filings.toolsItem 6. SELECTED FINANCIAL DATA
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Item 6. SELECTED FINANCIAL DATA
The following table sets forth our selected financial data for the periods indicated:
| Years Ended December 31, | ||||||||||||||||||||
| 2018 | 2017 | 2016 | 2015 | 2014 | ||||||||||||||||
| (Millions of dollars, except per share data) | ||||||||||||||||||||
| Revenues | $ | 12,593.2 | $ | 12,173.9 | $ | 8,920.9 | $ | 7,763.2 | $ | 12,195.1 | ||||||||||
| Net income | $ | 1,155.0 | $ | 593.5 | $ | 743.5 | $ | 379.2 | $ | 663.1 | ||||||||||
| Net income attributable to ONEOK | $ | 1,151.7 | $ | 387.8 | $ | 352.0 | $ | 245.0 | $ | 314.1 | ||||||||||
| Total assets | $ | 18,231.7 | $ | 16,845.9 | $ | 16,138.8 | $ | 15,446.1 | $ | 15,261.8 | ||||||||||
| Long-term debt, including current maturities | $ | 9,381.0 | $ | 8,524.3 | $ | 8,330.6 | $ | 8,434.2 | $ | 7,160.8 | ||||||||||
| Earnings per share - total | ||||||||||||||||||||
| Basic | $ | 2.80 | $ | 1.30 | $ | 1.67 | $ | 1.17 | $ | 1.50 | ||||||||||
| Diluted | $ | 2.78 | $ | 1.29 | $ | 1.66 | $ | 1.16 | $ | 1.49 | ||||||||||
| Dividends declared per share of common stock | $ | 3.245 | $ | 2.72 | $ | 2.46 | $ | 2.43 | $ | 2.125 |
Upon adoption of Topic 606 in January 2018, we determined that certain Natural Gas Gathering and Processing segment POP with fee contracts and Natural Gas Liquids segment exchange services contracts that include the purchase of commodities are supplier contracts. Therefore, contractual fees in these identified contracts are now recorded as a reduction of the commodity purchase price in cost of sales and fuel. In 2017 and prior periods, these fees were recorded as services revenue. For more information, see Note O in the Notes to the Consolidated Financial Statements.
In the fourth quarter 2017, we recorded a one-time noncash charge to net income through income tax expense of $141.3 million, related to the revaluation of our deferred tax balances and a valuation allowance on certain state net operating loss and tax credit carryforwards resulting from the enactment of the Tax Cuts and Jobs Act. For more information, see Note L in the Notes to the Consolidated Financial Statements.
Also in 2017, we incurred a $20.0 million noncash expense related to our Series E Preferred Stock contribution to the Foundation and operating costs related to the Merger Transaction of $30.0 million.
We recorded noncash impairment charges of $20.2 million, $264.3 million and $76.4 million in 2017, 2015 and 2014, respectively.
| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion and analysis should be read in conjunction with Part I, Item 1, Business, our audited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Annual Report.
RECENT DEVELOPMENTS
Please refer to the “Financial Results and Operating Information” and “Liquidity and Capital Resources” sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations in this Annual Report for additional information.
Merger Transaction - On June 30, 2017, we completed the acquisition of all of the outstanding common units of ONEOK Partners that we did not already own. Prior to June 30, 2017, we and our subsidiaries owned all of the general partner interest, which included incentive distribution rights, and a portion of the limited partner interest, which together represented a 41.2 percent ownership interest in ONEOK Partners. The earnings of ONEOK Partners that are attributed to its units held by the public during the six months ended June 30, 2017, are reported as “Net income attributable to noncontrolling interests” in our Consolidated Statement of Income. Our general partner incentive distribution rights effectively terminated at the closing of the Merger Transaction.
Market Conditions - Volumes increased across our operating regions in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in 2018, compared with 2017, as a result of improved crude oil prices, producers experiencing improved drilling economics and continued improvements in production due to enhanced completion techniques. While commodity
prices decreased in the fourth quarter 2018 and are expected to fluctuate in 2019, we do not expect a material impact on supply volumes across our business segments.
For most of 2018, we benefited from favorable NGL price differentials as available pipeline and fractionation capacity in and between the Conway, Kansas, and Mont Belvieu, Texas, market centers tightened due to growing NGL supply from the Mid-Continent and Rocky Mountain regions, combined with increased petrochemical and NGL export demand in the Gulf Coast, resulting in higher earnings from our Natural Gas Liquids segment’s optimization and marketing activities. In the fourth quarter 2018, these differentials narrowed resulting from seasonality of supply and demand in the Mid-Continent region, lower commodity prices and additional pipeline and fractionation capacity resulting from operational efficiencies. While we expect NGL price differentials to be volatile in 2019, we expect that they will be wider than historical norms due to additional demand in the Gulf Coast, additional NGL supply growth in the Mid-Continent region and continuing fractionation and pipeline constraints. We expect these wider NGL price differentials to continue until announced NGL pipeline and fractionation infrastructure projects, including our Arbuckle II pipeline, are completed in early 2020.
Ethane Opportunity - Ethane volumes delivered to our NGL system have been increasing since 2016, primarily as a result of NGL demand increasing from exports and petrochemical companies completing ethylene production projects and plant expansions. Ethane volumes across our system increased to 380 MBbl/d in 2018, compared with 315 MBbl/d in 2017. Our NGL capital-growth projects are expected to help alleviate system constraints, enabling additional NGLs, including ethane, to reach the Mont Belvieu, Texas, market center. We expect the amount of ethane delivered to our system to continue to fluctuate as NGL supply continues to increase, petrochemical companies complete expansion projects and exports increase.
Growth Projects - Increased producer activity and supply growth across our assets have increased demand for midstream infrastructure. We are responding to this growing demand by constructing assets to meet the needs of natural gas processors and producers across our operating regions, including the Williston, Permian, Powder River and DJ Basins and the STACK and SCOOP areas. We also expect additional demand for our services to support increased demand for NGL products from the petrochemical industry and NGL exporters, and increased demand for natural gas from exports and power plants, some of which rely on natural gas when renewable energy is not available.
We have spent approximately $2 billion of our announced $6 billion of additional capital-growth projects, including NGL pipelines, NGL fractionators and natural gas processing plants, that are designed to serve the expected growth and needs of natural gas processors and producers and the petrochemical industry. We expect these growth projects to provide long-term fee-based earnings and incremental cash flows. We have contracted for, and taken delivery of, a substantial amount of the steel pipe required for our pipeline projects from vendors located predominately in the United States. In addition to our large capital-growth projects discussed below, we are expanding our natural gas pipeline infrastructure in the Permian Basin and Oklahoma to provide additional natural gas takeaway capacity in these regions. Our announced large capital-growth projects are outlined in the tables below:
| Project | Scope | Approximate Costs (a) | Completion Date |
| Natural Gas Gathering and Processing | (In millions) | ||
| Additional STACK processing capacity | 200 MMcf/d processing capacity through long-term processing services agreement | $40 | Complete |
| 30-mile natural gas gathering pipeline | |||
| Canadian Valley expansion and related infrastructure | 200 MMcf/d processing plant expansion in the STACK area and related gathering infrastructure | 160 | Complete |
| Increases capacity to more than 400 MMcf/d | |||
| 20 MBbl/d additional NGL volume | |||
| Supported by acreage dedications, long-term primarily fee-based contracts and minimum volume commitments | |||
| Demicks Lake I plant and related infrastructure | 200 MMcf/d processing plant and related infrastructure in the core of the Williston Basin | 400 | Fourth Quarter 2019 |
| Supported by acreage dedications with long-term primarily fee-based contracts | |||
| Demicks Lake II plant and related infrastructure | 200 MMcf/d processing plant and related infrastructure in the core of the Williston Basin | 410 | First Quarter 2020 |
| Supported by acreage dedications with long-term primarily fee-based contracts | |||
| Total Natural Gas Gathering and Processing | $1,010 | ||
| Project | Scope | Approximate Costs (a) | Completion Date |
| Natural Gas Liquids | (In millions) | ||
| West Texas LPG pipeline expansion | 120-mile pipeline lateral extension with capacity of 110 MBbl/d in the Permian Basin | $200 (b) | Complete |
| Supported by long-term dedicated NGL production from two planned third-party natural gas processing plants | |||
| Sterling III pipeline expansion and Arbuckle connection | 60 MBbl/d NGL pipeline expansion | 130 | Complete |
| Increases capacity to 250 MBbl/d | |||
| Includes additional NGL gathering system expansions | |||
| Supported by long-term third-party contracts | |||
| Elk Creek pipeline and related infrastructure | 900-mile NGL pipeline from the Williston Basin to the Mid-Continent region, with initial capacity of 240 MBbl/d, and related infrastructure | 1,400 | Fourth Quarter 2019 (c) |
| Anchored by long-term contracts supported primarily by minimum volume commitments | |||
| Expansion capability up to 400 MBbl/d with additional pump facilities | |||
| Arbuckle II pipeline and related infrastructure | 530-mile NGL pipeline from the STACK area to Mont Belvieu, Texas, with initial capacity up to 400 MBbl/d, and related infrastructure | 1,360 | First Quarter 2020 |
| Supported by long-term contracts | |||
| Expansion capability up to 1,000 MBbl/d | |||
| West Texas LPG pipeline expansion and Arbuckle II connection | Increasing mainline capacity by 80 MBbl/d with additional pump facilities and pipeline looping | 295 | First Quarter 2020 |
| Connecting West Texas LPG pipeline system to the previously announced Arbuckle II pipeline | |||
| Supported by long-term dedicated production from six third-party processing plants expected to produce up to 60 MBbl/d | |||
| MB-4 fractionator and related infrastructure | 125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu | 575 | First Quarter 2020 |
| Fully contracted with long-term contracts | |||
| Arbuckle II extension project and additional gathering infrastructure | Provide additional takeaway capacity in the STACK area | 240 | First Quarter 2021 |
| Allow increasing volumes on our Elk Creek pipeline access to fractionation capacity at Mont Belvieu | |||
| Arbuckle II pipeline expansion | Increasing capacity by 100 MBbl/d with additional pump facilities | 60 | First Quarter 2021 |
| Increases capacity to 500 MBbl/d | |||
| MB-5 fractionator and related infrastructure | 125 MBbl/d NGL fractionator in Mont Belvieu, Texas, and related infrastructure, which includes additional NGL storage in Mont Belvieu | 750 | First Quarter 2021 |
| Fully contracted with long-term contracts | |||
| Total Natural Gas Liquids | $5,010 | ||
| Total | $6,020 |
(a) - Excludes capitalized interest/AFUDC.
