þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Delaware | 74-1079400 | |
(State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) | |
2800 Post Oak Boulevard, Houston, Texas | 77056 | |
(Address of Principal Executive Offices) | (Zip Code) |
Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer þ | Smaller reporting company ¨ | Emerging growth company ¨ | ||||
(Do not check if a smaller reporting company) |
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Item 16. |
• | Leakage from gathering systems, underground gas storage caverns, pipelines, transportation facilities and storage tanks; |
• | Damage to facilities resulting from accidents during normal operations; |
• | Damages to onshore and offshore equipment and facilities resulting from storm events or natural disasters; and |
• | Blowouts, cratering and explosions. |
• | Our and our affiliates’ future credit ratings; |
• | Amounts and nature of future capital expenditures; |
• | Expansion and growth of our business and operations; |
• | Expected in-service dates for capital projects; |
• | Financial condition and liquidity; |
• | Business strategy; |
• | Cash flow from operations or results of operations; |
• | Rate case filings; |
• | Natural gas prices, supply, and demand; and |
• | Demand for our services. |
• | Availability of supplies, including lower than anticipated volumes from third parties and market demand; |
• | Volatility of pricing including the effect of lower than anticipated energy commodity prices and margins; |
• | Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers); |
• | The strength and financial resources of our competitors and the effects of competition; |
• | Whether we are able to successfully identify, evaluate and timely execute our capital projects and other investment opportunities in accordance with our capital expenditure budget; |
• | Our ability to successfully expand our facilities and operations; |
• | Development and rate of adoption of alternative energy sources; |
• | Availability of adequate insurance coverage and the impact of operational and development hazards and unforeseen interruptions; |
• | The impact of existing and future laws (including, but not limited to, the Tax Cuts and Jobs Act of 2017), regulations, the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals and achieve favorable rate proceeding outcomes; |
• | Our costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates; |
• | Changes in maintenance and construction costs; |
• | Changes in the current geopolitical situation; |
• | Our exposure to the credit risks of our customers and counterparties; |
• | Risks related to financing, including restrictions stemming from our debt agreements, future changes in our credit ratings and the availability and cost of capital; |
• | Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities; |
• | Acts of terrorism, including cybersecurity threats, and related disruptions; and |
• | Additional risks described in our filings with the Securities and Exchange Commission (SEC). |
• | Aging infrastructure and mechanical problems; |
• | Damages to pipelines and pipeline blockages or other pipeline interruptions; |
• | Uncontrolled releases of natural gas; |
• | Operator error; |
• | Damage caused by third party activity, such as operation of construction equipment; |
• | Pollution and other environmental risks; and |
• | Fires, blowouts, cratering and explosions. |
• | The level of existing and new competition to deliver natural gas to our markets and competition from alternative fuel sources such as electricity, coal, fuel oils, or nuclear energy; |
• | Pricing, demand, availability and margins for natural gas in our markets; |
• | Whether the market will continue to support long-term firm contracts; |
• | The effects of regulation on us, our customers and our contracting practices; and |
• | The ability to understand our customers’ expectations, efficiently and reliably deliver high quality services and effectively manage customer relationships. The results of these efforts will impact our reputation and positioning in the market. |
• | Changing circumstances and deviations in variables could negatively impact our investment analysis, including our projections of revenues, earnings, and cash flow relating to potential investment targets, resulting in outcomes which are materially different than anticipated; |
• | We could be required to contribute additional capital to support acquired businesses or assets. We may assume liabilities that were not disclosed to us that exceed our estimates and for which contractual protections are either unavailable or prove inadequate; |
• | Acquisitions could disrupt our ongoing business, distract management, divert financial and operational resources from existing operations and make it difficult to maintain our current business standards, controls, and procedures; and |
• | Acquisitions and capital projects may require substantial new capital, including the issuance of debt or equity, and we may not be able to access credit or capital markets or obtain acceptable terms. |
• | Make it more difficult for us to satisfy our obligations with respect to our indebtedness, which could in turn result in an event of default on such indebtedness; |
• | Impair our ability to obtain additional financing in the future for working capital, capital expenditures, general limited liability company purposes, or other purposes; |
• | Diminish our ability to withstand a continued or future downturn in our business or the economy generally; |
• | Require us to dedicate a substantial portion of our cash flow from operations to debt service payments, thereby reducing the availability of cash for working capital, capital expenditures, general limited liability company purposes, or other purposes; and |
• | Limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate, including by limiting our ability to expand or pursue our business activities and by preventing us from engaging in certain transactions that might otherwise be considered beneficial to us. |
• | Payment of distributions and repayment of advances; |
• | Decisions on financings and our capital raising activities; |
• | Mergers or other business combinations; and |
• | Acquisition or disposition of assets. |
• | Transportation of natural gas in interstate commerce; |
• | Rates, operating terms, types of services and conditions of service; |
• | Certification and construction of new interstate pipeline and storage facilities; |
• | Acquisition, extension, disposition, or abandonment of existing interstate pipelines and storage facilities; |
• | Accounts and records; |
• | Depreciation and amortization policies; |
• | Relationships with affiliated companies who are involved in marketing functions of the natural gas business; and |
• | Market manipulation in connection with interstate sales, purchases, or transportation of natural gas. |
• | We utilized current FERC guidance for the default income tax rate for non-corporate taxpayers, which is an element of our overall effective tax rate. It is possible that the FERC will provide updated implementation guidance in the future, including an updated default income tax rate for non-corporate taxpayers. We estimate that a decline of one percentage point in our assumed overall effective tax rate would increase our regulatory liability by approximately $29 million. |
• | We made assumptions regarding the allocation of our taxable income between corporate and non-corporate taxpayers. This allocation is subject to annual variation that could impact the weighted average federal tax component of the overall income tax allowance rate. |
• | We made assumptions regarding the allocation of our taxable income among the states in which we conduct business. This allocation is subject to annual variation that could impact the weighted average state tax component of the overall income tax allowance rate. It is possible that certain states may change their income tax laws and/or rates in the future in response to Tax Reform. |
• | In determining the estimated liability that we currently believe is probable of return to customers through future rates, we considered the mix of services provided by us, taking into consideration that certain of these services are provided under contractually based rates, in lieu of recourse-based rates, that are designed to recover the cost of providing those services, with no expected future rate adjustment for the term of those contracts. We estimate that a one percent change in the relative mix of services would change the regulatory liability by approximately $8 million. |
• | $149.6 million increase in transportation reservation revenues related to new incremental projects primarily attributable to: |
• | $45.9 million from our Dalton project placed in partial service in April 2017, and fully in service in August 2017; |
• | $23.2 million from our Hillabee project Phase I placed in partial service in June 2017, and fully in service in July 2017; |
• | Partially offset by $6.2 million lower commodity revenues; |
• | $4.5 million lower firm transportation backhaul revenues; and |
• | $3.6 million due to one less billable day in 2017 compared to 2016. |
• | A $471.1 million increase in Regulatory charges resulting from Tax Reform (Note 1); |
• | A $6.5 million (11.4 percent) increase in Other expense, net primarily related to an unfavorable change in the deferral of Asset Retirement Obligations (ARO) related depreciation to a regulatory asset; |
• | An $84.9 million (26.8 percent) increase in Operation and maintenance costs mostly due to $59.2 million higher costs due to pipeline integrity, general maintenance and other testing on our pipeline, and higher employee labor and related benefit costs of $15.2 million, of which, $7.6 million was related to a pension early payout program; |
• | A $13.3 million (7.9 percent) increase in Administrative and general costs primarily due to higher allocated corporate expenses; |
• | A $10.4 million (3.4 percent) increase in Depreciation and amortization costs primarily due to $19.8 million higher expense related to additional assets placed into service, partly offset by $10.2 million lower expenses due to ARO related depreciation; and |
• | A $5.5 million (9.2 percent) increase in Taxes-other than income taxes primarily due to higher ad valorem taxes as a result of additional assets placed into service. |
• | A $27.7 million (748.6 percent) unfavorable change in Miscellaneous other (income) expenses, net primarily due to $32.7 million related to a regulatory asset charge associated with Tax Reform for the effects of deferred taxes on equity funds used during construction, partly offset by $5.1 million due to certain project related tax reimbursements; |
• | a $12.1 million (205.1 percent) unfavorable change in Equity in (earnings) loss of unconsolidated affiliates primarily related to a regulatory charge associated with establishing a regulatory liability resulting from Tax Reform; |
• | A $7.6 million (5.0 percent) unfavorable change in Interest expense-other primarily related to $10.1 million associated with an other financing obligation (See Note 3), partly offset by the absence of $2.9 million for our Washington Storage Service refunds recorded in 2016; and |
• | Partially offset by a $23.0 million (33.3 percent) favorable change in Allowance for equity and borrowed funds used during construction (AFUDC) associated with capital expenditures on projects. |
December 31, 2017 | Expected Maturity Date | ||||||||||||||
2018 | 2019 | 2020 | 2021 | ||||||||||||
(Dollars in millions) | |||||||||||||||
Long-term debt, excluding other financing obligation: | |||||||||||||||
Fixed rate | $ | 250 | $ | — | $ | — | $ | — | |||||||
Interest rate | 6.61 | % | 6.64 | % | 6.64 | % | 6.64 | % | |||||||
Other financing obligation: | |||||||||||||||
Fixed rate | $ | 2 | $ | 2 | $ | 2 | $ | 2 | |||||||
Interest rate | 9.53 | % | 9.53 | % | 9.53 | % | 9.53 | % | |||||||
December 31, 2017 | Expected Maturity Date | ||||||||||||||
2022 | Thereafter | Total | Fair Value | ||||||||||||
(Dollars in millions) | |||||||||||||||
Long-term debt, excluding other financing obligation: | |||||||||||||||
Fixed rate | $ | — | $ | 1,983 | $ | 2,233 | $ | 2,653 | |||||||
Interest rate | 6.64 | % | 5.49 | % | |||||||||||
Other financing obligation: | |||||||||||||||
Fixed rate | $ | 2 | $ | 221 | $ | 231 | $ | 450 | |||||||
Interest rate | 9.53 | % | 9.53 | % |
Years Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
Operating Revenues: | ||||||||||||
Natural gas sales | $ | 99,100 | $ | 86,720 | $ | 125,774 | ||||||
Natural gas transportation | 1,531,778 | 1,397,341 | 1,318,656 | |||||||||
Natural gas storage | 137,348 | 122,555 | 137,983 | |||||||||
Other | 6,779 | 9,519 | 10,106 | |||||||||
Total operating revenues | 1,775,005 | 1,616,135 | 1,592,519 | |||||||||
Operating Costs and Expenses: | ||||||||||||
Cost of natural gas sales | 99,100 | 86,720 | 125,774 | |||||||||
Cost of natural gas transportation | 19,589 | 19,689 | 26,501 | |||||||||
Operation and maintenance | 401,871 | 316,989 | 288,386 | |||||||||
Administrative and general | 182,121 | 168,759 | 179,489 | |||||||||
