months ended September 30, 2017, we sold unnecessary pipe related to the Sandpiper Project for cash proceeds of approximately $103 million. A gain on disposition of $57 million was included in "Gain on sale of assets" on our consolidated statements of income. In March 2017, we completed the sale of the Ozark Pipeline to a subsidiary of MPLX LP for cash proceeds of approximately $220 million, including reimbursement costs. A gain on disposition of $11 million was included in “Gain on sale of assets” on our consolidated statements of income. Discontinued Operations Sale of Natural Gas Business In June 2017, we completed the sale of all of our ownership interest in our Midcoast gas gathering and processing business to our General Partner for $2.3 billion, which included cash consideration of $1.3 billion and outstanding indebtedness at Midcoast Energy Partners, L.P. (MEP) of $953 million. This sale included our 48.4% limited partnership interest in Midcoast Operating, L.P., our 51.9% limited partnership interest in MEP, and our 100% interest in Midcoast Holdings, L.L.C., MEP’s general partner. We recorded no gain or loss on the sale as this transaction was between entities under common control of Enbridge. The carrying value of the net assets sold was $4.3 billion. As a result of the transaction, partners’ capital decreased by $2.1 billion, all of which was allocated to the General Partner’s capital account. Noncontrolling interest (NCI) in MEP of $297 million was eliminated. The following table presents the operating results from discontinued operations of our Midcoast gas gathering and processing business, which have been segregated from our continuing operations in our consolidated statements of income:
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EQUITY INVESTMENT IN JOINT VENTURE |
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Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||
EQUITY INVESTMENT IN JOINT VENTURE | 7. EQUITY INVESTMENT IN JOINT VENTURE The following table presents our equity investment in a joint venture and ownership interest in MarEn Bakken Company LLC (MarEn).
In February 2017, our joint venture with Marathon Petroleum Corporation (MPC), MarEn, closed its acquisition to acquire a 49% interest in Bakken Pipeline Investments LLC (BPI). BPI owns 75% of the Dakota Access Pipeline (DAPL) and the Energy Transfer Crude Oil Pipeline (ETCOP), collectively the Bakken Pipeline System. The Bakken Pipeline System was placed into service June 1, 2017. Our investment subsidiary, Enbridge Holdings (DakTex) L.L.C. (DakTex) and MPC indirectly hold 75% and 25% interests, respectively, of MarEn. The purchase of DakTex's effective 27.6% interest in the Bakken Pipeline System was $1.5 billion and funded through a bridge loan from Enbridge (U.S.) Inc., (EUS) an affiliate of our General Partner and was re-paid and terminated on April 27, 2017, as a result of the finalization by our Board of Directors of a joint funding arrangement with our General Partner. This arrangement resulted in DakTex now being owned 75% by our General Partner and 25% by us. Refer to Note 12 - Related Party Transactions for further details on our joint funding arrangements. We account for our investment in MarEn under the equity method of accounting. For the three and nine months ended September 30, 2018, we recognized $37 million and $93 million, respectively, and $22 million and $28 million for the three and nine months ended September 30, 2017, respectively, in “Income from equity investment in joint venture" in our consolidated statements of income representing our equity earnings for this investment, net of amortization of the excess of the purchase price over the underlying net book value (basis difference). Our equity investment includes basis difference of the investees’ assets at the purchase date, which is comprised of $14 million in goodwill and $931 million in amortizable assets. We amortized $9 million and $28 million for the three and nine months ended September 30, 2018, respectively and $10 million and $13 million for the three and nine months ended September 30, 2017, respectively, which was recorded as a reduction to equity earnings. |
DEBT |
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Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||
DEBT | 8. DEBT Credit Facilities
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Our commercial paper program provides for the issuance of up to an aggregate principal amount of $1.5 billion of commercial paper and is supported by the availability of long-term committed credit facilities, and therefore is classified as long-term debt as of September 30, 2018 and December 31, 2017, respectively. In addition to the committed credit facilities noted in the above table, we also have $175 million available under an uncommitted letters of credit arrangement, of which $171 million and $174 million were unutilized as of September 30, 2018 and December 31, 2017, respectively. On April 15, 2018, our 6.5% senior notes of $400 million matured, and were subsequently paid on April 16, 2018. On June 29, 2018, we extended the termination date attributable to our 364-Day Credit Facility to December 31, 2018, which has a term out option that could extend maturity of any outstanding borrowings to December 31, 2019. The size of the facility remains at $625 million and is through a syndicate of third party lenders. Debt Covenants We and our consolidated subsidiaries were in compliance with the terms of our financial covenants under our consolidated debt agreements as of September 30, 2018. Fair Value of Debt Obligations The carrying amounts of our outstanding commercial paper, borrowings under our Credit Facilities, and the EUS 364-day Credit Facility