(b) - Reflects total project cost. In July 2018, we acquired the remaining 20 percent interest in WTLPG.
(c) - We expect the southern section of the pipeline to be in service as early as the third quarter 2019.
Debt Issuances - In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which is available to be drawn until May 2019. Our $1.5 Billion Term Loan Agreement matures in November 2021 and bears interest at LIBOR plus 112.5 basis points based on our current credit ratings. The agreement contains an option, which may be exercised up to two times, to extend the term of the loan, in each case, for an additional one-year term subject to approval of the banks. Our $1.5 Billion Term Loan Agreement allows prepayment of all or any portion outstanding, without penalty or premium, and contains substantially the same covenants as those contained in our $2.5 Billion Credit Agreement. As of December 31, 2018, we had borrowings totaling $550 million outstanding under our $1.5 Billion Term Loan Agreement, which were used for general corporate purposes, including repayment of existing indebtedness.
In July 2018, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $800 million, 4.55 percent senior notes due 2028 and $450 million, 5.2 percent senior notes due 2048. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $1.23 billion. The proceeds were used for general corporate purposes, which included repayment of existing indebtedness and funding capital expenditures.
Equity Issuances - In January 2018, we completed an underwritten public offering of 21.9 million shares of our common stock at a public offering price of $54.50 per share, generating net proceeds of $1.2 billion. We used the net proceeds from this offering to fund capital expenditures and for general corporate purposes, which included repaying a portion of our outstanding indebtedness.
Dividends - During 2018, we paid dividends totaling $3.245 per share, an increase of 19 percent from the $2.72 per share paid in 2017. In February 2019, we paid a quarterly dividend of $0.86 per share ($3.44 per share on an annualized basis), an increase of 12 percent compared with the same quarter in the prior year. In 2018, 83 percent of our dividend payments to investors were a return of capital. Our dividend growth is due to the increase in cash flows resulting from the continued growth of our operations.
Tax Cuts and Jobs Act - In December 2017 the Tax Cuts and Jobs Act made extensive changes to the U.S. tax laws, including provisions that reduce the highest U.S. corporate tax rate to 21 percent from 35 percent, increase expensing for capital investment, and limit the interest deduction and use of net operating losses to offset future taxable income. Because tax expense can be, but is not always, a component of the rates charged by interstate natural gas pipelines, FERC issued a final rule requiring each interstate natural gas pipeline to submit a filing addressing any impact of the Tax Cuts and Jobs Act on its FERC-regulated rates. The applicable filings were completed for each of our wholly owned and equity investment interstate natural gas pipelines, and we expect no material impact to our results of operations.
Revenue Recognition - We adopted Topic 606 on January 1, 2018, using the modified retrospective method. Results for reporting periods beginning after January 1, 2018, are presented under Topic 606, while prior periods are not adjusted and continue to be reported under the accounting standards in effect for those periods. The primary impact to our financial results is a classification change between line items in our Consolidated Income Statement, with an immaterial impact on net income. Based on the new guidance, we determined that certain Natural Gas Gathering and Processing segment POP with fee contracts and Natural Gas Liquids segment exchange services contracts that include the purchase of commodities are supplier contracts. Therefore, contractual fees in these identified contracts are now recorded as a reduction of the commodity purchase price in cost of sales and fuel rather than as services revenue. To the extent we hold inventory related to these purchases, the related fees previously recorded in services revenue will not be recognized until the inventory is sold. The adoption of Topic 606 did not materially impact our reported operating income, net income or adjusted EBITDA.
FINANCIAL RESULTS AND OPERATING INFORMATION
Consolidated Operations
Selected Financial Results - The following table sets forth certain selected consolidated financial results for the periods indicated:
| Variances | Variances | |||||||||||||||||||||||||
| Years Ended December 31, | 2018 vs. 2017 | 2017 vs. 2016 | ||||||||||||||||||||||||
| Financial Results | 2018 | 2017 | 2016 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||||
| Revenues | ||||||||||||||||||||||||||
| Commodity sales | $ | 11,395.6 | $ | 9,862.7 | $ | 6,858.5 | $ | 1,532.9 | 16 | % | $ | 3,004.2 | 44 | % | ||||||||||||
| Services | 1,197.6 | 2,311.2 | 2,062.4 | (1,113.6 | ) | (48 | )% | 248.8 | 12 | % | ||||||||||||||||
| Total revenues | 12,593.2 | 12,173.9 | 8,920.9 | 419.3 | 3 | % | 3,253.0 | 36 | % | |||||||||||||||||
| Cost of sales and fuel (exclusive of items shown separately below) | 9,422.7 | 9,538.0 | 6,496.1 | (115.3 | ) | (1 | )% | 3,041.9 | 47 | % | ||||||||||||||||
| Operating costs | 907.0 | 822.7 | 747.0 | 84.3 | 10 | % | 75.7 | 10 | % | |||||||||||||||||
| Depreciation and amortization | 428.6 | 406.3 | 391.6 | 22.3 | 5 | % | 14.7 | 4 | % | |||||||||||||||||
| Impairment of long-lived assets | — | 16.0 | — | (16.0 | ) | (100 | )% | 16.0 | * | |||||||||||||||||
| Gain on sale of assets | (0.6 | ) | (0.9 | ) | (9.6 | ) | (0.3 | ) | (33 | )% | (8.7 | ) | (91 | )% | ||||||||||||
| Operating income | $ | 1,835.5 | $ | 1,391.8 | $ | 1,295.8 | $ | 443.7 | 32 | % | $ | 96.0 | 7 | % | ||||||||||||
| Equity in net earnings from investments | $ | 158.4 | $ | 159.3 | $ | 139.7 | $ | (0.9 | ) | (1 | )% | $ | 19.6 | 14 | % | |||||||||||
| Impairment of equity investments | $ | — | $ | (4.3 | ) | $ | — | $ | (4.3 | ) | (100 | )% | $ | 4.3 | * | |||||||||||
| Interest expense, net of capitalized interest | $ | (469.6 | ) | $ | (485.7 | ) | $ | (469.7 | ) | $ | (16.1 | ) | (3 | )% | $ | 16.0 | 3 | % | ||||||||
| Net income | $ | 1,155.0 | $ | 593.5 | $ | 743.5 | $ | 561.5 | 95 | % | $ | (150.0 | ) | (20 | )% | |||||||||||
| Adjusted EBITDA | $ | 2,447.5 | $ | 1,986.9 | $ | 1,849.9 | $ | 460.6 | 23 | % | $ | 137.0 | 7 | % | ||||||||||||
| Capital expenditures | $ | 2,141.5 | $ | 512.4 | $ | 624.6 | $ | 1,629.1 | * | $ | (112.2 | ) | (18 | )% |
- Percentage change is greater than 100 percent or is not meaningful.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
Changes in commodity prices, sales volumes and the impact of the adoption of Topic 606, as described in Note O of the Notes to Consolidated Financial Statements in this Annual Report, affect both revenues and cost of sales and fuel in our Consolidated Statements of Income, and, therefore, the impact is largely offset between these line items.