Depreciation and amortization | 318,058 | 307,707 | 277,850 | |||||||||
Taxes — other than income taxes | 65,612 | 60,119 | 49,567 | |||||||||
Regulatory charge resulting from Tax Reform (Note 1) | 471,096 | — | — | |||||||||
Other expense, net | 63,644 | 57,064 | 57,800 | |||||||||
Total operating costs and expenses | 1,621,091 | 1,017,047 | 1,005,367 | |||||||||
Operating Income | 153,914 | 599,088 | 587,152 | |||||||||
Other (Income) and Other Expenses: | ||||||||||||
Interest expense - affiliate | 60 | 60 | 64 | |||||||||
- other | 158,814 | 151,234 | 82,774 | |||||||||
Interest income - affiliate | (3,507 | ) | (2,201 | ) | (28 | ) | ||||||
- other | (2,782 | ) | (2,185 | ) | (1,933 | ) | ||||||
Allowance for equity and borrowed funds used during construction (AFUDC) | (92,013 | ) | (68,964 | ) | (63,072 | ) | ||||||
Equity in (earnings) loss of unconsolidated affiliates | 6,188 | (5,914 | ) | (5,593 | ) | |||||||
Miscellaneous other (income) expenses, net | 31,426 | 3,683 | (517 | ) | ||||||||
Total other (income) and other expenses | 98,186 | 75,713 | 11,695 | |||||||||
Net Income | 55,728 | 523,375 | 575,457 | |||||||||
Other comprehensive income: | ||||||||||||
Equity interest in unrealized gain on interest rate hedges (includes $103, $167, and $316 for the years ended December 31, 2017, 2016, and 2015, respectively, of accumulated other comprehensive income reclassification for equity interest in realized losses on interest rate hedges) | 327 | 41 | 84 | |||||||||
Comprehensive Income | $ | 56,055 | $ | 523,416 | $ | 575,541 |
December 31, | ||||||||
2017 | 2016 | |||||||
ASSETS | ||||||||
Current Assets: | ||||||||
Cash | $ | — | $ | — | ||||
Receivables: | ||||||||
Trade | 167,928 | 141,726 | ||||||
Affiliates | 1,109 | 489 | ||||||
Advances to affiliate | 395,247 | 811,693 | ||||||
Other | 2,494 | 2,589 | ||||||
Transportation and exchange gas receivables | 3,205 | 1,827 | ||||||
Inventories: | ||||||||
Gas in storage, at original cost | 790 | 786 | ||||||
Gas available for customer nomination, at average cost | 1,850 | 17,233 | ||||||
Materials and supplies, at lower of average cost or market | 37,387 | 37,190 | ||||||
Regulatory assets | 97,149 | 87,059 | ||||||
Other | 12,508 | 13,305 | ||||||
Total current assets | 719,667 | 1,113,897 | ||||||
Investments, at cost plus equity in undistributed earnings | 28,505 | 42,403 | ||||||
Property, Plant and Equipment: | ||||||||
Natural gas transmission plant | 13,771,183 | 11,996,454 | ||||||
Less-Accumulated depreciation and amortization | 3,859,520 | 3,687,473 | ||||||
Total property, plant and equipment, net | 9,911,663 | 8,308,981 | ||||||
Other Assets: | ||||||||
Regulatory assets | 276,315 | 264,001 | ||||||
Other | 141,786 | 102,198 | ||||||
Total other assets | 418,101 | 366,199 | ||||||
Total assets | $ | 11,077,936 | $ | 9,831,480 |
December 31, | ||||||||
2017 | 2016 | |||||||
LIABILITIES AND MEMBER’S EQUITY | ||||||||
Current Liabilities: | ||||||||
Payables: | ||||||||
Trade | $ | 444,021 | $ | 211,829 | ||||
Affiliates | 43,420 | 29,455 | ||||||
Cash overdrafts | 25,132 | 40,043 | ||||||
Transportation and exchange gas payables | 2,121 | 1,571 | ||||||
Accrued liabilities: | ||||||||
Property and other taxes | 12,843 | 13,594 | ||||||
Interest | 49,900 | 49,900 | ||||||
Regulatory liabilities | 16,350 | 9,120 | ||||||
Customer deposits | 15,754 | 47,049 | ||||||
Customer advances | 44,689 | 34,923 | ||||||
Asset retirement obligations | 13,676 | 26,934 | ||||||
Other | 20,390 | 16,177 | ||||||
Long-term debt due within one year | 251,430 | — | ||||||
Total current liabilities | 939,726 | 480,595 | ||||||
Long-Term Debt | 2,191,576 | 2,210,754 | ||||||
Other Long-Term Liabilities: | ||||||||
Asset retirement obligations | 350,280 | 248,518 | ||||||
Regulatory liabilities | 990,702 | 449,391 | ||||||
Advances for construction costs | 426,771 | 283,028 | ||||||
Transportation prepayments | 10,871 | 11,837 | ||||||
Deferred revenue | 225,858 | — | ||||||
Other | 4,828 | 6,088 | ||||||
Total other long-term liabilities | 2,009,310 | 998,862 | ||||||
Contingent Liabilities and Commitments (Note 2) | ||||||||
Member’s Equity: | ||||||||
Member’s capital | 4,088,499 | 3,678,499 | ||||||
Retained earnings | 1,848,488 | 2,462,760 | ||||||
Accumulated other comprehensive income | 337 | 10 | ||||||
Total member’s equity | 5,937,324 | 6,141,269 | ||||||
Total liabilities and member’s equity | $ | 11,077,936 | $ | 9,831,480 |
Years Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
Member's Capital: | ||||||||||||
Balance at beginning of period | $ | 3,678,499 | $ | 3,176,499 | $ | 2,524,499 | ||||||
Cash contributions from parent | 410,000 | 502,000 | 652,000 | |||||||||
Balance at end of period | 4,088,499 | 3,678,499 | 3,176,499 | |||||||||
Retained Earnings: | ||||||||||||
Balance at beginning of period | 2,462,760 | 2,379,385 | 2,339,928 | |||||||||
Net income | 55,728 | 523,375 | 575,457 | |||||||||
Cash distributions to parent | (430,000 | ) | (440,000 | ) | (536,000 | ) | ||||||
Non-cash distribution to parent | (240,000 | ) | — | — | ||||||||
Balance at end of period | 1,848,488 | 2,462,760 | 2,379,385 | |||||||||
Accumulated Other Comprehensive Income (Loss): | ||||||||||||
Balance at beginning of period | 10 | (31 | ) | (115 | ) | |||||||
Equity interest in unrealized gain (loss) on interest rate hedge | 327 | 41 | 84 | |||||||||
Balance at end of period | 337 | 10 | (31 | ) | ||||||||
Total Member's Equity | $ | 5,937,324 | $ | 6,141,269 | $ | 5,555,853 |
Years Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
Cash flows from operating activities: | ||||||||||||
Net income | $ | 55,728 | $ | 523,375 | $ | 575,457 | ||||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||||||
Depreciation and amortization | 318,058 | 307,707 | 277,850 | |||||||||
Allowance for equity funds used during construction (equity AFUDC) | (69,653 | ) | (56,468 | ) | (48,435 | ) | ||||||
Regulatory charge resulting from Tax Reform (Note 1) | 471,096 | — | — | |||||||||
Changes in operating assets and liabilities: | ||||||||||||
Receivables — affiliates | (620 | ) | 595 | (430 | ) | |||||||
— trade and other | (26,107 | ) | 5,941 | (19,521 | ) | |||||||
Transportation and exchange gas receivable | (1,378 | ) | 600 | 1,058 | ||||||||
Regulatory assets - current | (10,090 | ) | (7,484 | ) | (1,765 | ) | ||||||
Regulatory assets - non-current | (10,761 | ) | (271 | ) | (24,650 | ) | ||||||
Inventories | 15,182 | 1,632 | 9,858 | |||||||||
Payables — affiliates | 12,514 | (10,909 | ) | 2,676 | ||||||||
— trade | (9,823 | ) | 29,375 | (2,077 | ) | |||||||
Accrued liabilities | (29,651 | ) | 74,759 | (10,015 | ) | |||||||
Asset retirement obligations - non-current | 103,105 | 31,114 | 19,022 | |||||||||
Asset retirement obligation - removal costs | (4,578 | ) | (4,911 | ) | (3,097 | ) | ||||||
Deferred revenue | (4,542 | ) | — | — | ||||||||
Other, net | 14,415 | 32,030 | 45,007 | |||||||||
Net cash provided by operating activities | 822,895 | 927,085 | 820,938 | |||||||||
Cash flows from financing activities: | ||||||||||||
Proceeds from long-term debt | — | 998,250 | — | |||||||||
Retirement of long-term debt | — | (200,000 | ) | — | ||||||||
Payments on other financing obligations | (486 | ) | — | — | ||||||||
Payments for debt issuance costs | (13 | ) | (8,381 | ) | — | |||||||
Cash distributions to parent | (430,000 | ) | (440,000 | ) | (536,000 | ) | ||||||
Cash contributions from parent | 410,000 | 502,000 | 652,000 | |||||||||
Net cash provided by (used in) financing activities | (20,499 | ) | 851,869 | 116,000 |
Years Ended December 31, | ||||||||||||
2017 | 2016 | 2015 | ||||||||||
Cash flows from investing activities: | ||||||||||||
Property, plant and equipment additions, net of equity AFUDC* | $ | (1,576,611 | ) | $ | (1,213,969 | ) | $ | (1,270,860 | ) | |||
Contributions and advances for construction costs | 425,397 | 216,447 | 85,901 | |||||||||
Disposal of property, plant and equipment, net | (49,090 | ) | (12,529 | ) | (12,358 | ) | ||||||
Advances to affiliate, net | 416,446 | (747,085 | ) | 242,302 | ||||||||
Return of capital from unconsolidated affiliates | 3,926 | 2,767 | 2,015 | |||||||||
Purchase of ARO Trust investments | (57,099 | ) | (70,901 | ) | (64,087 | ) | ||||||
Proceeds from sale of ARO Trust investments | 31,435 | 44,195 | 43,284 | |||||||||
Proceeds from insurance | 3,200 | 2,121 | 35,132 | |||||||||
Other, net | — | — | 1,560 | |||||||||
Net cash used in investing activities | (802,396 | ) | (1,778,954 | ) | (937,111 | ) | ||||||
Increase (decrease) in cash | — | — | (173 | ) | ||||||||
Cash at beginning of period | — | — | 173 | |||||||||
Cash at end of period | $ | — | $ | — | $ | — | ||||||
____________________________ | ||||||||||||
* Increase to property, plant and equipment, net of equity AFUDC | $ | (1,784,254 | ) | $ | (1,200,696 | ) | $ | (1,222,292 | ) | |||
Changes in related accounts payable and accrued liabilities | 207,643 | (13,273 | ) | (48,568 | ) | |||||||
Property, plant and equipment additions, net of equity AFUDC | $ | (1,576,611 | ) | $ | (1,213,969 | ) | $ | (1,270,860 | ) | |||
Supplemental disclosures of cash flow information: | ||||||||||||
Cash paid during the year for: | ||||||||||||
Interest (exclusive of amount capitalized) | $ | 136,439 | $ | 103,391 | $ | 66,489 | ||||||
Income taxes | 2,089 | 828 | 1,161 |
Category of Property | 2017-2015 | |
Gathering facilities | 1.35% - 2.50% | |
Storage facilities | 2.10% - 2.25% | |
Onshore transmission facilities | 2.61% - 5.00% | |
Offshore transmission facilities | 1.20% - 1.20% |
2017 | 2016 | |||||||
Debentures: | ||||||||
7.08% due 2026 | $ | 7,500 | $ | 7,500 | ||||
7.25% due 2026 | 200,000 | 200,000 | ||||||
Total debentures | 207,500 | 207,500 | ||||||
Notes: | ||||||||
6.05% due 2018 | 250,000 | 250,000 | ||||||
7.85% due 2026 | 1,000,000 | 1,000,000 | ||||||
5.4% due 2041 | 375,000 | 375,000 | ||||||
4.45% due 2042 | 400,000 | 400,000 | ||||||
Total notes | 2,025,000 | 2,025,000 | ||||||
Other financing obligation | 230,926 | — | ||||||
Total long-term debt, including current portion | 2,463,426 | 2,232,500 | ||||||
Unamortized debt issuance costs | (15,377 | ) | (16,408 | ) | ||||
Unamortized debt premium and discount, net | (5,043 | ) | (5,338 | ) | ||||
Long-term debt due within one year | (251,430 | ) | — | |||||
Total long-term debt | $ | 2,191,576 | $ | 2,210,754 |
2018: 6.05% Notes and other financing obligation | $ | 251,566 | ||
2019: Other financing obligation | $ | 1,721 | ||
2020: Other financing obligation | $ | 1,893 | ||
2021: Other financing obligation | $ | 2,081 | ||
2022: Other financing obligation | $ | 2,289 |
2018 | $ | 13,558 | ||
2019 | 14,890 | |||
2020 | 14,860 | |||
2021 | 14,710 | |||
2022 | 14,654 | |||
Thereafter | 122,333 | |||
Total net minimum obligations | $ | 195,005 |
December 31, 2017 | December 31, 2016 | |||||||||||||||
Amortized Cost Basis | Fair Value | Amortized Cost Basis | Fair Value | |||||||||||||
Cash and Money Market Funds | $ | 12.6 | $ | 12.6 | $ | 5.0 | $ | 5.0 | ||||||||
U.S. Equity Funds | 35.9 | 50.5 | 29.4 | 36.5 | ||||||||||||
International Equity Funds | 20.7 | 24.6 | 19.2 | 18.6 | ||||||||||||
Municipal Bond Funds | 46.8 | 46.9 | 36.7 | 36.3 | ||||||||||||
Total | $ | 116.0 | $ | 134.6 | $ | 90.3 | $ | 96.4 |
Fair Value Measurements Using | ||||||||||||||||||||
Carrying Amount | Fair Value | Quoted Prices In Active Markets for Identical Assets (Level 1) | Significant Other Observable Inputs (Level 2) | Significant Unobservable Inputs (Level 3) | ||||||||||||||||
(Millions) | ||||||||||||||||||||
Assets (liabilities) at December 31, 2017: | ||||||||||||||||||||
Measured on a recurring basis: | ||||||||||||||||||||
ARO Trust investments | $ | 134.6 | $ | 134.6 | $ | 134.6 | $ | — | $ | — | ||||||||||
Additional disclosures: | ||||||||||||||||||||
Long-term debt, including current portion | (2,443.0 | ) | (3,103.3 | ) | — | (3,103.3 | ) | — | ||||||||||||
Assets (liabilities) at December 31, 2016: | ||||||||||||||||||||
Measured on a recurring basis: | ||||||||||||||||||||
ARO Trust investments | $ | 96.4 | $ | 96.4 | $ | 96.4 | $ | — | $ | — | ||||||||||
Additional disclosures: | ||||||||||||||||||||
Long-term debt | (2,210.8 | ) | (2,507.5 | ) | — | (2,507.5 | ) | — |
2017 | 2016 | 2015 | |||||||||
Duke Energy Corporation | $ | 198.4 | $ | 178.9 | $ | 94.6 | |||||
National Grid | 177.4 | 166.3 | 129.6 | ||||||||
The Southern Company, Inc. | 160.0 | 69.6 | 61.6 |
2017 | 2016 | |||||||
Beginning balance | $ | 275,452 | $ | 323,026 | ||||
Accretion (1) | 104,659 | 35,740 | ||||||
New obligations | 28,447 | 7,995 | ||||||
Changes in estimates of existing obligations (2) | (38,470 | ) | (85,514 | ) | ||||
Property dispositions/obligations settled | (6,132 | ) | (5,795 | ) | ||||
Ending balance | $ | 363,956 | $ | 275,452 |
(1) | The increase in accretion for 2017 includes the cumulative effect of accretion adjustment associated with new AROs identified in our historical land agreements of $87 million that are not a component of new obligations. |