approximate their fair values due to the short-term nature and frequent repricing of the amounts outstanding under these obligations. The fair value of our outstanding commercial paper and borrowings under our Credit Facilities and the EUS 364-day Credit Facility are included with our long-term debt obligations above since we have the ability and the intent to refinance the amounts outstanding on a long-term basis. The approximate fair value of our fixed-rate debt obligations was $5.1 billion and $5.8 billion as of September 30, 2018 and December 31, 2017, respectively. We determined the approximate fair values using a standard methodology that incorporates pricing points that are obtained from independent, third-party investment dealers who actively make markets in our debt securities. We use these pricing points to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding. The fair value of our long-term debt obligations is categorized as Level 2 within the fair value hierarchy. |
ASSET RETIREMENT OBLIGATIONS |
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ASSET RETIREMENT OBLIGATIONS | 9. ASSET RETIREMENT OBLIGATIONS Our AROs relate mostly to the retirement of our crude oil and liquid petroleum pipelines and storage facilities. A reconciliation of movements to our ARO liabilities is as follows:
ARO liabilities of $192 million are included in "Other long-term liabilities" on our consolidated statements of financial position. |
NONCONTROLLING INTERESTS |
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NONCONTROLLING INTERESTS | 10. NONCONTROLLING INTERESTS The following table presents income attributable to our noncontrolling interests as outlined below:
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PARTNERS' CAPITAL |
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Partners' Capital Notes [Abstract] | |
PARTNERS’ CAPITAL | 11. PARTNERS' CAPITAL Curing Our limited partnership agreement does not permit capital deficits to accumulate in the capital accounts of any limited partner and thus requires that such capital account deficits be “cured” by additional allocations from the positive capital accounts of the common units, i-units, and our General Partner, generally on a pro-rated basis. For the nine months ended September 30, 2018, the carrying amounts for the capital accounts of the Class B common units were reduced below zero due to distributions to limited partners in excess of earnings and were subsequently cured. Class A common units and i-units had positive capital balances and therefore, as outlined in the partnership agreement, we allocated earnings of $255 million to our General Partner to recover previous curing allocations made by the General Partner. Redemption of Series 1 Preferred Units In April 2017, we redeemed all of our outstanding Series 1 Preferred units held by our General Partner at face value of $1.2 billion in cash. The remaining unamortized beneficial conversion feature discount of $9 million was recorded against the capital balance of the General Partner. Additionally, we repaid $357 million in deferred distributions on the Series 1 Preferred units owed to our General Partner upon the closing of the Midcoast sale. Issuance of Class A Units In April 2017, we funded the redemption of the Series 1 Preferred units through the issuance of 64.3 million Class A common units to our General Partner at a price of $18.66 per Class A common unit. The Class A common units were recognized at fair value. The fair value of the Class A common units was $18.57 per unit, resulting in a $1.2 billion increase to the Class A common units capital account. Simplification of Incentive Distributions In April 2017, a wholly-owned subsidiary of our General Partner irrevocably waived all of its rights associated with its 66.1 million Class D units and 1,000 incentive distribution units (IDU), in exchange for the issuance of 1,000 Class F units. The waiver represented an extinguishment, resulting in a derecognition of the Class D units and IDUs at their respective carrying values. The Class F units were recorded at their fair value using the income approach on the basis of discounted cash flow from expected quarterly distributions of $263 million with the difference between the fair value of the Class F units and the carrying value of the Class D units and IDUs being recorded as an increase of $2.7 billion to our General Partner's capital accounts. |
RELATED PARTY TRANSACTIONS |
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RELATED PARTY TRANSACTIONS | 12. RELATED PARTY TRANSACTIONS Administrative and Workforce Related Services We do not directly employ any of the individuals responsible for managing or operating our business nor do we have any directors. Enbridge and its affiliates provide management and we obtain managerial, administrative, operational and workforce related services from our General Partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among our General Partner, Enbridge Management, affiliates of Enbridge, and us. Pursuant to these service agreements, we have agreed to reimburse our General Partner, Enbridge Management and affiliates of Enbridge, for the cost of managerial, administrative, operational and director services they provide to us. Where directly attributable, the cost of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us. The affiliate amounts incurred by us for services received pursuant to the services agreements are reflected in “Operating and administrative - affiliates” on our consolidated statements of income. Enbridge and its affiliates allocated direct workforce costs to us for our construction projects of $8 million and $17 million as of September 30, 2018 and December 31, 2017, respectively, which