2018 vs. 2017 - Operating income increased primarily as a result of the following:
| • | an increase of $342.9 million due to Natural gas and NGL volume growth, primarily in the Williston Basin and STACK and SCOOP areas in our Natural Gas Gathering and Processing and Natural Gas Liquids segments; |
| • | an increase of $150.4 million due to higher optimization and marketing earnings primarily from wider location price differentials in our Natural Gas Liquids segment; |
| • | an increase of $36.4 million from higher transportation services due primarily to increased interruptible volumes and firm transportation capacity contracted in our Natural Gas Pipelines segment; and |
| • | an increase of $16.0 million resulting from the impact of noncash impairment charges in 2017 related to nonstrategic long-lived assets in our Natural Gas Gathering and Processing segment; offset partially by |
| • | an increase in operating costs of $84.3 million due primarily to higher employee-related costs associated with labor and benefits, higher materials, supplies, outside services, noncash compensation and spending on routine maintenance projects, offset partially by the $30.0 million impact of the Merger Transaction included in 2017 operating costs; and |
| • | an increase in depreciation expense of $22.3 million due to capital projects placed in service. |
Net income increased due to the items discussed above, a one-time noncash charge through income tax expense of $141.3 million in 2017, related to revaluation of our deferred tax balances and a valuation allowance on certain state net operating loss and tax credit carryforwards resulting from the enactment of the Tax Cuts and Jobs Act and $20.0 million of noncash expenses related to our Series E Preferred Stock contribution to the Foundation made in 2017.
Capital expenditures increased due primarily to spending on our announced capital-growth projects.
2017 vs. 2016 - Operating income increased primarily as a result of the following:
| • | an increase of $147.5 million due to natural gas and NGL volume growth in the Williston Basin and STACK and SCOOP areas in our Natural Gas Gathering and Processing and Natural Gas Liquids segments; |
| • | an increase of $44.0 million due to restructured contracts resulting in higher fee revenues from increased average fee rates and a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts in our Natural Gas Gathering and Processing segment; |
| • | an increase of $26.9 from higher transportation services due to higher firm transportation capacity contracted in our Natural Gas Pipelines segment; and |
| • | an increase of $13.5 due to higher optimization and marketing earnings due to higher optimization volumes and wider location price differentials in our Natural Gas Liquids segment; offset partially by |
| • | an increase in operating costs of $45.7 million due to higher labor and employee-related costs associated with benefit plans, routine maintenance projects and higher ad valorem taxes; |
| • | an increase in operating costs of $30.0 million due to Merger Transaction costs in 2017; |
| • | a decrease of $16.0 million due to noncash impairment charges related to nonstrategic long-lived assets in our Natural Gas Gathering and Processing segment; and |
| • | a decrease of $11.9 million due to lower net realized natural gas prices and condensate prices, net of hedges in our Natural Gas Gathering and Processing segment. |
Net income was further impacted by a one-time noncash charge through income tax expense of $141.3 million, related to revaluation of our deferred tax balances and a valuation allowance on certain state net operating loss and tax credit carryforwards resulting from the enactment of the Tax Cuts and Jobs Act and $20.0 million of noncash expenses related to our Series E Preferred Stock contribution to the Foundation.
Equity in net earnings from investments increased due primarily to higher firm transportation revenues related to Roadrunner’s Phase II capacity, which was placed in service in October 2016. Roadrunner is fully subscribed under long-term firm demand charge contracts.
Capital expenditures decreased due primarily to growth projects placed in service in 2016 in our Natural Gas Gathering and Processing segment.
Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.
Natural Gas Gathering and Processing
Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas, including the Bakken Shale and Three Forks formations in the Williston Basin and the STACK and SCOOP areas, that we expect will enable us to meet the needs of crude oil and natural gas producers in those areas. See “Growth Projects” in the “Recent Developments” section for discussion of our announced capital-growth projects.
For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.
Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Gathering and Processing segment for the periods indicated:
| Variances | Variances | |||||||||||||||||||||||||
| Years Ended December 31, | 2018 vs. 2017 | 2017 vs. 2016 | ||||||||||||||||||||||||
| Financial Results | 2018 | 2017 | 2016 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||||
| NGL sales | $ | 1,567.2 | $ | 1,208.0 | $ | 586.0 | $ | 359.2 | 30 | % | $ | 622.0 | * | |||||||||||||
| Condensate sales | 208.8 | 103.2 | 58.3 | 105.6 | * | 44.9 | 77 | % | ||||||||||||||||||
| Residue natural gas sales | 1,084.2 | 856.3 | 690.6 | 227.9 | 27 | % | 165.7 | 24 | % | |||||||||||||||||
| Gathering, compression, dehydration and processing fees and other revenue | 174.4 | 859.1 | 716.7 | (684.7 | ) | (80 | )% | 142.4 | 20 | % | ||||||||||||||||
| Cost of sales and fuel (exclusive of depreciation and operating costs) | (2,041.4 | ) | (2,216.4 | ) | (1,331.5 | ) | (175.0 | ) | (8 | )% | 884.9 | 66 | % | |||||||||||||
| Operating costs, excluding noncash compensation adjustments | (357.7 | ) | (302.6 | ) | (283.4 | ) | 55.1 | 18 | % | 19.2 | 7 | % | ||||||||||||||
| Equity in net earnings from investments, excluding noncash impairment charges | 0.4 | 12.1 | 10.7 | (11.7 | ) | (97 | )% | 1.4 | 13 | % | ||||||||||||||||
| Other | (4.3 | ) | (1.2 | ) | (0.6 | ) | (3.1 | ) | * | (0.6 | ) | (100 | )% | |||||||||||||
| Adjusted EBITDA | $ | 631.6 | $ | 518.5 | $ | 446.8 | $ | 113.1 | 22 | % | $ | 71.7 | 16 | % | ||||||||||||
| Impairment of equity investments | $ | — | $ | (4.3 | ) | $ | — | $ | (4.3 | ) | (100 | )% | $ | 4.3 | * | |||||||||||
| Capital expenditures | $ | 694.6 | $ | 284.2 | $ | 410.5 | $ | 410.4 | * | $ | (126.3 | ) | (31 | )% |
- Percentage change is greater than 100 percent or is not meaningful.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
Changes in commodity prices and sales volumes and the impact of the adoption of Topic 606, as described in Note O of the Notes to Consolidated Financial Statements in this Annual Report, affect both revenue and cost of sales and fuel, and, therefore, the impact is largely offset between these line items.
2018 vs. 2017 - Adjusted EBITDA increased $113.1 million, primarily as a result of the following:
| • | an increase of $159.2 million due primarily to natural gas volume growth in the Williston Basin and the STACK and SCOOP areas, offset partially by natural production declines; and |
| • | an increase of $22.3 million due primarily to higher realized NGL and condensate prices, net of hedges, offset partially by lower realized natural gas prices, net of hedges; offset partially by |
| • | an increase of $55.1 million in operating costs due primarily to increased materials and supplies and outside services related to the growth of our operations and higher employee-related costs associated with labor and benefits; and |
| • | a decrease of $11.7 million due primarily to lower equity in net earnings from investments due to a decrease in supply volumes in the coal-bed methane area of the Powder River Basin. |
Capital expenditures increased due to our announced capital-growth projects and increased well connections.
2017 vs. 2016 - Adjusted EBITDA increased $71.7 million, primarily as a result of the following:
| • | an increase of $66.0 million due primarily to natural gas volume growth in the Williston Basin and the STACK and SCOOP areas, offset partially by natural production declines and the impact of severe winter weather in the first quarter 2017; and |
| • | an increase of $44.0 million due primarily to restructured contracts resulting in higher fee revenues from increased average fee rates, offset partially by a lower percentage of proceeds retained from the sale of commodities under our POP with fee contracts; offset partially by |
| • | an increase of $19.2 million in operating costs due primarily to higher employee-related costs associated with labor and benefits and the growth of our operations; |
| • | a decrease of $11.9 million due primarily to lower realized natural gas and condensate prices, net of hedges; and |
| • | a decrease of $8.0 million due to contract settlements in 2016. |
Capital expenditures decreased due to growth projects placed in service in 2016.
| Years Ended December 31, | ||||||||||||
| Operating Information (a) | 2018 | 2017 | 2016 | |||||||||
| Natural gas gathered (BBtu/d) | 2,546 | 2,211 | 2,034 | |||||||||
| Natural gas processed (BBtu/d) (b) | 2,382 | 2,056 | 1,882 | |||||||||
| NGL sales (MBbl/d) | 198 | 187 | 156 | |||||||||
| Residue natural gas sales (BBtu/d) | 1,088 | 896 | 865 | |||||||||
| Average fee rate ($MMBtu) | $ | 0.90 | $ | 0.86 | $ | 0.76 |
(a) - Includes volumes for consolidated entities only.
(b) - Includes volumes at company-owned and third-party facilities.
Natural gas gathered, natural gas processed, NGL sales and residue natural gas sales volumes increased in 2018, compared with 2017, due primarily to the following:
| • | producers focusing their drilling and completion in the most productive areas with favorable economics where we have significant gathering and processing assets; and |
| • | continued producer improvements in production due to enhanced completion techniques; offset partially by |
| • | natural production declines. |
Natural gas gathered, natural gas processed, NGL sales and residue natural gas sales increased in 2017, compared with 2016, due to the completion of growth projects and new supply in the Williston Basin and the STACK and SCOOP areas, offset partially by natural production declines on existing wells and the impact of severe winter weather in the first quarter 2017.