(2) | Changes in estimates of existing obligations are primarily due to the annual review process, which considers various factors including inflation rate, current estimates for removal cost, discount rates, and the estimated remaining life of assets. The changes in estimates of existing obligations reflect a decrease of $38 million and $86 million for 2017 and 2016, respectively. The decrease in 2017 is primarily due to a decrease in current estimates for offshore removal costs. The decrease in 2016 is due primarily to revisions in the estimated remaining life of assets and the current estimate to the inflation rate. |
Regulatory Assets | 2017 | 2016 | ||||||
Grossed-up deferred taxes on equity funds used during construction | $ | 37.9 | $ | 73.2 | ||||
Asset retirement obligations | 168.7 | 117.2 | ||||||
Asset retirement costs - Eminence | 49.5 | 53.9 | ||||||
Deferred taxes - asset | 3.8 | 4.8 | ||||||
Deferred cash out | 42.5 | 48.2 | ||||||
Deferred gas costs | 6.0 | — | ||||||
Fuel cost | 61.4 | 51.3 | ||||||
Other | 3.7 | 2.5 | ||||||
Total Regulatory Assets | $ | 373.5 | $ | 351.1 |
Regulatory Liabilities | 2017 | 2016 | ||||||
Negative salvage | $ | 409.7 | $ | 357.1 | ||||
Deferred taxes - liability | 471.1 | — | ||||||
Sentinel meter station depreciation | 6.3 | 6.2 | ||||||
Postretirement benefits other than pension | 73.9 | 63.0 | ||||||
Electric power cost | 13.3 | 6.3 | ||||||
Pension - deferred collections | 32.5 | 21.3 | ||||||
Other | 0.3 | 4.6 | ||||||
Total Regulatory Liabilities | $ | 1,007.1 | $ | 458.5 |
2017 | First | Second | Third | Fourth (1) | ||||||||||||
Operating revenues | $ | 413,716 | $ | 432,502 | $ | 452,052 | $ | 476,735 | ||||||||
Operating expenses | 246,539 | 274,719 | 300,436 | 799,397 | ||||||||||||
Operating income (loss) | 167,177 | 157,783 | 151,616 | (322,662 | ) | |||||||||||
Interest expense | 37,257 | 37,236 | 41,304 | 43,077 | ||||||||||||
Other (income) and deductions, net | (24,936 | ) | (31,121 | ) | (24,020 | ) | 19,389 | |||||||||
Net income (loss) | 154,856 | 151,668 | 134,332 | (385,128 | ) | |||||||||||
Equity interest in unrealized gain (loss) on interest rate hedge | 35 | 1 | 72 | 219 | ||||||||||||
Comprehensive income (loss) | $ | 154,891 | $ | 151,669 | $ | 134,404 | $ | (384,909 | ) |
2016 | First (2) | Second | Third | Fourth | ||||||||||||
Operating revenues | $ | 395,866 | $ | 393,017 | $ | 412,849 | $ | 414,403 | ||||||||
Operating expenses | 242,691 | 245,375 | 264,686 | 264,295 | ||||||||||||
Operating income | 153,175 | 147,642 | 148,163 | 150,108 | ||||||||||||
Interest expense | 38,822 | 37,817 | 37,318 | 37,337 | ||||||||||||
Other (income) and deductions, net | (10,365 | ) | (18,015 | ) | (21,068 | ) | (26,133 | ) | ||||||||
Net income | 124,718 | 127,840 | 131,913 | 138,904 | ||||||||||||
Equity interest in unrealized gain (loss) on interest rate hedge | (234 | ) | (50 | ) | 156 | 169 | ||||||||||
Comprehensive income | $ | 124,484 | $ | 127,790 | $ | 132,069 | $ | 139,073 |
(1) | Includes $471.1 million increase to operating expenses for a regulatory charge resulting from Tax Reform. Includes $12.2 million increase to operating expenses for the portion of Williams' pension settlement costs charged to us. Includes $32.7 million unfavorable change to other (income) and deductions, net for regulatory assets associated with the effects of deferred taxes on equity funds used during construction as a result of Tax Reform. Includes $10.3 million unfavorable change to other (income) and deductions, net for regulatory charge resulting from Tax Reform for our equity investments. |
(2) | Includes $15.0 million decrease to operating revenues to establish an accrual for Washington Storage Service potential refunds. Includes $6.3 million increase to operating expenses for severance related costs. Includes $2.9 million increase to interest expense related to interest on refunds for Washington Storage Services. |
2017 | 2016 | |||||||
Audit fees | $ | 1,300 | $ | 1,314 | ||||
Audit-related fees | — | — | ||||||
Tax fees | — | — | ||||||
All other fees | — | — | ||||||
Total fees | $ | 1,300 | $ | 1,314 |
Page Reference to 2017 10-K | |
A. 1 and 2. Transcontinental Gas Pipe Line Company, LLC financials | |
Index | |
Covered by Report of Independent Registered Public Accounting Firm: | |
Not covered by Report of Independent Registered Public Accounting Firm: | |
The following schedules are omitted because of the absence of the conditions under which they are required: I, II, III, IV, and V. |
Exhibit Number | Description | |
2 | ||
3.1 | ||
3.2 | ||
4.1 | ||
4.2 | ||
4.3 | ||
4.4 | ||
4.5 | ||
10.1 | ||
10.2 | ||
10.3 | ||
10.4 | ||
10.5 | ||
31.1* | ||
31.2* | ||
32 ** |
101.INS* 101.I SCH * 101.CAL* 101.DEF* 101.LAB* | XBRL Instance Document. XBRL Taxonomy Extension Schema. XBRL Taxonomy Extension Calculation Linkbase. XBRL Taxonomy Extension Definition Linkbase. XBRL Taxonomy Extension Label Linkbase. | |
101.PRE* | XBRL Taxonomy Extension Presentation Linkbase. |
* Filed herewith. ** Furnished herewith. |
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC (Registrant) | ||
By: | /s/ Ted T. Timmermans | |
Ted T. Timmermans | ||
Vice President, Controller and Chief Accounting Officer (Principal Accounting Officer) |
Signature | Title | |
/s/ Frank J. Ferazzi | Management Committee Member and Senior Vice President (Principal Executive Officer) | |
Frank J. Ferazzi | ||
/s/ Ted T. Timmermans | Vice President, Controller and Chief Accounting Officer (Principal Financial and Accounting Officer) | |
Ted T. Timmermans |
1. | I have reviewed this annual report on Form 10-K of Transcontinental Gas Pipe Line Company, LLC; |
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(s) 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(s) 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/ Frank J. Ferazzi |
Frank J. Ferazzi | |
Senior Vice President | |
(Principal Executive Officer) |
1. | I have reviewed this annual report on Form 10-K of Transcontinental Gas Pipe Line Company, LLC; |
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(s) 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(s) 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/ Ted T. Timmermans |
Ted T. Timmermans | |
Vice President, Controller and Chief Accounting Officer | |
(Principal Financial Officer) |
(1) | The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and |
(2) | The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. |
/s/ Frank J. Ferazzi |
Frank J. Ferazzi |
Senior Vice President |
February 22, 2018 |
/s/ Ted T. Timmermans |
Ted T. Timmermans |
Vice President, Controller and Chief Accounting Officer |
February 22, 2018 |
Document and Entity Information Document - USD ($) |
12 Months Ended | |
---|---|---|
Dec. 31, 2017 |
Feb. 22, 2018 |
|
Entity Information [Line Items] | ||
Entity Registrant Name | Transcontinental Gas Pipe Line Company, LLC | |
Entity Central Index Key | 0000099250 | |
Document Type | 10-K | |
Document Period End Date | Dec. 31, 2017 | |
Amendment Flag | false | |
Document Fiscal Year Focus | 2017 | |
Document Fiscal Period Focus | FY | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Entity Common Stock, Shares Outstanding | 0 | |
Entity Well-known Seasoned Issuer | No | |
Entity Voluntary Filers | No | |
Entity Current Reporting Status | Yes | |
Entity Public Float | $ 0 |
Consolidated Statement of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands |
12 Months Ended | ||
---|---|---|---|
Dec. 31, 2017 |
Dec. 31, 2016 |
Dec. 31, 2015 |
|
Income Statement [Abstract] | |||
Accumulated other comprehensive income reclassification for realized losses on interest rate hedges | $ 103 | $ 167 | $ 316 |
Consolidated Balance Sheet Consolidated Balance Sheet (Parenthetical) - USD ($) $ in Thousands |
Dec. 31, 2017 |
Dec. 31, 2016 |
---|---|---|
Statement of Financial Position [Abstract] | ||
Allowance for receivables | $ 0 | $ 0 |
Summary of Significant Accounting Policies (Notes) |
12 Months Ended | ||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Dec. 31, 2017 | |||||||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||
Summary of Significant Accounting Policies | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Corporate Structure and Control In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and, unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” Transco is indirectly owned by Williams Partners L.P. (WPZ), a publicly traded Delaware limited partnership, which is consolidated by The Williams Companies, Inc. (Williams). In January 2017, Williams permanently waived the WPZ general partner's incentive distribution rights, converted its 2 percent general partner interest in WPZ to a non-economic interest and purchased additional WPZ common units. At December 31, 2017, Williams owns a 74 percent limited partner interest in WPZ. Transco is a single member limited liability company, and as such, single member losses are limited to the amount of its investment. Related Party Transaction A former member of Williams' Board of Directors, who was elected in 2013 and resigned during 2016, is also the current chairman, president, and chief executive officer of Public Service Enterprise Group, an energy services company that is a customers of ours. This board member does not have any material interest in any transactions between the energy services company and us and he had no role in any such transactions. Nature of Operations We are an interstate natural gas transmission company that owns a natural gas pipeline system extending from Texas, Louisiana, Mississippi and the Gulf of Mexico through Alabama, Georgia, South Carolina, North Carolina, Virginia, Maryland, Delaware, Pennsylvania and New Jersey to the New York City metropolitan area. The system serves customers in Texas and the 12 southeast and Atlantic seaboard states mentioned above, including major metropolitan areas in Georgia, Washington D.C., Maryland, North Carolina, New York, New Jersey and Pennsylvania. Regulatory Accounting We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) Regulated Operations (Topic 980), provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations (ARO), and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. In December 2017, the Tax Cuts and Jobs Act was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (Tax Reform). In accordance with ASC 980-740-25-2, we have recognized a regulatory liability to reflect the probable return to certain customers through future rates of the future decrease in income taxes payable associated with Tax Reform. In determining the estimated liability that we currently believe is probable of return to certain customers through future rates, we considered the mix of services provided by us, taking into consideration that certain of these services are provided under contractually based rates, in lieu of recourse-based rates, that are designed to recover the cost of providing those services, with no expected future rate adjustment for the term of those contracts. The liability was recorded in December 2017 through a regulatory charge to operating income of $471.1 million. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service. Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity in (earnings) loss of unconsolidated affiliates on our Consolidated Statement of Comprehensive Income has been reduced by $10.3 million related to our proportionate share of the associated regulatory charges. Our regulatory asset associated with the effects of deferred taxes on equity funds used during construction were also impacted by Tax Reform and were reduced by $32.7 million in December 2017 through a charge to Miscellaneous other (income) expenses, net on our Consolidated Statement of Comprehensive Income. Basis of Presentation Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2017, the remaining property, plant and equipment allocation was approximately $0.6 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost. Principles of Consolidation The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 2017 and December 31, 2016 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $8.0 million, $8.6 million, and $7.6 million in 2017, 2016 and 2015, respectively. Included in the distributions are $3.9 million, $2.8 million and $2.0 million return of capital in 2017, 2016 and 2015, respectively. Use of Estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; 6) asset retirement obligations; and 7) regulatory deferred taxes. Revenue Recognition Revenues for transportation of gas under long-term firm agreements are recognized considering separately the reservation and commodity charges. Reservation revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the reservation, capacity, and injection and withdrawal charges. Reservation and capacity revenues are recognized monthly over the term of the agreement regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided in our FERC tariff. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note). As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks. Environmental Matters We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates. Property, Plant and Equipment Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income. We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2017, 2016 and 2015 are as follows:
We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates. Impairment of Long-lived Assets We evaluate the long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $22.3 million, $12.5 million and $14.6 million, for 2017, 2016 and 2015, respectively. The allowance for equity funds was $69.7 million, $56.5 million, and $48.4 million, for 2017, 2016 and 2015, respectively. Income Taxes We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by unitholders of our ultimate parent, WPZ. Net income for financial statement purposes may differ significantly from taxable income of WPZ’s unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the WPZ partnership agreement. The aggregated difference in the basis of our assets for financial and tax reporting purposes cannot be readily determined because information regarding each of WPZ’s unitholder’s tax attributes in WPZ is not available to us. Accounts Receivable and Allowance for Doubtful Receivables Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination. Gas Imbalances In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2017 and 2016. We utilize the average cost method of accounting for gas imbalances. Deferred Cash Out Most transportation imbalances are settled in cash on a monthly basis (cash out). We are required by our tariff to refund revenues received from the cash out of transportation imbalances in excess of costs incurred during the annual August through July reporting period. Revenues received in excess of costs incurred are deferred until refunded in accordance with the tariff. Gas Inventory We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2017 and 2016, Gas in Storage, at LIFO, was zero. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost. Materials and Supplies Inventory All inventories are stated at lower of average cost or net realizable value. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2017 and 2016. Contingent Liabilities We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates. Pension and Other Postretirement Benefits We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 6.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost. Cash Flows from Operating Activities and Cash Equivalents We use the indirect method to report cash flows from operating activities, which requires adjustments to net income to reconcile to net cash flows provided by operating activities. We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents. Accounting Standards Issued But Not Yet Adopted In August 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments” (ASU 2016-15). ASU 2016-15 provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. ASU 2016-15 is effective for interim and annual periods beginning after December 15, 2017. Early adoption is permitted. ASU 2016-15 requires a retrospective transition. We do not expect ASU 2016-15 to have a material impact on our consolidated financial statements. In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (ASU 2016-13). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans, and other instruments, entities will be required to use a new forward-looking “expected loss” model that generally will result in the earlier recognition of allowances for losses. The guidance also requires increased disclosures. ASU 2016-13 is effective for interim and annual periods beginning after December 15, 2019. Early adoption is permitted. ASU 2016-13 requires varying transition methods for the different categories of amendments. We do not expect ASU 2016-13 to have a significant impact on our consolidated financial statements. In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842)” (ASU 2016-02). ASU 2016-02 establishes a comprehensive new lease accounting model. ASU 2016-02 modifies the definition of a lease, requires a dual approach to lease classification similar to current lease accounting, and causes lessees to recognize leases on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset, with an exception for leases with a term of one year or less. Additional disclosures will also be required regarding the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842” (ASU 2018-01). Per ASU 2018-01, land easements and rights-of-way are required to be assessed under ASU 2016-02 to determine whether the arrangements are or contain a lease and permits an entity to elect a transition practical expedient to not apply ASU 2016-02 to land easements that exist or expired before the effective date of ASU 2016-02 and that were not previously assessed under the previous lease guidance in ASC Topic 840 “Leases”. ASU 2016-02 is effective for interim and annual periods beginning after December 15, 2018. Early adoption is permitted. ASU 2016-02 currently requires a modified retrospective transition for financing or operating leases existing at or entered into after the beginning of the earliest comparative period presented in the financial statements. In January 2018, the FASB proposed an accounting standard update titled “Leases (Topic 842): Targeted Improvements”, which is an update to ASU 2016-02 allowing entities an additional transition method to the existing requirements whereby an entity could adopt the provisions of ASU 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. We expect to adopt ASU 2016-02 effective January 1, 2019. We are in the process of reviewing contracts to identify leases based on the modified definition of a lease, implementing a financial lease accounting system, and evaluating internal control changes to support management in the accounting for and disclosure of leasing activities. While we are still in the process of completing our implementation evaluation of ASU 2016-02, we currently believe the most significant changes relate to the recognition of a lease liability and offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases. We are also evaluating ASU 2016-02's currently available and proposed practical expedients on adoption. In May 2014, the FASB issued ASU 2014-09 establishing ASC Topic 606, “Revenue from Contracts with Customers” (ASC 606). ASC 606 establishes a comprehensive new revenue recognition model designed to depict the transfer of goods or services to a customer in an amount that reflects the consideration the entity expects to be entitled to receive in exchange for those goods or services and requires significantly enhanced revenue disclosures. In August 2015, the FASB issued ASU 2015-14 “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” (ASU 2015-14). Per ASU 2015-14, the standard is effective for interim and annual reporting periods beginning after December 15, 2017. ASC 606 allows either full retrospective or modified retrospective transition and early adoption is permitted for annual periods beginning after December 15, 2016. We are adopting ASC 606 utilizing the modified retrospective transition approach, effective January 1, 2018. We do not anticipate any cumulative effect adjustment to retained earnings upon initially applying ASC 606 for periods prior to January 1, 2018. We are in the final stages of evaluating the impact ASC 606 will have on our financial statements. For each revenue contract type, we have conducted a formal contract review process to evaluate the impact of ASC 606. We have substantially completed our evaluation. During the fourth quarter of 2017, we concluded on certain technical matters, including the evaluation of significant financing components and prepayments for services, resulting in no adjustment upon adoption. We continue to evaluate and develop disclosures required under the new standard, with a particular focus on the scope of contracts subject to disclosure of remaining performance obligations. Financial system and internal control changes necessary for adoption have been implemented effective as of January 1, 2018. We do not expect ASC 606 to have a material impact on the timing of our revenue recognition. |
Contingent Liabilities and Commitments (Notes) |
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Commitments and Contingencies Disclosure [Abstract] | |
Contingent Liabilities and Commitments | CONTINGENT LIABILITIES AND COMMITMENTS Rate Matters General rate case (Docket No. RP06-569) On August 31, 2006, we submitted to the FERC a general rate filing principally designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one were resolved by settlement. The one issue reserved for litigation or further settlement related to our proposal to change the design of the rates for service under our WSS-OA storage rate schedule, which was implemented subject to refund on March 1, 2007. Following a hearing, the FERC issued an opinion approving our proposed incremental rate design, and subsequently denied requests for rehearing of that approval. On February 21, 2014, the U. S. Court of Appeals for the D.C. Circuit (D.C. Circuit) issued an opinion that vacated and remanded the FERC's order because the FERC did not adequately support its conclusions. On March 17, 2016, the FERC issued an order addressing the issues raised by the D.C. Circuit's opinion. In the March 17 order, the FERC reversed its prior opinion and found that Transco's incremental rate design was unjust and unreasonable. The FERC directed Transco to design its WSS-OA rates on a rolled-in basis, to file revised WSS-OA rates reflecting the findings in the order, and to refund the amounts collected in excess of those rates since March 1, 2007. On April 18, 2016, we submitted the compliance filing reflecting rolled-in rates for WSS-OA service consistent with the March 17 order, and began charging those rates beginning April 19, 2016. We also filed a request for rehearing of the March 17 order. On October 4, 2017, the FERC issued an order denying all requests for rehearing of the March 17 order, accepting our April 18, 2016 compliance filing, and directing us to make refunds. No party filed a request for rehearing of the October 4 order, and no party filed an appeal of the March 17, 2016 or October 4, 2017 order. On November 16, 2017, we issued refunds of $19.2 million to the affected customers. The rates we charge to our customers are subject to the rate-making policies of the FERC. These policies permit us to include in our cost-of-service an income tax allowance that includes a deferred income tax component. The recently enacted Tax Reform, makes significant changes to the U.S. federal income tax rules applicable to both individuals and entities, including among other things, a reduction in corporate federal income tax rates. Although we expect that the decreased federal income tax rates will require us to return amounts to certain customers in the future and as a result we recognized a regulatory liability as of the date of enactment of Tax Reform, the details of any regulatory implementation guidance remain uncertain. Station 62 Incident On October 8, 2015, an explosion and fire occurred at our Compressor Station No. 62 in Gibson, Louisiana. At the time of the incident, planned facility maintenance was being performed at the station and the facility was not operational. The incident was related to maintenance work being performed on the slug catcher at the station. Four contractor employees were killed in the incident and others were injured. In responding to the incident, we cooperated with local, state and federal authorities, including the Louisiana State Police, Terrebonne Parish, the Louisiana Department of Environmental Quality, the U.S. Environmental Protection Agency (Region 6), the Occupational Safety and Health Administration, and the U.S. Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA). On July 29, 2016, PHMSA issued a Notice of Probable Violation (NOPV), which includes a $1.6 million proposed civil penalty to us in connection with the incident. This penalty was accrued in the second quarter of 2016 and would not be covered by our insurance policies. We filed a response to the NOPV on August 25, 2016, and on July 14, 2017, PHMSA held a hearing on the NOPV. The incident did not cause any rupture of the gas pipeline or any damage to the building containing the compressor engines. In anticipation of the planned maintenance, our Southeast Louisiana Lateral was taken out of service on October 4, 2015, which affected approximately 200 MMcf/d of natural gas production. The lateral was restored to service in early 2016 after repairs were made to the facilities damaged in the incident. We are a defendant in lawsuits seeking damages for wrongful death, personal injury and property damages. We believe it is reasonably possible that losses will be incurred on some lawsuits. However, in management's judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. While we also have claims for indemnification, we believe that it is probable that any ultimate losses incurred will be covered by our general liability insurance policy. Environmental Matters We have had studies underway for many years to test some of our facilities for the presence of toxic and hazardous substances such as polychlorinated biphenyls (PCBs) and mercury to determine to what extent, if any, remediation may be necessary. We have also similarly evaluated past on-site disposal of hydrocarbons at a number of our facilities. We have worked closely with and responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $6 million to $8 million (including both expense and capital expenditures), measured on an undiscounted basis, and will substantially be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At December 31, 2017, we had a balance of approximately $4.0 million for the expense portion of these estimated costs, $1.8 million recorded in Accrued liabilities - Other and $2.2 million recorded in Other Long-Term Liabilities - Other in the accompanying Consolidated Balance Sheet. At December 31, 2016, we had a balance of approximately $4.2 million for the expense portion of these estimated costs, $2.1 million recorded in Accrued liabilities - Other and $2.1 million recorded in Other Long-Term Liabilities - Other in the accompanying Consolidated Balance Sheet. We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $6 million to $8 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act and applicable state law can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above. The EPA and various state regulatory agencies routinely promulgate and propose new rules, and issue updated guidance to existing rules. More recent rules and rulemakings include, but are not limited to, rules for reciprocating internal combustion engine maximum achievable control technology, air quality standards for one hour nitrogen dioxide emissions, and volatile organic compound and methane new source performance standards impacting design and operation of storage vessels, pressure valves, and compressors. On October 1, 2015, the EPA issued its rule regarding National Ambient Air Quality Standards for ground-level ozone, setting a stricter standard of 70 parts per billion. We are monitoring the rule’s implementation as the reduction will trigger additional federal and state regulatory actions that may impact our operations. Implementation of the regulations is expected to result in impacts to our operations and increase the cost of additions to Total property, plant and equipment, net in the Consolidated Balance Sheet for both new and existing facilities in affected areas. We are unable to reasonably estimate the cost of additions that may be required to meet the regulations at this time due to uncertainty created by various legal challenges to these regulations and the need for further specific regulatory guidance. We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Consolidated Balance Sheet until collected through rates. At December 31, 2017, we had a balance of approximately $2.2 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $1.0 million recorded in Other Assets - Regulatory assets in the accompanying Consolidated Balance Sheet. At December 31, 2016, we had a balance of approximately $2.5 million of uncollected environmental related regulatory assets, $1.2 million recorded in Current Assets - Regulatory assets and $1.3 million recorded in Other Assets - Regulatory assets in the accompanying Consolidated Balance Sheet. Other Matters Various other proceedings are pending against us and are considered incidental to our operations. Summary We estimate that for all matters for which we are able to reasonably estimate a range of loss, including those noted above and others that are not individually significant, our aggregate reasonably possible losses beyond amounts accrued for all of our contingent liabilities are immaterial to our expected future annual results of operations, liquidity and financial position. These calculations have been made without consideration of any potential recovery from third parties. We have disclosed all significant matters for which we are unable to reasonably estimate a range of possible loss. Other Commitments Commitments for construction We have commitments for construction and acquisition of property, plant and equipment of approximately $114 million at December 31, 2017. |
Debt, Financing Arrangements and Leases (Notes) |
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Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt, Financing Arrangements and Leases | DEBT, FINANCING ARRANGEMENTS AND LEASES Long-Term Debt At December 31, 2017 and 2016, long-term debt outstanding was as follows (in thousands):
Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2017, for the next five years, are as follows (in thousands):
No property is pledged as collateral under any of our long-term debt issues. Restrictive Debt Covenants At December 31, 2017, none of our debt instruments restrict the amount of distributions to our parent, provided, however, that under the credit facility described below, we are restricted from making distributions to our parent during an event of default if we have directly incurred indebtedness under the credit facility. Our debt agreements contain restrictions on our ability to incur secured debt beyond certain levels and to guarantee certain indebtedness. The indenture governing our $1 billion of 7.85% Senior Notes due 2026 further restricts our ability to guarantee certain indebtedness. Issuance and Retirement of Long-Term Debt On January 22, 2016, we issued $1 billion of 7.85 percent senior unsecured notes due 2026 to investors in a private debt placement. A portion of these proceeds was used to retire our $200 million of 6.4 percent notes that matured on April 15, 2016. We used the remainder for funding of capital expenditures. As part of the new issuance, we entered into a registration rights agreement with the initial purchasers of the unsecured notes. We were obligated to file and consummate a registration statement for an offer to exchange the notes for a new issue of substantially identical notes registered under the Securities Act, within 365 days from closing and to use commercially reasonable efforts to complete the exchange offer. In January 2017, we completed an exchange of these notes for substantially identical new notes that are registered under the Securities Act. Other Financing Obligation During the construction of our Dalton Expansion Project, we received funding from a partner for its proportionate share of construction costs related to its undivided ownership interest in the Dalton lateral. Amounts received were recorded in Advances for construction costs and 100 percent of the costs associated with construction were capitalized on our Consolidated Balance Sheet. Upon placing the project in service during the third quarter of 2017, we began leasing this partner's undivided interest in the lateral, including the associated pipeline capacity, and reclassified approximately $235.8 million of funding previously received from our partner from Advances for construction costs to Long-Term Debt on our Consolidated Balance Sheet to reflect the financing obligation payable to our partner over an expected term of 35 years. At December 31, 2017, the amount included in Long-Term Debt on our Consolidated Balance Sheet for financing obligation is $229.4 million. As this transaction did not meet the criteria for sale leaseback accounting due to our continued involvement, it was accounted for as a financing arrangement over the course of the capacity agreement. The obligation matures in July 2052, requires monthly interest and principal payments, and bears an interest rate of approximately 10 percent. Long-Term Debt Due Within One Year The long-term debt due within one year at December 31, 2017 is associated with the $250 million of 6.05 percent notes maturing on June 15, 2018 and with the previously described other financing obligation. Credit Facility On February 2, 2015, we along with WPZ, Northwest, the lenders named therein and an administrative agent entered into the Second Amended & Restated Credit Agreement with aggregate commitments available of $3.5 billion, with up to an additional $500 million increase in aggregate commitments available under certain circumstances. In November 2017, the maturity date of the facility was extended to February 2, 2021. However, the co-borrowers may request an additional extension of the maturity date for a one year period to allow a maturity date as late as February 2, 2022, under certain circumstances. The agreement allows for swing line loans up to aggregate amount of $150 million, subject to available capacity under the credit facility, and letters of credit commitments available to WPZ of $1.125 billion. We are able to borrow up to $500 million under this credit facility to the extent not otherwise utilized by the other co-borrowers. At December 31, 2017, no letters of credit have been issued and no loans to WPZ were outstanding under the credit facility. Measured as of December 31, 2017, we are in compliance with our financial covenant under the credit facility. Various covenants may limit, among other things, a borrower's and its material subsidiaries' ability to grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, enter into certain restrictive agreements, and allow any material change in the nature of its business. If an event of default with respect to a borrower occurs under the credit facility, the lenders will be able to terminate the commitments for the respective borrowers and accelerate the maturity of any loans of the defaulting borrower under the credit facility agreement and exercise other rights and remedies. Other than swing line loans, each time funds are borrowed, the borrower must choose whether such borrowing will be an alternate base rate borrowing or a Eurodollar borrowing. If such borrowing is an alternate base rate borrowing, interest is calculated on the basis of the greater of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus one half of 1 percent and (c) a periodic fixed rate equal to the London Interbank Offered Rate (LIBOR) plus 1 percent, plus, in the case of each of (a), (b) and (c), an applicable margin. If the borrowing is a Eurodollar borrowing, interest is calculated on the basis of LIBOR for the relevant period plus an applicable margin. Interest on swing line loans is calculated as the sum of the alternate base rate plus an applicable margin. The borrower is required to pay a commitment fee based on the unused portion of the credit facility. The applicable margin and the commitment fee are determined for each borrower by reference to a pricing schedule based on such borrower's senior unsecured long-term debt ratings. WPZ participates in a commercial paper program and WPZ management considers amounts outstanding under this program to be a reduction of available capacity under the credit facility. The program allows a maximum outstanding amount at any time of $3 billion of unsecured commercial paper notes. At December 31, 2017, WPZ had no outstanding commercial paper. Lease Obligations The future minimum lease payments under our various operating leases are as follows (in thousands):
Our lease expense was $11.0 million in 2017, $10.6 million in 2016, and $10.7 million in 2015. |
ARO Trust (Notes) |
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Investments, Debt and Equity Securities [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
ARO Trust | ARO TRUST Available-for-Sale Investments We are entitled to collect in rates the amounts necessary to fund our ARO. We deposit monthly, into an external trust account (ARO Trust), the revenues specifically designated for ARO. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities. Effective March 1, 2013, the annual funding obligation is approximately $36.4 million, with deposits made monthly. Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):
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Fair Value Measurements (Notes) |
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Fair Value Measurements | FAIR VALUE MEASUREMENTS The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash, short-term financial assets (advances to affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
Fair Value of Methods The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale and are reported in Other Assets-Other in the Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust. Long-term debt - The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (See Note 3 - Debt and Financing Agreements). Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the year ended December 31, 2017 or 2016. |
Benefit Plans (Notes) |
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Dec. 31, 2017 | |
Retirement Benefits [Abstract] | |