we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position. Affiliate Revenues We record operating revenues for storage, transportation and terminalling services we provide to affiliates, which are presented in “Transportation and other services - affiliates” on our consolidated statements of income. Financial Transactions with Affiliates EUS 364-day Credit Facility We are party to the EUS 364-day Credit Facility, with EUS. The EUS 364-day Credit Facility is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, $750 million. On July 24, 2018, we entered into an agreement with EUS whereby the termination date was extended to July 23, 2019. The terms of our agreement with EUS remain unchanged. At that time, we may elect to convert any outstanding loans to term loans, which would mature on July 23, 2020. As of September 30, 2018, we had $750 million outstanding under this facility, excluding any accrued interest to date. Joint Funding Arrangement for Bakken Pipeline System We have a joint funding arrangement with our General Partner which established ownership in the Class A units of DakTex, the entity through which we and our General Partner own our interest in MarEn. Our General Partner owns a 75% interest and we own a 25% interest in DakTex, with an option for us to increase our interest by 20% at a price equal to net book value, at any time during the five years subsequent to the June 1, 2017 in-service date of the Bakken Pipeline System. Our General Partner made contributions to DakTex totaling $7 million and $30 million, respectively, for the nine months ended September 30, 2018 and 2017, respectively. During the second quarter of 2017 we received distributions from DakTex in the amount of $1.1 billion. The funds received, along with additional borrowing under the EUS 364-day Credit Facility, were used to repay a bridge loan from EUS which was subsequently terminated. Income from equity investment in joint venture for the three and nine months ended September 30, 2018, was $37 million and $93 million, respectively and $22 million and $28 million, respectively, for the three and nine months ended September 30, 2017, of which 75% is attributable to our General Partner and recorded as part of NCI. Joint Funding Arrangement for U.S. Line 3 Replacement Program We have a joint funding arrangement with our General Partner for the U.S. Line 3 Replacement Program (U.S. L3R Program). Under the terms of the arrangement, our General Partner funds 99% and we fund 1% of the capital cost of the U.S. L3R Program. We have an option to increase our interest in the U.S. L3R Program assets up to 40% in the U.S. portion at book value at any time up to four years after the project goes into service. Our General Partner paid $450 million for its 99% interest in the project in January 2017, including our share of the construction costs and other incremental amounts. The carrying amount of our General Partner's 99% interest in the project was recorded as an increase to noncontrolling interest. The $40 million difference between the cash received and the carrying amount was recorded as an increase to the capital accounts of our common units, i-units, and General Partner interest on a pro-rated basis. Our General Partner made contributions to Enbridge Energy, Limited Partnership (OLP) totaling $189 million and $185 million for the nine months ended September 30, 2018 and 2017, respectively, to fund its portion of the construction costs associated with the U.S. L3R Program. Joint Funding Arrangement for Eastern Access Projects We have a joint funding arrangement with our General Partner that established the Series EA interests in the OLP (the EA interest), which were created to finance the Eastern Access Project to increase access to refineries in the U.S. Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States. In January 2017, we exercised our option under the Eastern Access joint funding arrangement to acquire an additional 15% interest in the Eastern Access Project, thereby increasing our ownership interest from 25% to 40% and reducing the interest of our General Partner from 75% to 60%. The exercise of our option occurred at book value of approximately $360 million and reduced noncontrolling interests by approximately $360 million. The Eastern Access Project was placed into service in June 2016. Our General Partner made contributions to the OLP totaling $1 million and $9 million for the nine months ended September 30, 2018 and 2017, respectively, to fund its portion of the construction costs associated with the Eastern Access Project. Joint Funding Arrangement for U.S. Mainline Expansion Projects The OLP also has a series of partnership interests (the ME interests) which were created to finance the Mainline Expansion Projects to increase access to the markets of North Dakota and western Canada for light oil production on our Lakehead System between Neche, North Dakota and Superior, Wisconsin. Our General Partner owns 75% of the ME interests and we own 25% of the ME interests, with an option for us to increase our ownership interest by an additional 15% at cost, under the Mainline Expansion joint funding arrangement. Our General Partner made contributions to the OLP totaling $8 million and $27 million for the nine months ended September 30, 2018 and 2017, respectively, to fund its portion of the construction costs associated with the Mainline Expansion Projects. Distributions Distributions from Enbridge Holdings (DakTex) L.L.C. The following table presents distributions paid by DakTex during the nine months ended September 30, 2018, to our General Partner and its affiliate, representing the noncontrolling interest in Class A units of DakTex, and to us, as the holders of the remaining Class A units of DakTex.