The quantity and composition of NGLs and natural gas are expected to continue to change with anticipated production increases across our supply basins, new processing plants placed in service and increased ethane recovery.
Commodity Price Risk - See discussion regarding our commodity price risk under “Commodity Price Risk” in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.
Impairment Charges - In 2017, following a review of nonstrategic assets for potential divestiture, we recorded $16.0 million of noncash impairment charges related to certain nonstrategic gathering and processing assets located in North Dakota and $4.3 million of noncash impairment charges related to a nonstrategic equity investment located in Oklahoma.
Natural Gas Liquids
Growth Projects - Our growth strategy in our Natural Gas Liquids segment is focused around the crude oil and NGL-rich natural gas drilling activity in shale and other nonconventional resource areas from the Rocky Mountain region through the Mid-Continent region and the Permian Basin. Crude oil, natural gas and NGL production from this activity; higher petrochemical industry demand for NGL products; and increased exports have resulted in our making additional capital investments to expand our infrastructure to bring these commodities from supply basins to market.
Our Natural Gas Liquids segment invests in NGL-related projects to transport, fractionate, store and deliver to the market NGL supply from shale and other resource development areas across our asset base and alleviate expected infrastructure constraints between the Mid-Continent and Gulf Coast market centers and to meet increasing petrochemical industry and NGL export demand in the Gulf Coast. See “Growth Projects” in the “Recent Developments” section for discussion of our announced capital-growth projects.
We continue to evaluate opportunities to increase the capacity of our gathering, fractionation, storage and distribution assets or construct new assets to connect supply growth from the Williston and Powder River Basins, Mid-Continent region and Permian Basin with end-use markets.
In 2018, we connected five third-party natural gas processing plants to our NGL system in the STACK and SCOOP areas, one in the Rocky Mountain region and one in the Permian Basin. Two natural gas processing plants, one third-party and one in our Natural Gas Gathering and Processing segment, also were expanded in the STACK and SCOOP areas of the Mid-Continent region.
For a discussion of our capital expenditure financing, see “Capital Expenditures” in the “Liquidity and Capital Resources” section.
Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Liquids segment for the periods indicated:
| Variances | Variances | |||||||||||||||||||||||||
| Years Ended December 31, | 2018 vs. 2017 | 2017 vs. 2016 | ||||||||||||||||||||||||
| Financial Results | 2018 | 2017 | 2016 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||||
| NGL and condensate sales | $ | 10,319.9 | $ | 8,998.9 | $ | 6,152.5 | $ | 1,321.0 | 15 | % | $ | 2,846.4 | 46 | % | ||||||||||||
| Exchange service revenues and other | 415.7 | 1,430.3 | 1,327.5 | (1,014.6 | ) | (71 | )% | 102.8 | 8 | % | ||||||||||||||||
| Transportation and storage revenues | 199.0 | 197.0 | 195.7 | 2.0 | 1 | % | 1.3 | 1 | % | |||||||||||||||||
| Cost of sales and fuel (exclusive of depreciation and operating costs) | (9,176.8 | ) | (9,176.5 | ) | (6,321.4 | ) | 0.3 | — | % | 2,855.1 | 45 | % | ||||||||||||||
| Operating costs, excluding noncash compensation adjustments | (378.3 | ) | (351.3 | ) | (326.1 | ) | 27.0 | 8 | % | 25.2 | 8 | % | ||||||||||||||
| Equity in net earnings from investments | 67.1 | 59.9 | 54.5 | 7.2 | 12 | % | 5.4 | 10 | % | |||||||||||||||||
| Other | (6.0 | ) | (3.4 | ) | (3.1 | ) | (2.6 | ) | (76 | )% | (0.3 | ) | (10 | )% | ||||||||||||
| Adjusted EBITDA | $ | 1,440.6 | $ | 1,154.9 | $ | 1,079.6 | $ | 285.7 | 25 | % | $ | 75.3 | 7 | % | ||||||||||||
| Capital expenditures | $ | 1,306.3 | $ | 114.3 | $ | 105.9 | $ | 1,192.0 | * | $ | 8.4 | 8 | % |
- Percentage change is greater than 100 percent.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
Changes in commodity prices and sales volumes and the impact of the adoption of Topic 606, as described in Note O of the Notes to Consolidated Financial Statements in this Annual Report, affect both revenues and cost of sales and fuel, and, therefore, the impact is largely offset between these line items.
2018 vs. 2017 - Adjusted EBITDA increased $285.7 million, primarily as a result of the following:
| • | an increase of $164.6 million in exchange services due to $183.7 million in higher volumes primarily in the STACK and SCOOP areas and the Williston Basin and $52.3 million in higher average fee rates in the Mid-Continent region and Permian Basin, offset partially by $56.6 million in higher third-party fractionation and rail transportation costs and $19.8 million in higher power costs due to increased volumes; |
| • | an increase of $150.4 million in optimization and marketing due primarily to wider location price differentials, which includes the $15.0 million unfavorable impact of higher NGL products in inventory at the end of the year due to facility maintenance in the fourth quarter 2018. We expect the earnings benefit on physical-forward sales of this inventory in the first quarter 2019; and |
| • | an increase of $7.2 million in equity in net earnings from investments due primarily to higher volumes delivered to the Overland Pass pipeline; offset partially by |
| • | an increase of $27.0 million in operating costs due primarily to higher employee-related costs associated with labor and benefits, spending on routine maintenance projects and higher ad valorem taxes, offset partially by the impact of Hurricane Harvey on operating costs in 2017; and |
| • | a decrease of $6.8 million in transportation and storage services due primarily to lower storage capacity contracted with third parties in the Mid-Continent region. |
Capital expenditures increased due primarily to spending on our announced capital-growth projects.
2017 vs. 2016 - Adjusted EBITDA increased $75.3 million, primarily as a result of the following:
| • | an increase of $81.5 million in exchange services due primarily to higher volumes in the Williston Basin, the STACK and SCOOP areas and the Powder River Basin and ethane recovery; offset partially by lower volumes in the Granite Wash and Barnett Shale and reduced volumes related to Hurricane Harvey; |
| • | an increase of $13.5 million in our optimization and marketing activities due primarily to higher optimization volumes and wider location price differentials; and |
| • | an increase of $5.4 million in equity in net earnings from investments due primarily to higher volumes delivered to the Overland Pass pipeline from our Bakken NGL pipeline and higher volumes and increased ethane recovery from plants connected to the Overland Pass pipeline; offset partially by |
| • | an increase of $25.2 million in operating costs due primarily to routine maintenance projects, higher ad valorem taxes, higher employee-related costs associated with labor and benefits, and additional operating costs related to Hurricane Harvey. |
Capital expenditures increased due primarily to increased routine growth and maintenance projects.
| Years Ended December 31, | ||||||||||||
| Operating Information | 2018 | 2017 | 2016 | |||||||||
| Raw feed throughput (MBbl/d) (a) | 1,010 | 895 | 836 | |||||||||
| NGLs transported - gathering lines (MBbl/d) (b) | 912 | 812 | 770 | |||||||||
| NGLs fractionated (MBbl/d) (c) | 715 | 621 | 586 | |||||||||
| Average Conway-to-Mont Belvieu OPIS price differential - ethane in ethane/propane mix ($/gallon) | $ | 0.15 | $ | 0.05 | $ | 0.03 |
(a) - Represents physical raw feed volumes on which we charge a fee for transportation and/or fractionation services.
(b) - Includes volumes for consolidated entities only.
(c) - Includes volumes at company-owned and third-party facilities.
2018 vs. 2017 - Volumes increased primarily from the STACK and SCOOP areas and Williston Basin. While overall volumes, including ethane, increased, a portion of the contractual fees associated with those volumes gathered and fractionated was previously being earned under contracts with minimum volume obligations.
2017 vs. 2016 - Volumes increased primarily from the STACK and SCOOP areas and Williston Basin resulting from plant connections, increased supply and increased ethane recovery, which was offset partially by decreased volumes from the Barnett Shale and Granite Wash. Volumes also increased from the Permian Basin. While overall volumes and ethane recovery increased, a portion of the fees associated with those volumes gathered and fractionated was previously being earned under contracts with minimum volume obligations.
Natural Gas Pipelines
Growth Projects - Our natural gas pipelines primarily serve end users, such as natural gas distribution and electric-generation companies, that require natural gas to operate their businesses regardless of location price differentials. The development of shale and other resource areas has continued to increase available natural gas supply, and we expect producers and natural gas processors to require incremental transportation services in the future as additional supply is developed.