Benefit Plans | BENEFIT PLANS Certain of the benefit costs charged to us by Williams associated with employees who directly support us are described below. Additionally, allocated corporate expenses from Williams to us also include amounts related to these same employee benefits, which are not included in the amounts presented below. Pension and Other Postretirement Benefit Plans Williams has noncontributory defined benefit pension plans (Williams Pension Plan, Williams Inactive Employees Pension Plan and The Williams Companies Retirement Restoration Plan) that provide pension benefits for its eligible employees. Pension cost charged to us by Williams was $15.6 million, $8.7 million and $13.5 million for 2017, 2016, and 2015, respectively. Included in our 2017 pension costs is a $7.6 million settlement charge. This amount reflects the portion of Williams’ settlement charge directly charged to us which was required as a result of lump-sum benefit payments made under Williams’ 2017 program to pay out certain deferred vested pension benefits, as well as lump-sum benefit payments made throughout 2017. In addition, we were charged $4.6 million of allocated corporate expenses also associated with the settlement charge. Williams makes annual cash contributions to the pension plans, based on annual actuarial estimates, which Transco recovers through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and collected or refunded through future rate adjustments. The amount of deferred pension collections recorded as a regulatory liability at December 31, 2017 and 2016 were $32.5 million and $21.3 million, respectively. Williams provides subsidized retiree health care and life insurance benefits to certain eligible participants. Generally, participants that were employed by Williams on or before December 31, 1991 or December 31, 1995, if they were employees or retirees of Transco Energy Company and its subsidiaries, are eligible for subsidized retiree health care benefits. We recognized other postretirement benefit income of $10.9 million, $12.0 million and $11.9 million for 2017, 2016, and 2015, respectively. We have been allowed by rate case settlements to collect or refund in future rates any differences between the actuarially determined costs and amounts currently being recovered in rates related to other postretirement benefits. Any differences between the annual actuarially determined cost and amounts currently being recovered in rates are recorded as an adjustment to expense and collected or refunded through future rate adjustments. The amount of other postretirement benefits costs deferred as a regulatory liability at December 31, 2017 and 2016 are $73.9 million and $63.0 million, respectively. These amounts are comprised of amounts being deferred for future rate treatment of $65.4 million and $52.0 million at December 31, 2017 and 2016, respectively, and amounts of $8.5 million and $11.0 million being amortized over a period of approximately 8 years per Docket No. RP12-993 at December 31, 2017 and 2016, respectively. Defined Contribution Plan Williams maintains a defined contribution plan for substantially all of its employees. Williams charged us compensation expense of $7.7 million, $6.5 million and $6.6 million in 2017, 2016 and 2015, respectively, for Williams’ company matching contributions to this plan. Employee Stock-Based Compensation Plan Information The Williams Companies, Inc. 2007 Incentive Plan, as subsequently amended and restated, (Plan) provides for Williams’ common stock based awards to both employees and non-management directors. The Plan permits the granting of various types of awards including, but not limited to, restricted stock units and stock options. Awards may be granted for no consideration other than prior and future services or based on certain financial performance targets achieved. Williams currently bills us directly for compensation expense related to stock-based compensation awards based on the fair value of the awards. We are also billed for our proportionate share of Williams’ and other affiliates’ stock-based compensation expense through various allocation processes. Total stock-based compensation expense for the years ended December 31, 2017, 2016, and 2015 was $5.7 million, $4.0 million and $4.0 million, respectively, excluding amounts allocated from WPZ and Williams. |
Transactions with Major Customers and Affiliates (Notes) |
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Transactions with Major Customers and Affiliates [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Transactions with Major Customers and Affiliates | TRANSACTIONS WITH MAJOR CUSTOMERS AND AFFILIATES Major Customers Operating revenues received from three of our major customers in 2017, 2016 and 2015 are as follows (in millions):
Affiliates We are a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At December 31, 2017 and 2016, our advances to WPZ totaled approximately $395.2 million and $811.7 million, respectively. These advances are represented by demand notes and are classified as Receivables - Advances to affiliate in the accompanying Consolidated Balance Sheet. Advances are stated at the historical carrying amounts. Interest income is recognized when chargeable and collectability is reasonably assured. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At December 31, 2017, the interest rate was 1.16 percent. Included in Operating Revenues in the accompanying Consolidated Statement of Comprehensive Income for 2017, 2016 and 2015 are revenues received from affiliates of $10.3 million, $11.2 million, and $4.6 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers. Included in Cost of natural gas sales in the accompanying Consolidated Statement of Comprehensive Income for 2017, 2016 and 2015 is purchased gas cost from affiliates of $3.9 million, $4.3 million, and $6.0 million, respectively. All gas purchases are made at market or contract prices. We have no employees. Services necessary to operate our business are provided to us by Williams and certain affiliates of Williams. We reimburse Williams and its affiliates for all direct and indirect expenses incurred or payments made (including salary, bonus, incentive compensation and benefits) in connection with these services. Employees of Williams also provide general, administrative and management services to us, and we are charged for certain administrative expenses incurred by Williams. These charges are either directly identifiable or allocated to our assets. Direct charges are for goods and services provided by Williams at our request. Allocated charges are based on a three-factor formula, which considers revenues; property, plant and equipment; and payroll. In management’s estimation, the allocation methodologies used are reasonable and result in a reasonable allocation to us of our costs of doing business incurred by Williams. We were billed $370.4 million, $318.4 million, and $327.1 million during 2017, 2016 and 2015, respectively, for these services. Such expenses are primarily included in Administrative and general and Operation and maintenance expenses in the accompanying Consolidated Statement of Comprehensive Income. The amount billed to us during 2016 includes $7.4 million for severance and other related costs associated with a reduction in workforce primarily recognized in the first quarter. We provide services to certain of our affiliates. We recorded reductions in operating expenses for services provided to and reimbursed by our affiliates of $3.7 million, $4.3 million, and $5.7 million in 2017, 2016 and 2015, respectively. We made equity distributions of $430 million, $440 million and $536 million during 2017, 2016 and 2015, respectively. During 2017, 2016 and 2015, our parent made contributions totaling $410 million, $502 million and $652 million, respectively, to us to fund a portion of our expenditures for additions to property, plant and equipment. During July 2017, we recorded deferred revenue and recognized a non-cash distribution to our parent of $240 million associated with funds received by WPZ related to the March 2016 WPZ agreement with the member-sponsors of Sabal Trail regarding the Hillabee Expansion and Sabal Trail projects. Although the agreement was between WPZ and the member-sponsors, since the agreement was, in part, related to furthering the completion of Hillabee, this deferred revenue is assigned to our results of operations over the 25-year term of the capacity agreement with Sabal Trail. |
Asset Retirement Obligations (Notes) |
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Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligations | ASSET RETIREMENT OBLIGATIONS These accrued obligations relate to underground storage caverns, offshore platforms, pipelines, and gas transmission facilities. At the end of the useful life of each respective asset, we are legally obligated to plug storage caverns and remove any related surface equipment, to dismantle offshore platforms, to cap certain gathering pipelines at the wellhead connection and remove any related surface equipment, and to remove certain components of gas transmission facilities from the ground. During 2017 and 2016, our overall asset retirement obligation changed as follows (in thousands):
We are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements are deposited into an external trust account dedicated to funding our ARO. Under our current rate settlement our annual funding obligation is approximately $36.4 million, with installments to be deposited monthly (See Note 4). |
Regulatory Assets and Liabilities (Notes) |
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Regulatory Assets and Liabilities Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets and Liabilities | REGULATORY ASSETS AND LIABILITIES The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2017 and December 31, 2016 are as follows (in millions):
The significant regulatory assets and liabilities include: Grossed-up deferred taxes on equity funds used during construction: Regulatory asset balance established to offset the deferred tax for the equity component of the allowance for funds used during the construction of long-lived assets. All amounts were generated during the period that we were a taxable entity. Taxes on capitalized funds used during construction and the offsetting deferred income taxes are included in the rate base and are recovered over the depreciable lives of the long-lived asset to which they relate. Asset retirement obligations: Regulatory asset balance established to offset depreciation of the ARO asset and changes in the ARO liability due to the passage of time. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates (See Note 8). Asset retirement costs - Eminence: Regulatory asset balance associated with the Eminence Storage Field retirement costs. The regulatory asset is being recovered through our rates, and is being amortized to expense consistent with the amounts collected in rates. Deferred taxes - asset: Regulatory asset balance was established as a result of an increase to rate base deferred taxes due to an increase to the effective state income tax rate. The regulatory asset is being collected from rate payers over the remaining depreciable lives of the long-lived asset to which they relate. Deferred cash out: This amount represents the deferral of gains or losses on the purchases and sales of gas imbalances with shippers. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual cash out filing periods. Deferred gas costs: This amount arises from the movement of gas volumes between gas inventory accounts that have different valuations. These amounts are expected to be recovered/refunded in subsequent periods. Fuel cost: This amount represents the difference between the gas retained from our customers and the gas consumed in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual fuel tracker filing periods. Negative salvage: Our rates include a component designed to recover certain future retirement costs for which we are not required to record an asset retirement obligation. We record a regulatory liability representing the cumulative residual amount of recoveries through rates, net of expenditures associated with these retirement costs. Sentinel meter station depreciation: This amount reflects the incremental depreciation being recorded related to the meter station modifications made for three of the Sentinel shippers. These modifications will be recovered through a surcharge over a defined period of time as stated in the Sentinel FERC order. The incremental depreciation represents the difference between the FERC granted depreciation rate for such facilities in the last rate case as compared to the depreciation rates in the Sentinel order which are based on the contractual terms in the surcharge agreements. The incremental depreciation will be recorded through the end of the contractual term and then will be amortized. Postretirement benefits: We recover the actuarially determined cost of postretirement benefits through rates that are set through periodic general rate filings. Any difference between the annual actuarially determined cost and the amount recovered in rates is recorded as a regulatory asset or liability to be collected or refunded through future rate adjustments. These amounts are not included in the rate base (See Note 6). Electric power cost: This amount represents the difference between the electric power costs recovered from our customers and the electric power costs incurred in operations. These amounts are not included in the rate base but are expected to be recovered/refunded in subsequent annual electric power tracker filing periods. Pension - deferred collections: We recover the actuarially determined pension cash contributions through rates that are set through periodic general rate filings. Effective with the RP12-993 Settlement, any amounts of annual contributions that exceed an upper threshold or fall below a lower threshold are recorded as adjustments to income and collected or refunded through future rate adjustments (See Note 6). Deferred taxes - liability: Regulatory liability balance was established as a result of a decrease to rate base deferred taxes due to a decrease to the effective federal income tax rate. The timing of the refund of the regulatory liability to rate payers will be subject to future discussions and negotiations with our customers in our next rate case. |