Distributions to Series EA Interests The following table presents distributions paid by the OLP during the nine months ended September 30, 2018, to our General Partner and its affiliate, representing the noncontrolling interest in the Series EA, and to us, as the holders of the Series EA general partner interests and certain limited partner interests.
Distributions to Series ME Interests The following table presents distributions paid by the OLP during the nine months ended September 30, 2018, to our General Partner and its affiliate, representing the noncontrolling interest in the Series ME, and to us, as the holders of the Series ME general partner and certain limited partner interests.
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COMMITMENTS AND CONTINGENCIES |
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Sep. 30, 2018 | |
Commitments and Contingencies Disclosure [Abstract] | |
COMMITMENTS AND CONTINGENCIES | 13. COMMITMENTS AND CONTINGENCIES Environmental Liabilities We are subject to federal and state laws and regulations relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us. Environmental risk is inherent to liquid hydrocarbon pipeline operations, and we are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our liquids businesses. Our General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead System assets prior to the transfer of these assets to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations. As of September 30, 2018 and December 31, 2017, our consolidated statements of financial position included $16 million and $23 million, respectively, in “Environmental liabilities,” and $25 million and $51 million, respectively, in “Other long-term liabilities,” that we have accrued for costs to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids assets and penalties we have been or expect to be assessed. On May 31, 2018, we received a No Further Action letter from the Michigan Department of Environmental Quality and subsequently reduced our Line 6B environmental accrual by $28 million. Legal and Regulatory Proceedings We are subject to various legal and regulatory actions and proceedings that arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. Some of these proceedings are covered, in whole or in part, by insurance. |
SUBSEQUENT EVENTS |
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Subsequent Events [Abstract] | |
SUBSEQUENT EVENTS | 14. SUBSEQUENT EVENTS Distribution to Partners On October 24, 2018, the board of directors of Enbridge Management declared a distribution payable to our partners on November 14, 2018. The distribution will be paid to unitholders of record as of November 7, 2018 of our available cash of $165 million at September 30, 2018, or $0.35 per limited partner unit. Of this distribution, $130 million will be paid in cash, $34 million will be distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $1 million will be retained from our General Partner from amounts otherwise distributable to it in respect of its general partner interest and limited partner interest to maintain its 2% general partner interest. Distribution to Series EA Interests On October 24, 2018, the managing general partner of the Series EA interests, declared a distribution payable to the holders of the Series EA general and limited partner interests. The OLP will pay $40 million to the noncontrolling interest in the Series EA, while $27 million will be paid to us. Distribution to Series ME Interests On October 24, 2018, the managing general partner of the Series ME interests declared a distribution payable to the holders of the Series ME general and limited partner interests. The OLP will pay $33 million to the noncontrolling interest in the Series ME, while $11 million will be paid to us. |
CHANGES IN ACCOUNTING POLICIES (Policies) |
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Accounting Policies [Abstract] | |
Adoption of New Standards | Adoption of New Standards Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset upon sale or partial sale and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions so that an in-scope partial sale results in the recognition of a full gain or loss. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in our consolidated statements of cash flows to include restricted cash and restricted cash equivalents with cash and cash equivalents. Simplifying Cash Flow Classification Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the statements of cash flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements. Revenues from Contracts with Customers Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not yet completed at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments, as well as additional disclosures. The adoption of this new standard did not have a material impact on our consolidated financial statements, see Note 3 - Revenue for further details. Future Accounting Policy Changes Amended Guidance on Cloud Computing Arrangements In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally ASU 2018-15 specifies that an entity would apply Accounting Standard Codification (ASC) 350-40 to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs to be the same as that of the prepayment of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements. Disclosure Effectiveness In August 2018, the Financial Accounting Standards Board issued amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements. ASU 2018-13 was issued to modify the disclosure requirements in ASC 820, Fair Value Measurement. The amendments in ASU 2018-13 eliminate and modify some disclosures, while also adding new disclosures for fair value measurements. This update is effective January 1, 2020; however, entities are permitted to early adopt the eliminated or modified disclosures. We are currently assessing the impact of the new standard on our consolidated financial statements. Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the objective of better aligning an organization's risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on the consolidated financial statements. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements. Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients also permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under ASC 840 continue to meet the definition of initial direct costs under the new guidance. Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements. In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also provides a practical expedient which allows lessors to combine associated lease and nonlease components within a contract when certain conditions are met. We intend to adopt the new transition option in connection with the adoption of the new lease requirements; however, we continue to evaluate the lessor practical expedient to combine lease and nonlease components. We have substantially completed the process of identifying existing lease contracts and are currently performing detailed evaluations of our leases under the new accounting requirements. We believe the most significant change to our financial statements will be the recognition of lease liabilities and right-of-use assets in our consolidated statements of financial position for operating leases. We continue to assess the necessary changes to accounting and business processes in order to implement the recognition and disclosure requirements of the new lease standard. |
REVENUE (Tables) |
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Disaggregation of Revenue |
Major Products and Services
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NET INCOME PER LIMITED PARTNER UNIT (Tables) |
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Basic and Diluted Net Income Per Limited Partner Unit | We determined basic and diluted net income per limited partner unit as follows:
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REGULATORY MATTERS (Tables) |
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Regulatory Assets and Liabilities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Changes in Net Regulatory Asset Balance | Our over and under recovery revenue adjustments and net regulatory asset amortization are as follows:
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ASSET HELD FOR SALE, DISPOSITIONS AND DISCONTINUED OPERATIONS (Tables) |
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Disposal Groups, Including Discontinued Operations | The following table presents the operating results from discontinued operations of our Midcoast gas gathering and processing business, which have been segregated from our continuing operations in our consolidated statements of income:
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EQUITY INVESTMENT IN JOINT VENTURE (Tables) |
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Equity Method Investments | The following table presents our equity investment in a joint venture and ownership interest in MarEn Bakken Company LLC (MarEn).
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DEBT (Tables) |
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Schedule of Line of Credit Facilities | Credit Facilities
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ASSET RETIREMENT OBLIGATIONS (Tables) |
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Schedule of Asset Retirement Obligations | A reconciliation of movements to our ARO liabilities is as follows:
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NONCONTROLLING INTERESTS (Tables) |
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Schedule of Non Controlling Interest | The following table presents income attributable to our noncontrolling interests as outlined below:
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RELATED PARTY TRANSACTIONS (Tables) |
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Related Party Transactions [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Distributions | The following table presents distributions paid by the OLP during the nine months ended September 30, 2018, to our General Partner and its affiliate, representing the noncontrolling interest in the Series EA, and to us, as the holders of the Series EA general partner interests and certain limited partner interests.
The following table presents distributions paid by DakTex during the nine months ended September 30, 2018, to our General Partner and its affiliate, representing the noncontrolling interest in Class A units of DakTex, and to us, as the holders of the remaining Class A units of DakTex.
The following table presents distributions paid by the OLP during the nine months ended September 30, 2018, to our General Partner and its affiliate, representing the noncontrolling interest in the Series ME, and to us, as the holders of the Series ME general partner and certain limited partner interests.