We are expanding our natural gas pipeline infrastructure in Oklahoma and the Permian Basin. The projects include an eastbound expansion of our ONEOK Gas Transportation system by 150 MMcf/d from the STACK and SCOOP areas to an interstate pipeline delivery point in eastern Oklahoma, a westbound expansion of our ONEOK Gas Transportation system by 100 MMcf/d from the STACK area to multiple interstate pipeline delivery points in western Oklahoma, and an expansion of our WesTex Transmission system by 300 MMcf/d from the Permian Basin to interstate pipeline delivery points in the Texas Panhandle. Additionally, we completed an expansion project on our Roadrunner joint venture to make the pipeline bidirectional, which will result in approximately 1.0 Bcf/d of eastbound transportation capacity from the Delaware Basin to the Waha area.
See “Capital Expenditures” in “Liquidity and Capital Resources” for additional detail of our projected capital expenditures.
Selected Financial Results and Operating Information - The following tables set forth certain selected financial results and operating information for our Natural Gas Pipelines segment for the periods indicated:
| Variances | Variances | |||||||||||||||||||||||||
| Years Ended December 31, | 2018 vs. 2017 | 2017 vs. 2016 | ||||||||||||||||||||||||
| Financial Results | 2018 | 2017 | 2016 | Increase (Decrease) | Increase (Decrease) | |||||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||||
| Transportation revenues | $ | 333.7 | $ | 323.7 | $ | 288.5 | $ | 10.0 | 3 | % | $ | 35.2 | 12 | % | ||||||||||||
| Storage revenues | 60.3 | 59.2 | 60.0 | 1.1 | 2 | % | (0.8 | ) | (1 | )% | ||||||||||||||||
| Natural gas sales and other revenues | 37.7 | 37.0 | 30.9 | 0.7 | 2 | % | 6.1 | 20 | % | |||||||||||||||||
| Cost of sales and fuel (exclusive of depreciation and operating costs) | (16.0 | ) | (43.4 | ) | (30.6 | ) | (27.4 | ) | (63 | )% | 12.8 | 42 | % | |||||||||||||
| Operating costs, excluding noncash compensation adjustments | (139.2 | ) | (123.1 | ) | (114.7 | ) | 16.1 | 13 | % | 8.4 | 7 | % | ||||||||||||||
| Equity in net earnings from investments | 90.8 | 87.3 | 74.4 | 3.5 | 4 | % | 12.9 | 17 | % | |||||||||||||||||
| Other | (1.0 | ) | (0.9 | ) | 4.6 | (0.1 | ) | (11 | )% | (5.5 | ) | * | ||||||||||||||
| Adjusted EBITDA | $ | 366.3 | $ | 339.8 | $ | 313.1 | $ | 26.5 | 8 | % | $ | 26.7 | 9 | % | ||||||||||||
| Capital expenditures | $ | 119.2 | $ | 95.6 | $ | 96.3 | $ | 23.6 | 25 | % | $ | (0.7 | ) | (1 | )% |
- Percentage change is greater than 100 percent.
See reconciliation of net income to adjusted EBITDA in the “Adjusted EBITDA” section.
As a result of the adoption of Topic 606, we record retained fuel charges as a reduction to cost of sales and fuel that would have been recorded as revenue prior to adoption and therefore the impact is offset between these line items.
2018 vs. 2017 - Adjusted EBITDA increased $26.5 million primarily as a result of the following:
| • | an increase of $36.4 million from transportation services due primarily to increased interruptible volumes and firm transportation capacity contracted; and |
| • | an increase of $7.1 million in natural gas storage services due primarily to higher rates and capacity contracted; offset partially by |
| • | an increase of $16.1 million in operating costs due primarily to employee-related costs associated with labor and benefits and timing of routine maintenance projects. |
Capital expenditures increased due primarily to timing of maintenance projects and our announced capital-growth projects.
2017 vs. 2016 - Adjusted EBITDA increased $26.7 million primarily as a result of the following:
| • | an increase of $26.9 million from higher transportation services due primarily to increased firm transportation contracted capacity; and |
| • | an increase of $12.9 million in equity in net earnings from investments due primarily to higher firm transportation revenues on Roadrunner; offset partially by |
| • | an increase of $8.4 million in operating costs due primarily to routine maintenance projects and higher employee-related costs associated with labor and benefits; and |
| • | a decrease of $6.3 million due primarily to gains on sales of excess natural gas in storage in 2016. |
| Years Ended December 31, | |||||||||
| Operating Information (a) | 2018 | 2017 | 2016 | ||||||
| Natural gas transportation capacity contracted (MDth/d) | 6,846 | 6,611 | 6,345 | ||||||
| Transportation capacity subscribed | 96 | % | 94 | % | 92 | % |
(a) - Includes volumes for consolidated entities only.
Roadrunner, in which we have a 50 percent ownership interest, has contracted all of its westbound capacity through 2041. We made contributions of $65 million to Roadrunner in 2016. During the years ended December 31, 2018 and 2017, our contributions to Roadrunner were not material.
Northern Border Pipeline, in which we have a 50 percent ownership interest, has contracted substantially all of its long-haul transportation capacity through the fourth quarter 2020. We made contributions of $83 million to Northern Border Pipeline in 2017. During the years ended December 31, 2018 and 2016, we made no contributions to Northern Border Pipeline.
Northern Border Pipeline entered into a settlement with shippers that was approved by the FERC in February 2018. The settlement provides for tiered rate reductions beginning January 1, 2018, that will reduce rates 12.5 percent by January 2020, compared with previous rates, and requires new rates to be established by January 2024. We do not expect the impact of lower tariff rates on Northern Border Pipeline’s equity earnings and cash distributions to be material to us.
In compliance with the FERC final rule, Northern Border Pipeline completed the required filing related to the Tax Cuts and Jobs Act, and we do not expect the impact on tariff rates to be material to us.
In March 2018, the FERC initiated a review of Midwestern Gas Transmission Company’s rates pursuant to Section 5 of the Natural Gas Act. The parties reached agreement on the terms of a settlement that provides for an approximate 7 percent reduction in transportation rates. The revised rates became effective September 1, 2018, and the settlement agreement was approved by the FERC in January 2019. We do not expect the impact of the revised rates to be material to us.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP measure of our financial performance. Adjusted EBITDA is defined as net income adjusted for interest expense, depreciation and amortization, noncash impairment charges, income taxes, allowance for equity funds used during construction, noncash compensation and other noncash items. Prior periods have been adjusted to conform to current presentation. We believe this non-GAAP financial measure is useful to investors because it and similar measures are used by many companies in our industry as a measurement of financial performance and is commonly employed by financial analysts and others to evaluate our financial performance and to compare financial performance among companies in our industry. Adjusted EBITDA should not be considered an alternative to net income, earnings per unit or any other measure of financial performance presented in accordance with GAAP. Additionally, this calculation may not be comparable with similarly titled measures of other companies.
The following table sets forth a reconciliation of net income, the nearest comparable GAAP financial performance measure, to adjusted EBITDA for the periods indicated:
| Years Ended December 31, | ||||||||||||
| (Unaudited) | 2018 | 2017 | 2016 | |||||||||
| Reconciliation of net income to adjusted EBITDA | (Thousands of dollars) | |||||||||||
| Net income | $ | 1,155,032 | $ | 593,519 | $ | 743,499 | ||||||
| Add: | ||||||||||||
| Interest expense, net of capitalized interest | 469,620 | 485,658 | 469,651 | |||||||||
| Depreciation and amortization | 428,557 | 406,335 | 391,585 | |||||||||
| Income taxes | 362,903 | 447,282 | 212,406 | |||||||||
| Impairment charges | — | 20,240 | — | |||||||||
| Noncash compensation expense | 37,954 | 13,421 | 31,981 | |||||||||
| Other noncash items and equity AFUDC (a) | (6,545 | ) | 20,398 | 796 | ||||||||
| Adjusted EBITDA | $ | 2,447,521 | $ | 1,986,853 | $ | 1,849,918 | ||||||
| Reconciliation of segment adjusted EBITDA to adjusted EBITDA | ||||||||||||
| Segment adjusted EBITDA: | ||||||||||||
| Natural Gas Gathering and Processing | $ | 631,607 | $ | 518,472 | $ | 446,778 | ||||||
| Natural Gas Liquids | 1,440,605 | 1,154,939 | 1,079,619 | |||||||||
| Natural Gas Pipelines | 366,251 | 339,818 | 313,137 | |||||||||
| Other (b) | 9,058 | (26,376 | ) | 10,384 | ||||||||
| Adjusted EBITDA | $ | 2,447,521 | $ | 1,986,853 | $ | 1,849,918 |
(a) - Year ended December 31, 2017, includes our April 2017 contribution to the Foundation of 20,000 shares of Series E Preferred Stock, with an aggregate value of $20.0 million.
(b) - Year ended December 31, 2017, includes Merger Transaction costs of $30.0 million.
CONTINGENCIES
See Note N of the Notes to Consolidated Financial Statements in this Annual Report for a discussion of regulatory matters and developments concerning the Gas Index Pricing Litigation.