Other (Notes) |
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Dec. 31, 2017 | |
Other Income and Expenses [Abstract] | |
Other | OTHER During 2017 and 2016, we capitalized $0.2 million and $1.4 million, respectively, of project feasibility costs, which had been expensed in prior periods in Other expense, net, upon determining that the project was probable of development. The Advances for construction costs on the Consolidated Balance Sheet are associated with advances received from third parties related to construction costs on the Atlantic Sunrise and Dalton projects. This balance increases as we receive additional advances. After construction of the respective projects are completed, the related liabilities will be reclassified to Long-Term Debt and reduced by payments we make to the third parties under terms of the applicable lease agreements. In the third quarter of 2017, the advances received from a third party related to construction costs on the Dalton lateral was reclassified to Long-Term Debt on our Consolidated Balance Sheet. |
Summary of Significant Accounting Policies (Policies) |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||
Regulatory Accounting | Regulatory Accounting We are regulated by the Federal Energy Regulatory Commission (FERC). The Accounting Standards Codification (ASC) Regulated Operations (Topic 980), provides that rate-regulated public utilities account for and report regulatory assets and liabilities consistent with the economic effect of the way in which regulators establish rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Accounting for businesses that are regulated and apply the provisions of Topic 980 can differ from the accounting requirements for non-regulated businesses. Transactions that are recorded differently as a result of regulatory accounting requirements include the capitalization of an equity return component on regulated capital projects, capitalization of other project costs, retirements of general plant assets, employee related benefits, environmental costs, negative salvage, asset retirement obligations (ARO), and other costs and taxes included in, or expected to be included in, future rates. As a rate-regulated entity, our management has determined that it is appropriate to apply the accounting prescribed by Topic 980 and, accordingly, the accompanying consolidated financial statements include the effects of the types of transactions described above that result from regulatory accounting requirements. In December 2017, the Tax Cuts and Jobs Act was enacted, which, among other things, reduced the federal corporate income tax rate from 35 percent to 21 percent (Tax Reform). In accordance with ASC 980-740-25-2, we have recognized a regulatory liability to reflect the probable return to certain customers through future rates of the future decrease in income taxes payable associated with Tax Reform. In determining the estimated liability that we currently believe is probable of return to certain customers through future rates, we considered the mix of services provided by us, taking into consideration that certain of these services are provided under contractually based rates, in lieu of recourse-based rates, that are designed to recover the cost of providing those services, with no expected future rate adjustment for the term of those contracts. The liability was recorded in December 2017 through a regulatory charge to operating income of $471.1 million. The timing and actual amount of such return will be subject to future negotiations regarding this matter and many other elements of cost-of-service rate proceedings, including other costs of providing service. Certain of our equity-method investees recorded similar regulatory liabilities, for which our Equity in (earnings) loss of unconsolidated affiliates on our Consolidated Statement of Comprehensive Income has been reduced by $10.3 million related to our proportionate share of the associated regulatory charges. Our regulatory asset associated with the effects of deferred taxes on equity funds used during construction were also impacted by Tax Reform and were reduced by $32.7 million in December 2017 through a charge to Miscellaneous other (income) expenses, net on our Consolidated Statement of Comprehensive Income. |
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Basis of Presentation | Basis of Presentation Williams’ acquisition of Transco Energy Company and its subsidiaries, including us, in 1995 was accounted for using the purchase method of accounting. Accordingly, an allocation of the purchase price was assigned to our assets and liabilities based on their estimated fair values. The purchase price allocation to us primarily consisted of a $1.5 billion allocation to property, plant and equipment and adjustments to deferred taxes based upon the book basis of the net assets recorded as a result of the acquisition. The amount allocated to property, plant and equipment is being depreciated on a straight-line basis over 40 years, the estimated useful lives of these assets at the date of acquisition, at approximately $35 million per year. At December 31, 2017, the remaining property, plant and equipment allocation was approximately $0.6 billion. Current FERC policy does not permit us to recover through rates amounts in excess of original cost. |
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Principles of Consolidation | Principles of Consolidation The consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of December 31, 2017 and December 31, 2016 consist of Cardinal Pipeline Company, LLC (Cardinal) with ownership interest of approximately 45 percent and Pine Needle LNG Company, LLC (Pine Needle) with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $8.0 million, $8.6 million, and $7.6 million in 2017, 2016 and 2015, respectively. Included in the distributions are $3.9 million, $2.8 million and $2.0 million return of capital in 2017, 2016 and 2015, respectively. |
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Use of Estimates | Use of Estimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; 6) asset retirement obligations; and 7) regulatory deferred taxes. |
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Revenue Recognition | Revenue Recognition Revenues for transportation of gas under long-term firm agreements are recognized considering separately the reservation and commodity charges. Reservation revenues are recognized monthly over the term of the agreement regardless of the volume of natural gas transported. Commodity revenues from both firm and interruptible transportation are recognized in the period transportation services are provided based on volumes of natural gas physically delivered at the agreed upon delivery point. Revenues for the storage of gas under firm agreements are recognized considering separately the reservation, capacity, and injection and withdrawal charges. Reservation and capacity revenues are recognized monthly over the term of the agreement regardless of the volume of storage service actually utilized. Injection and withdrawal revenues are recognized in the period when volumes of natural gas are physically injected into or withdrawn from storage. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. The resulting imbalances are primarily settled through the purchase and sale of gas with our customers under terms provided in our FERC tariff. Revenue is recognized from the sale of gas upon settlement of the transportation and exchange imbalances (See Gas Imbalances in this Note). As a result of the ratemaking process, certain revenues collected by us may be subject to refunds upon the issuance of final orders by the FERC in pending rate proceedings. We record estimates of rate refund liabilities considering our and other third-party regulatory proceedings, advice of counsel and other risks. |
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Environmental Matters | Environmental Matters We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit and potential for rate recovery. We believe that any expenditures required to meet applicable environmental laws and regulations are prudently incurred in the ordinary course of business and such expenditures would be permitted to be recovered through rates. |
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Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment is recorded at cost. The carrying values of these assets are also based on estimates, assumptions and judgments relative to capitalized costs, useful lives and salvage values. These estimates, assumptions and judgments reflect FERC regulations, as well as historical experience and expectations regarding future industry conditions and operations. The FERC identifies installation, construction and replacement costs that are to be capitalized. All other costs are expensed as incurred. Gains or losses from the ordinary sale or retirement of property, plant and equipment are credited or charged to accumulated depreciation; certain other gains or losses are recorded in operating income. We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2017, 2016 and 2015 are as follows:
We record a liability and increase the basis in the underlying asset for the present value of each expected future ARO at the time the liability is initially incurred, typically when the asset is acquired or constructed. Measurements of AROs include, as a component of future expected costs, an estimate of the price that a third party would demand, and could expect to receive, for bearing the uncertainties inherent in the obligations, sometimes referred to as a market-risk premium. The ARO asset is depreciated in a manner consistent with the expected timing of the future abandonment of the underlying physical assets. We measure changes in the liability due to passage of time by applying an interest method of allocation. The depreciation of the ARO asset and accretion of the ARO liability are recognized as an increase to a regulatory asset, as management expects to recover such amounts in future rates. The regulatory asset is amortized commensurate with our collection of these costs in rates. |
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Impairment of Long-Lived Assets | Impairment of Long-lived Assets We evaluate the long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. When an indicator of a potential impairment has occurred we compare our management’s estimate of undiscounted future cash flows attributable to the assets to the carrying value of the assets to determine whether an impairment has occurred. We apply a probability-weighted approach to consider the likelihood of different cash flow assumptions and possible outcomes including selling in the near term or holding for the remaining estimated useful life. If an impairment of the carrying value has occurred, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. For assets identified to be disposed of in the future and considered held for sale in accordance with the ASC Property, Plant, and Equipment (Topic 360), we compare the carrying value to the estimated fair value less the cost to sell to determine if recognition of an impairment is required. Until the assets are disposed of, the estimated fair value, which includes estimated cash flows from operations until the assumed date of sale, is recalculated when related events or circumstances change. Judgments and assumptions are inherent in our management’s estimate of undiscounted future cash flows used to determine recoverability of an asset and the estimate of an asset’s fair value used to calculate the amount of impairment to recognize. |
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Allowance for Funds Used During Construction | Allowance for Funds Used During Construction Allowance for funds used during construction (AFUDC) represents the estimated cost of borrowed and equity funds applicable to utility plant in process of construction and are included as a cost of property, plant and equipment because it constitutes an actual cost of construction under established regulatory practices. The FERC has prescribed a formula to be used in computing separate allowances for borrowed and equity AFUDC. The allowance for borrowed funds used during construction was $22.3 million, $12.5 million and $14.6 million, for 2017, 2016 and 2015, respectively. The allowance for equity funds was $69.7 million, $56.5 million, and $48.4 million, for 2017, 2016 and 2015, respectively. |