|
REVENUE (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | |||
---|---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
Jan. 01, 2018 |
|
Disaggregation of Revenue [Line Items] | |||||
Revenue from contract with customer | $ 564 | $ 1,703 | |||
Other revenue | (4) | (14) | |||
Revenues | 560 | $ 616 | 1,689 | $ 1,817 | |
Accounts receivables | 218 | 218 | $ 255 | ||
Contract with customer, liability | 3 | 3 | |||
Transportation Revenue [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from contract with customer | 543 | 1,633 | |||
Storage and Other Revenue [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from contract with customer | 21 | 70 | |||
Transferred over Time [Member] | |||||
Disaggregation of Revenue [Line Items] | |||||
Revenue from contract with customer | $ 564 | $ 1,703 |
REGULATORY MATTERS (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Regulatory Assets and Liabilities [Roll Forward] | ||||
Net regulatory (liability) asset balance at beginning of period | $ (34) | $ (24) | $ 3 | $ 12 |
Prior period true-up | 0 | 0 | 4 | (5) |
Current period (over) under recovery revenue adjustments | (13) | 29 | (50) | 2 |
Amortization of prior year regulatory asset | (2) | (1) | (6) | (5) |
Net regulatory (liability) asset balance at end of period | $ (49) | $ 4 | $ (49) | $ 4 |
ASSET HELD FOR SALE, DISPOSITIONS AND DISCONTINUED OPERATIONS (Consolidated Statements of Income) (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Operating expenses: | ||||
Loss from discontinued operations, net of taxes | $ 0 | $ 0 | $ 0 | $ (57) |
Discontinued Operations, Disposed of by Sale [Member] | ||||
Operating revenues: | ||||
Operating revenues | 1,161 | |||
Operating expenses: | ||||
Commodity costs | 1,011 | |||
Operating and administrative | 133 | |||
Depreciation and amortization | 74 | |||
Operating expenses, Total | 1,218 | |||
Operating loss | (57) | |||
Interest expense, net | 17 | |||
Other income | 18 | |||
Loss before income taxes | (56) | |||
Income tax expense | (1) | |||
Loss from discontinued operations, net of taxes | $ (57) |
EQUITY INVESTMENT IN JOINT VENTURE (Details) - USD ($) $ in Millions |
Sep. 30, 2018 |
Dec. 31, 2017 |
---|---|---|
Equity investment in joint venture (Note 7) | $ 1,517 | $ 1,565 |
MarEn Bakken Company LLC [Member] | ||
Equity method investment, ownership percentage | 75.00% | |
Equity investment in joint venture (Note 7) | $ 1,517 | $ 1,565 |
DEBT (Credit Facility) (Details) - USD ($) |
9 Months Ended | |
---|---|---|
Sep. 30, 2018 |
Dec. 31, 2017 |
|
Committed Credit Facility [Member] | ||
Line of credit facility, expiring in year one | $ 175,000,000 | |
Line of credit facility expiring in year two | $ 185,000,000 | |
Revolving Credit Facility [Member] | ||
Total Facilities | $ 2,450,000,000 | |
Draws | 1,710,000,000 | |
Remaining borrowing capacity | 740,000,000 | |
Credit Facility [Member] | Revolving Credit Facility [Member] | ||
Total Facilities | 1,825,000,000 | |
EUS 364-day Credit Facility [Member] | Revolving Credit Facility [Member] | ||
Total Facilities | $ 625,000,000 |
ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions |
9 Months Ended | |
---|---|---|
Sep. 30, 2018 |
Sep. 30, 2017 |
|
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at beginning of year | $ 106 | $ 98 |
Liabilities incurred | 87 | 0 |
Accretion expense | 4 | 5 |
Liabilities settled | (5) | 0 |
Revision in estimate | 0 | 3 |
Balance at end of year | 192 | $ 106 |
Other Long-Term Liabilities [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Balance at end of year | $ 192 |
RELATED PARTY TRANSACTIONS (Narrative) (Details) - USD ($) |
9 Months Ended | 12 Months Ended |
---|---|---|
Sep. 30, 2018 |
Dec. 31, 2017 |
|
Related Party Transaction [Line Items] | ||
Long-term line of credit | $ 750,000,000 | |
Enbridge Inc., Credit Agreement [Member] | ||
Related Party Transaction [Line Items] | ||
Maximum borrowing capacity of line of credit | 750,000,000 | |
Construction Project Work Force Cost Transactions [Member] | ||
Related Party Transaction [Line Items] | ||
Related party expenses | $ 8,000,000 | $ 17,000,000 |
COMMITMENTS AND CONTINGENCIES (Narrative) (Details) - USD ($) $ in Millions |
3 Months Ended | ||
---|---|---|---|
Jun. 30, 2018 |
Sep. 30, 2018 |
Dec. 31, 2017 |
|
Commitments and Contingencies Disclosure [Abstract] | |||
Remaining liabilities | $ 16 | $ 23 | |
Accrual for environmental loss contingencies | $ 25 | $ 51 | |
Accrual for environmental loss contingencies, period decrease | $ 28 |
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