Other Legal Proceedings - We are a party to various litigation matters and claims that have arisen in the normal course of our operations. While the results of these litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
LIQUIDITY AND CAPITAL RESOURCES
General - Our primary sources of cash inflows are operating cash flows, proceeds from our commercial paper program and our $2.5 Billion Credit Agreement, debt issuances and the issuance of common stock for our liquidity and capital resources requirements. In addition, we expect cash outflows related to i) capital expenditures, ii) interest and repayment of debt maturities and iii) dividends paid to shareholders. We expect our cash outflows related to capital expenditures and dividends paid to increase due to our announced capital-growth projects and higher anticipated dividends per share, subject to board of directors’ approval.
We expect our sources of cash inflow to provide sufficient resources to finance our operations, capital expenditures and quarterly cash dividends, including expected future dividend increases. Our $2.5 Billion Credit Agreement and the remaining $950 million available to be drawn on our $1.5 Billion Term Loan Agreement provide significant liquidity to fund capital expenditures and repay existing indebtedness. We may access the capital markets to issue debt or equity securities as we consider prudent to provide additional liquidity to refinance existing debt, improve credit metrics or to fund capital expenditures. Although we expect to continue to fund capital projects primarily with cash from operations, short-term borrowings and long-term debt, we continue to have access to $550 million available through our “at-the-market” equity program. With $1.6 billion of equity issued in 2017 and January 2018, we have satisfied our expected equity financing needs for our announced capital-growth projects.
We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt, interest-rate swaps and treasury lock contracts. For additional information on our interest-rate swaps, see Note C of the Notes to Consolidated Financial Statements in this Annual Report.
Cash Management - We use a centralized cash management program that concentrates the cash assets of our operating subsidiaries in joint accounts for the purposes of providing financial flexibility and lowering the cost of borrowing, transaction costs and bank fees. Our centralized cash management program provides that funds in excess of the daily needs of our operating subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within our consolidated group. Our operating subsidiaries participate in this program to the extent they are permitted pursuant to FERC regulations or their operating agreements. Under the cash management program, depending on whether a participating subsidiary has short-term cash surpluses or cash requirements, we provide cash to the subsidiary or the subsidiary provides cash to us.
Short-term Liquidity - Our principal sources of short-term liquidity consist of cash generated from operating activities, distributions received from our equity-method investments, proceeds from our commercial paper program, our $2.5 Billion Credit Agreement and the remaining $950 million available to be drawn on our $1.5 Billion Term Loan Agreement. As of December 31, 2018, we were in compliance with all covenants of the $2.5 Billion Credit Agreement and the $1.5 Billion Term Loan Agreement.
At December 31, 2018, we had $12.0 million of cash and cash equivalents and $2.5 billion of borrowing capacity under the $2.5 Billion Credit Agreement.
We had working capital (defined as current assets less current liabilities) deficits of $709.8 million and $902.9 million as of December 31, 2018, and December 31, 2017, respectively. Although working capital is influenced by several factors, including, among other things: (i) the timing of (a) scheduled debt payments, (b) the collection and payment of accounts receivable and payable, and (c) equity and debt issuances, and (ii) the volume and cost of inventory and commodity imbalances, our working capital deficit at December 31, 2018, was driven primarily by current maturities of long-term debt, with December 31, 2017, also impacted by short-term borrowings. We may have working capital deficits in future periods as we continue to finance our capital-growth projects and repay long-term debt, often initially with short-term borrowings. We do not expect this working capital deficit to have an adverse impact to our cash flows or operations.
For additional information on our $2.5 Billion Credit Agreement and commercial paper program, see Note F of the Notes to Consolidated Financial Statements in this Annual Report.
Long-term Financing - In addition to our principal sources of short-term liquidity discussed above, we expect to fund our longer-term financing requirements by issuing long-term notes. Other options to obtain financing include, but are not limited to, issuing common stock, loans from financial institutions, issuance of convertible debt securities or preferred equity securities, asset securitization and the sale and lease-back of facilities.
Debt Issuances and Upcoming Maturities - In November 2018, we entered into the $1.5 Billion Term Loan Agreement with a syndicate of banks, which is available to be drawn until May 2019. The $1.5 Billion Term Loan Agreement matures in November 2021 and bears interest at LIBOR plus 112.5 basis points based on our current credit ratings. The agreement contains an option, which may be exercised up to two times, to extend the term of the loan, in each case, for an additional one-year term subject to approval of the banks. The $1.5 Billion Term Loan Agreement allows prepayment of all or any portion outstanding, without penalty or premium, and contains substantially the same covenants as those contained in the $2.5 Billion Credit Agreement. As of December 31, 2018, we had borrowings totaling $550 million outstanding under the $1.5 Billion Term Loan Agreement, which were used for general corporate purposes, including repayment of existing indebtedness.
In July 2018, we completed an underwritten public offering of $1.25 billion senior unsecured notes consisting of $800 million, 4.55 percent senior notes due 2028, and $450 million, 5.2 percent senior notes due 2048. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were $1.23 billion. The proceeds were used for general corporate purposes, which included repayment of existing indebtedness and funding capital expenditures.
We expect to repay the $500 million, 8.625 percent senior notes due in March 2019, with a combination of cash on hand and/or short- or long-term borrowings.
Debt Repayments - In August 2018, we repaid the $425 million, 3.2 percent senior notes due September 2018 with cash on hand. In January 2018 we repaid the remaining $500 million balance outstanding on the ONEOK Partners Term Loan Agreement due 2019 with a combination of cash on hand and short-term borrowings.
For additional information on our long-term debt, see Note F of the Notes to Consolidated Financial Statements in this Annual Report.
Equity Issuances - In January 2018, we completed an underwritten public offering of 21.9 million shares of our common stock at a public offering price of $54.50 per share, generating net proceeds of $1.2 billion. We used the net proceeds from this offering to fund capital expenditures and for general corporate purposes, which included repaying a portion of our outstanding indebtedness.
In July 2017, we established an “at-the-market” equity program for the offer and sale from time to time of our common stock up to an aggregate amount of $1 billion. The program allows us to offer and sell our common stock at prices we deem appropriate through a sales agent. Sales of our common stock may be made by means of ordinary brokers’ transactions on the NYSE, in block transactions, or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common stock under the program. During the year ended December 31, 2017, we sold 8.4 million shares of common stock through our “at-the-market” equity program that resulted in net proceeds of $448.3 million. During the year ended December 31, 2018, no shares were sold through our “at-the-market” equity program.
Capital Expenditures - We classify expenditures that are expected to generate additional revenue, return on investment or significant operating efficiencies as capital-growth expenditures. Maintenance capital expenditures are those capital expenditures required to maintain our existing assets and operations and do not generate additional revenues. Maintenance capital expenditures are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives. Our capital expenditures are financed typically through operating cash flows, short- and long-term debt and the issuance of equity.
The following table sets forth our growth and maintenance capital expenditures, excluding AFUDC and capitalized interest, for the periods indicated:
| Capital Expenditures | 2018 | 2017 | 2016 | |||||||||
| (Millions of dollars) | ||||||||||||
| Natural Gas Gathering and Processing | $ | 694.6 | $ | 284.2 | $ | 410.5 | ||||||
| Natural Gas Liquids | 1,306.3 | 114.3 | 105.9 | |||||||||
| Natural Gas Pipelines | 119.2 | 95.6 | 96.3 | |||||||||
| Other | 21.4 | 18.3 | 11.9 | |||||||||
| Total capital expenditures | $ | 2,141.5 | $ | 512.4 | $ | 624.6 |
Capital expenditures increased in 2018, compared with 2017, due primarily to capital-growth projects in progress. Capital expenditures decreased in 2017, compared with 2016, due primarily to the completion of several large projects. We expect our 2019 projected capital expenditures to increase relative to 2018 due to our announced capital-growth projects. See discussion of our announced capital-growth projects in the “Recent Developments” section.
The following table summarizes our 2019 projected growth and maintenance capital expenditures, excluding AFUDC and capitalized interest:
| 2019 Projected Capital Expenditures | ||
| (Millions of dollars) | ||
| Growth | $2,500-$3,700 | |
| Maintenance | $160-$200 | |
| Total projected capital expenditures | $2,660-$3,900 |
Credit Ratings - Our long-term debt credit ratings as of February 19, 2019, are shown in the table below:
| Rating Agency | Long-Term Rating | Short-Term Rating | Outlook |
| Moody’s | Baa3 | Prime-3 | Stable |
| S&P | BBB | A-2 | Stable |
Our credit ratings, which are investment grade, may be affected by a material change in our financial ratios or a material event affecting our business and industry. The most common criteria for assessment of our credit ratings are the debt-to-EBITDA ratio, interest coverage, business risk profile and liquidity. If our credit ratings were downgraded, our cost to borrow funds under the $2.5 Billion Credit Agreement and $1.5 Billion Term Loan Agreement would increase and a potential loss of access to the commercial paper market could occur. In the event that we are unable to borrow funds under our commercial paper program and there has not been a material adverse change in our business, we would continue to have access to our $1.5 Billion Term Loan Agreement until fully drawn or through May 2019, as well as our $2.5 Billion Credit Agreement, which expires in 2023. An adverse credit rating change alone is not a default under our $2.5 Billion Credit Agreement or our $1.5 Billion Term Loan Agreement. We do not expect a downgrade in our credit rating to have a material impact on our results of operations.