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Income Taxes | Income Taxes We generally are not a taxable entity for federal or state and local income tax purposes. The tax on net income is generally borne by unitholders of our ultimate parent, WPZ. Net income for financial statement purposes may differ significantly from taxable income of WPZ’s unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under the WPZ partnership agreement. The aggregated difference in the basis of our assets for financial and tax reporting purposes cannot be readily determined because information regarding each of WPZ’s unitholder’s tax attributes in WPZ is not available to us. |
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Accounts Receivable and Allowance for Doubtful Receivables | Accounts Receivable and Allowance for Doubtful Receivables Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. Our credit risk exposure in the event of nonperformance by the other parties is limited to the face value of the receivables. We perform ongoing credit evaluations of our customers’ financial condition and require collateral from our customers, if necessary. Due to our customer base, we have not historically experienced recurring credit losses in connection with our receivables. Receivables determined to be uncollectible are reserved or written off in the period of determination. |
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Gas Imbalances | Gas Imbalances In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on behalf of us than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables which are recovered or repaid in cash or through the receipt or delivery of gas in the future and are recorded in the accompanying Consolidated Balance Sheet. Settlement of imbalances requires agreement between the pipelines and shippers as to allocations of volumes to specific transportation contracts and timing of delivery of gas based on operational conditions. Our tariff includes a method whereby most transportation imbalances are settled on a monthly basis. Each month a portion of the imbalances are not identified to specific parties and remain unsettled. These are generally identified to specific parties and settled in subsequent periods. We believe that amounts that remain unidentified to specific parties and unsettled at year end are valid balances that will be settled with no material adverse effect upon our financial position, results of operations or cash flows. Management has implemented a policy of continuing to carry any unidentified transportation and exchange imbalances on the books for a three-year period. At the end of the three year period a final assessment will be made of their continued validity. Absent a valid reason for maintaining the imbalance, any remaining balance will be recognized in income. Certain imbalances are being recovered or repaid in cash or through the receipt or delivery of gas upon agreement of the parties as to the allocation of the gas volumes, and as permitted by pipeline operating conditions. These imbalances have been classified as current assets and current liabilities at December 31, 2017 and 2016. We utilize the average cost method of accounting for gas imbalances. Deferred Cash Out Most transportation imbalances are settled in cash on a monthly basis (cash out). We are required by our tariff to refund revenues received from the cash out of transportation imbalances in excess of costs incurred during the annual August through July reporting period. Revenues received in excess of costs incurred are deferred until refunded in accordance with the tariff. |
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Inventory | Gas Inventory We utilize the last-in, first-out (LIFO) method of accounting for inventory gas in storage. At December 31, 2017 and 2016, Gas in Storage, at LIFO, was zero. The basis for determining current cost at the end of each year is the December monthly average gas price delivered to pipelines in Texas and Louisiana. We utilize the average cost method of accounting for gas available for customer nomination. Liquefied natural gas in storage is valued at original cost. Materials and Supplies Inventory All inventories are stated at lower of average cost or net realizable value. We perform an annual review of Materials and Supplies inventories, including a quarterly analysis of parts that may no longer be useful due to planned replacements of compressor engines and other components on our system. Based on this assessment, we record a reserve for the value of the inventory which can no longer be used for maintenance and repairs on our pipeline. There was a minimal reserve at December 31, 2017 and 2016. |
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Contingent Liabilities | Contingent Liabilities We record liabilities for estimated loss contingencies, including environmental matters, when we assess that a loss is probable and the amount of the loss can be reasonably estimated. These liabilities are calculated based upon our assumptions and estimates with respect to the likelihood or amount of loss and upon advice of legal counsel, engineers, or other third parties regarding the probable outcomes of the matters. These calculations are made without consideration of any potential recovery from third-parties. We recognize insurance recoveries or reimbursements from others when realizable. Revisions to these liabilities are generally reflected in income when new or different facts or information become known or circumstances change that affect the previous assumptions or estimates. |
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Pension and Other Postretirement Benefits | Pension and Other Postretirement Benefits We do not have employees. Certain of the costs charged to us by Williams associated with employees who directly support us include costs related to Williams’ pension and other postretirement benefit plans. (See Note 6.) Although the underlying benefit plans of Williams are single-employer plans, we follow multiemployer plan accounting whereby the amount charged to us and thus paid by us, is based on our share of net periodic benefit cost. |
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Cash Equivalents | We include short-term, highly-liquid investments that have an original maturity of three months or less as cash equivalents. |
Fair Value Measurements (Policies) |
12 Months Ended |
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Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | Fair Value of Methods The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value: ARO Trust investments - We deposit a portion of our collected rates, pursuant to the terms of the Docket No. RP12-993 rate case settlement, into the ARO Trust which is specifically designated to fund future asset retirement obligations. The ARO Trust invests in a portfolio of actively traded mutual funds that are measured at fair value on a recurring basis based on quoted prices in an active market, are classified as available-for-sale and are reported in Other Assets-Other in the Consolidated Balance Sheet. However, both realized and unrealized gains and losses are ultimately recorded as regulatory assets or liabilities. See Note 4 for more information regarding the ARO Trust. Long-term debt - The disclosed fair value of our long-term debt is determined primarily by a market approach using broker quoted indicative period-end bond prices. The quoted prices are based on observable transactions in less active markets for our debt or similar instruments. The fair value of the financing obligation associated with our Dalton lateral, which is included within long-term debt, was determined using an income approach (See Note 3 - Debt and Financing Agreements). Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No transfers between Level 1 and Level 2 occurred during the year ended December 31, 2017 or 2016. |
Summary of Significant Accounting Policies (Tables) |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||
Depreciation rates | We provide for depreciation under the composite (group) method at straight-line FERC prescribed rates that are applied to the cost of the group for transmission facilities, production and gathering facilities and storage facilities. Under this method, assets with similar lives and characteristics are grouped and depreciated as one asset. Included in our depreciation rates is a negative salvage component (net cost of removal) that we currently collect in rates. Our depreciation rates are subject to change each time we file a general rate case with the FERC. Depreciation rates used for major regulated gas plant facilities at December 31, 2017, 2016 and 2015 are as follows:
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Debt, Financing Arrangements and Leases (Tables) |
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Debt Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Long-term debt | At December 31, 2017 and 2016, long-term debt outstanding was as follows (in thousands):
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Maturities of long-term debt | Aggregate minimum maturities (face value) applicable to long-term debt outstanding at December 31, 2017, for the next five years, are as follows (in thousands):
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Future minimum lease payments | The future minimum lease payments under our various operating leases are as follows (in thousands):
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ARO Trust (Tables) |
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Dec. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Investments, Debt and Equity Securities [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
ARO Trust | Investments in available-for-sale securities within the ARO Trust at fair value were as follows (in millions):
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Fair Value Measurements (Tables) |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of fair value, assets and liabilities measured on recurring basis | The following table presents, by level within the fair value hierarchy, certain of our financial assets and liabilities. The carrying values of cash, short-term financial assets (advances to affiliate) that have variable interest rates, accounts receivable and accounts payable approximate fair value because of the short-term nature of these instruments. Therefore, these assets and liabilities are not presented in the following table.
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Transactions with Major Customers and Affiliates (Tables) |
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Transactions with Major Customers and Affiliates [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of revenue by major customers | Operating revenues received from three of our major customers in 2017, 2016 and 2015 are as follows (in millions):
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Asset Retirement Obligations (Tables) |
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Dec. 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Asset Retirement Obligation Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of change in asset retirement obligation | During 2017 and 2016, our overall asset retirement obligation changed as follows (in thousands):
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Regulatory Assets and Liabilities (Tables) |
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Dec. 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Regulatory Assets and Liabilities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Regulatory Assets [Table Text Block] | The regulatory assets and regulatory liabilities resulting from our application of the provisions of ASC Topic 980, Regulated Operations, included in the accompanying Consolidated Balance Sheet at December 31, 2017 and December 31, 2016 are as follows (in millions):
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Schedule of Regulatory Liabilities [Table Text Block] |
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Asset Retirement Obligations (Details) - USD ($) $ in Thousands |
12 Months Ended | |
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Dec. 31, 2017 |
Dec. 31, 2016 |
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Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning balance | $ 275,452 | $ 323,026 |
Accretion (1) | 104,659 | 35,740 |
New obligations | 28,447 | 7,995 |
Changes in estimates of existing obligations (2) | (38,470) | (85,514) |
Property dispositions/obligations settled | (6,132) | (5,795) |
Ending balance | 363,956 | 275,452 |
Annual funding obligation | 36,400 | |
Asset retirement obligation [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Changes in estimates of existing obligations (2) | (38,000) | $ (86,000) |
Accretion (1) | 87,000 | |
External ARO trust [Member] | ||
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Annual funding obligation | $ 36,400 |
Other (Details) - USD ($) $ in Millions |
12 Months Ended | |
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Dec. 31, 2017 |
Dec. 31, 2016 |
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Property, Plant and Equipment [Line Items] | ||
Capitalization of project feasibility costs previously expensed | $ 0.2 | $ 1.4 |
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