In the normal course of business, our counterparties provide us with secured and unsecured credit. In the event of a downgrade in our credit ratings or a significant change in our counterparties’ evaluation of our creditworthiness, we could be required to provide additional collateral in the form of cash, letters of credit or other negotiable instruments as a condition of continuing to conduct business with such counterparties. We may be required to fund margin requirements with our counterparties with cash, letters of credit or other negotiable instruments.
Dividends - Holders of our common stock share equally in any common stock dividends declared by our board of directors, subject to the rights of the holders of outstanding preferred stock. In 2018, we paid dividends of $3.245 per share, an increase of 19 percent compared with the prior year. In February 2019, we paid a quarterly dividend of $0.86 per share ($3.44 per share on an annualized basis), an increase of 12 percent compared with the same quarter in the prior year.
Our Series E Preferred Stock pays quarterly dividends on each share of Series E Preferred Stock, when, as and if declared by our Board of Directors, at a rate of 5.5 percent per year. In 2018, we paid dividends of $1.1 million for the Series E Preferred Stock. In February 2019, we paid dividends totaling $0.3 million for the Series E Preferred Stock.
For the years ended December 31, 2018 and 2017, cash flows from operations exceeded cash dividends paid by $866.1 million and $486.0 million, respectively. We expect our cash flows from operations to continue to sufficiently fund our cash dividends.
To the extent operating cash flows are not sufficient to fund our dividends, we may utilize short- and long-term debt and issuances of equity, as necessary or appropriate.
CASH FLOW ANALYSIS
We use the indirect method to prepare our Consolidated Statements of Cash Flows. Under this method, we reconcile net income to cash flows provided by operating activities by adjusting net income for those items that affect net income but do not result in actual cash receipts or payments during the period and for operating cash items that do not impact net income. These reconciling items include depreciation and amortization, impairment charges, allowance for equity funds used during construction, gain or loss on sale of assets, deferred income taxes, net undistributed earnings from equity-method investments, share-based compensation expense, other amounts and changes in our assets and liabilities not classified as investing or financing activities.
The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:
| Years Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
| (Millions of dollars) | ||||||||||||
| Total cash provided by (used in): | ||||||||||||
| Operating activities | $ | 2,186.7 | $ | 1,315.4 | $ | 1,353.2 | ||||||
| Investing activities | (2,114.9 | ) | (567.6 | ) | (615.4 | ) | ||||||
| Financing activities | (97.0 | ) | (959.5 | ) | (586.5 | ) | ||||||
| Change in cash and cash equivalents | (25.2 | ) | (211.7 | ) | 151.3 | |||||||
| Cash and cash equivalents at beginning of period | 37.2 | 248.9 | 97.6 | |||||||||
| Cash and cash equivalents at end of period | $ | 12.0 | $ | 37.2 | $ | 248.9 |
Operating Cash Flows - Operating cash flows are affected by earnings from our business activities and changes in our operating assets and liabilities. Changes in commodity prices and demand for our services or products, whether because of general economic conditions, changes in supply, changes in demand for the end products that are made with our products or increased competition from other service providers, could affect our earnings and operating cash flows. Our operating cash flows can also be impacted by changes in our natural gas and NGL inventory balances, which are driven primarily by commodity prices, supply, demand and the operation of our assets.
2018 vs. 2017 - Cash flows from operating activities, before changes in operating assets and liabilities, increased to $2.0 billion for 2018, compared with $1.5 billion for 2017. This increase is due primarily to higher earnings resulting from volume growth in the Williston Basin and STACK and SCOOP areas in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and higher optimization and marketing earnings due primarily to wider location price differentials in our Natural Gas Liquids segment, as discussed in “Financial Results and Operating Information.”
The changes in operating assets and liabilities increased operating cash flows $206.4 million for 2018, compared with a decrease of $192.6 million for 2017. This change is due primarily to the change in natural gas and NGLs in storage, which vary from period to period and vary with changes in commodity prices; the change in accounts receivable, accounts payable, and other accruals and deferrals resulting from the timing of receipt of cash from customers and payments to vendors, suppliers and other third parties; and the change in the fair value of our risk-management assets and liabilities.
2017 vs. 2016 - Cash flows from operating activities, before changes in operating assets and liabilities, increased to $1.5 billion for 2017, compared with $1.4 billion for 2016. This increase is due primarily to higher revenues resulting from volume growth in the Williston Basin and STACK and SCOOP areas in our Natural Gas Gathering and Processing and Natural Gas Liquids segments, higher fees resulting from contract restructuring in our Natural Gas Gathering and Processing segment, higher transportation services due to increased firm demand charge contracted capacity in our Natural Gas Pipelines segment and higher optimization and marketing earnings due primarily to higher optimization volumes and wider location price differentials in our Natural Gas Liquids segment, as discussed in “Financial Results and Operating Information.”
The changes in operating assets and liabilities decreased operating cash flows $192.6 million for 2017, compared with a decrease of $40.8 million for 2016. This change is due primarily to the change in natural gas and NGLs in storage, which varies from period to period and varies with changes in commodity prices, the change in accounts receivable, accounts payable,
and other accruals and deferrals resulting from the timing of receipt of cash from customers and payments to vendors, suppliers and other third parties and the change in risk-management assets and liabilities.
Investing Cash Flows
2018 vs. 2017 - Cash used in investing activities increased $1.5 billion due primarily to increased capital expenditures related to our announced capital-growth projects.
2017 vs. 2016 - Cash used in investing activities decreased $47.8 million due primarily to projects placed in service in 2016, offset partially by lower distributions received from unconsolidated affiliates in excess of cumulative earnings, lower proceeds from sale of assets and higher contributions to our unconsolidated affiliates.
Financing Cash Flows
2018 vs. 2017 - Cash used in financing activities decreased $862.5 million due primarily to issuance of common stock, the $550 million draw on our $1.5 Billion Term Loan Agreement and decreased distributions to noncontrolling interests resulting from the Merger Transaction, offset partially by repayment of short-term borrowings, increased dividends and the acquisition of the remaining 20 percent interest in WTLPG.
2017 vs. 2016 - Cash used in financing activities increased $373.0 million due primarily to repayment of short-term borrowings and increased dividends, offset partially by the issuance of common stock through our “at-the-market” equity program and decreased distributions to noncontrolling interests resulting from the Merger Transaction.
IMPACT OF NEW ACCOUNTING STANDARDS
Information about the impact of new accounting standards is included in Note A of the Notes to Consolidated Financial Statements in this Annual Report.
ESTIMATES AND CRITICAL ACCOUNTING POLICIES
The preparation of our Consolidated Financial Statements and related disclosures in accordance with GAAP requires us to make estimates and assumptions with respect to values or conditions that cannot be known with certainty that affect the reported amounts of assets and liabilities, and the disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements. These estimates and assumptions also affect the reported amounts of revenue and expenses during the reporting period. Although we believe these estimates and assumptions are reasonable, actual results could differ from our estimates.
The following is a summary of our most critical accounting policies, which are defined as those estimates and policies most important to the portrayal of our financial condition and results of operations and requiring management’s most difficult, subjective or complex judgment, particularly because of the need to make estimates concerning the impact of inherently uncertain matters. We have discussed the development and selection of our estimates and critical accounting policies with the Audit Committee of our Board of Directors.
Derivatives and Risk-Management Activities - We utilize derivatives to reduce our market-risk exposure to commodity price and interest-rate fluctuations and to achieve more predictable cash flows. We record all derivative instruments at fair value, except for normal purchases and normal sales transactions that are expected to result in physical delivery. While many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists, some contracts are executed in markets for which market prices may exist, but the market may be relatively inactive. This results in limited price transparency that requires management’s judgment and assumptions to estimate fair values. Fair value measurements classified as Level 3 are based on inputs that may include one or more unobservable inputs, including internally developed natural gas basis and NGL price curves that incorporate observable and unobservable market data from broker quotes and third-party pricing services. These balances are comprised predominantly of exchange-cleared and over-the-counter derivatives for natural gas basis and NGLs. Our commodity derivatives are generally valued using forward quotes provided by third-party pricing services that are validated with other market data. We believe any measurement uncertainty at December 31, 2018, is immaterial as our Level 3 fair value measurements are based on unadjusted pricing information from broker quotes and third-party pricing services.
The accounting for changes in the fair value of a derivative instrument depends on whether it qualifies and has been designated as part of a hedging relationship. When possible, we implement effective hedging strategies using derivative financial
instruments that qualify as hedges for accounting purposes. We have not used derivative instruments for trading purposes. For a derivative designated as a cash flow hedge, the gain or loss from a change in fair value of the derivative instrument is deferred in accumulated other comprehensive income (loss) until the forecasted transaction affects earnings, at which time the fair value of the derivative instrument is reclassified into earnings.
We assess the effectiveness of hedging relationships at the inception of the hedge by performing an effectiveness test to determine whether they are highly effective. We subsequently assess qualitative factors. We do not believe that changes in our fair value estimates of our derivative instruments have a material impact on our results of operations, as the majority of our derivatives are accounted for as effective cash flow hedges. However, if a derivative instrument is ineligible for cash flow hedge accounting or if we fail to appropriately designate it as a cash flow hedge, changes in fair value of the derivative instrument would be recorded currently in earnings. Additionally, if a cash flow hedge ceases to qualify for hedge accounting treatment because it is no longer probable that the forecasted transaction will occur, the change in fair value of the derivative instrument would be recognized in earnings. For more information on commodity price sensitivity and a discussion of the market risk of pricing changes, see Item 7A, Quantitative and Qualitative Disclosures about Market Risk.
See Notes A, B and C of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of fair value measurements and derivatives and risk-management activities.
Impairment of Goodwill and Long-Lived Assets, including Intangible Assets - We assess our goodwill for impairment at least annually on July 1, unless events or changes in circumstances indicate an impairment may have occurred before that time. As part of our goodwill impairment test, we may first assess qualitative factors (including macroeconomic conditions, industry and market considerations, cost factors and overall financial performance) to determine whether it is more likely than not that the fair value of each of our reporting units is less than its carrying amount. If further testing is necessary or a quantitative test is elected, we perform a two-step impairment test for goodwill.
Our qualitative goodwill impairment analysis performed as of July 1, 2018, did not result in an impairment charge nor did our analysis reflect any reporting units at risk, and subsequent to that date, no event has occurred indicating that the implied fair value of each of our reporting units is less than the carrying value of its net assets.
The following table sets forth our goodwill, by segment, for the periods indicated:
| December 31, 2018 | December 31, 2017 | ||||||
| (Thousands of dollars) | |||||||
| Natural Gas Gathering and Processing | $ | 153,404 | $ | 153,404 | |||
| Natural Gas Liquids | 371,217 | 371,217 | |||||
| Natural Gas Pipelines | 156,479 | 156,479 | |||||
| Total goodwill | $ | 681,100 | $ | 681,100 |
We assess our long-lived assets, including intangible assets with finite useful lives, for impairment whenever events or changes in circumstances indicate that an asset’s carrying amount may not be recoverable. An impairment is indicated if the carrying amount of a long-lived asset exceeds the sum of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If an impairment is indicated, we record an impairment loss equal to the difference between the carrying value and the fair value of the long-lived asset.
For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. Therefore, we periodically evaluate the amount at which we carry our equity-method investments to determine whether current events or circumstances warrant adjustments to our carrying value.
Impairment Charges - We recorded $20.2 million of noncash impairment charges in 2017 related to our nonstrategic long-lived assets and equity investments in North Dakota and Oklahoma.
Our impairment tests require the use of assumptions and estimates such as industry economic factors and the profitability of future business strategies. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future impairment charges.
See Notes A, D, E and M of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of goodwill, long-lived assets and investments in unconsolidated affiliates.
Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment - Our property, plant and equipment are depreciated using the straight-line method that incorporates management assumptions regarding useful economic lives and residual values. As we continue to increase capital spending and place additional assets in service, our estimates related to depreciation expense have become more significant and changes in estimated useful lives of our assets could have a material effect on our results of operations. At the time we place our assets in service, we believe such assumptions are reasonable; however, circumstances may develop that would cause us to change these assumptions, which would change our depreciation expense prospectively. Examples of such circumstances include changes in (i) competition, (ii) laws and regulations that limit the estimated economic life of an asset, (iii) technology that render an asset obsolete, (iv) expected salvage values and (v) forecasts of the remaining economic life for the resource basins where our assets are located, if any.
See Note D of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of property, plant and equipment.
Contingencies - Our accounting for contingencies covers a variety of business activities, including contingencies for legal and environmental exposures. We accrue these contingencies when our assessments indicate that it is probable that a liability has been incurred or an asset will not be recovered, and an amount can be reasonably estimated. We expense legal fees as incurred and base our legal liability estimates on currently available facts and our assessments of the ultimate outcome or resolution. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than the completion of a remediation feasibility study. Recoveries of environmental remediation costs from other parties are recorded as assets when their receipt is deemed probable. Our expenditures for environmental evaluation, mitigation, remediation and compliance to date have not been significant in relation to our financial position or results of operations, and our expenditures related to environmental matters had no material effect on earnings or cash flows during 2018, 2017 or 2016. Actual results may differ from our estimates resulting in an impact, positive or negative, on our results of operations.
See Note N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of contingencies.
CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table sets forth our contractual obligations related to debt, leases and other long-term obligations as of December 31, 2018. For additional discussion of the debt agreements, see Note F of the Notes to Consolidated Financial Statements in this Annual Report.
| Payments Due by Period | ||||||||||||||||||||||||||||
| Contractual Obligations | Total | 2019 | 2020 | 2021 | 2022 | 2023 | Thereafter | |||||||||||||||||||||
| (Millions of dollars) | ||||||||||||||||||||||||||||
| Senior notes | $ | 8,872.4 | $ | 500.0 | $ | 300.0 | $ | — | $ | 1,447.4 | $ | 925.0 | $ | 5,700.0 | ||||||||||||||
| $1.5 Billion Term Loan Agreement (a) | 550.0 | — | — | 550.0 | — | — | — | |||||||||||||||||||||
| Guardian Pipeline senior notes | 29.0 | 7.7 | 7.7 | 7.7 | 5.9 | — | — | |||||||||||||||||||||
| Interest payments on debt | 6,325.4 | 463.4 | 447.0 | 442.1 | 399.2 | 355.5 | 4,218.2 | |||||||||||||||||||||
| Operating leases | 23.2 | 6.9 | 2.2 | 1.9 | 1.7 | 1.5 | 9.0 | |||||||||||||||||||||
| Capital lease | 44.1 | 4.5 | 4.5 | 4.5 | 4.5 | 4.5 | 21.6 | |||||||||||||||||||||
| Firm transportation and storage contracts | 202.4 | 63.7 | 51.6 | 35.7 | 22.4 | 17.3 | 11.7 | |||||||||||||||||||||
| Financial and physical derivatives | 229.1 | 224.8 | 4.3 | — | — | — | — | |||||||||||||||||||||
| Employee benefit plans | 86.9 | 16.5 | 14.0 | 18.4 | 18.5 | 19.5 | — | |||||||||||||||||||||
| Purchase commitments and other | 190.1 | 56.0 | 56.5 | 34.4 | 14.9 | 13.9 | 14.4 | |||||||||||||||||||||
| Total | $ | 16,552.6 | $ | 1,343.5 | $ | 887.8 | $ | 1,094.7 | $ | 1,914.5 | $ | 1,337.2 | $ | 9,974.9 |
(a) - In November 2018, we entered into our $1.5 Billion Term Loan Agreement with a syndicate of banks, which is available to be drawn until May 2019 and matures in November 2021. As of December 31, 2018, we had borrowings totaling $550 million outstanding under our $1.5 Billion Term Loan Agreement.
Senior notes and $1.5 Billion Term Loan Agreement - The amount of principal due in each period.
Interest payments on debt - Interest payments are calculated by multiplying long-term debt principal amount by the respective coupon rates.
Operating leases - Our operating leases primarily include leases for office space, pipeline equipment, rail cars and information technology equipment.
Capital lease - We lease certain compression facilities under a capital lease that has a fixed-price purchase option in 2028.
Firm transportation and storage contracts - Our Natural Gas Gathering and Processing and Natural Gas Liquids segments are party to fixed-price contracts for firm transportation and storage capacity.
Financial and physical derivatives - These are obligations arising from our fixed- and variable-price purchase commitments for physical and financial commodity derivatives. Estimated future variable-price purchase commitments are based on market information at December 31, 2018. Actual future variable-price purchase obligations may vary depending on market prices at the time of delivery. Sales of the related physical volumes and net positive settlements of financial derivatives are not reflected in the table above.
Employee benefit plans - We contributed $14.5 million to our defined benefit pension plan in January 2019 and expect to make $2.0 million in contributions to our other postretirement plans in 2019. See Note K of the Notes to Consolidated Financial Statements in this Annual Report for discussion of our employee benefit plans.
Purchase commitments and other - Purchase commitments include commitments related to our growth capital expenditures and other contractual commitments. Purchase commitments exclude commodity purchase contracts, which are included in the “Financial and physical derivatives” amounts.
FORWARD-LOOKING STATEMENTS
Some of the statements contained and incorporated in this Annual Report are forward-looking statements as defined under federal securities laws. The forward-looking statements relate to our anticipated financial performance (including projected operating income, net income, capital expenditures, cash flows and projected levels of dividends), liquidity, management’s plans and objectives for our future capital-growth projects and other future operations (including plans to construct additional natural gas and natural gas liquids pipelines and processing facilities and related cost estimates), our business prospects, the outcome of regulatory and legal proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under federal securities legislation and other applicable laws. The following discussion is intended to identify important factors that could cause future outcomes to differ materially from those set forth in the forward-looking statements.
Forward-looking statements include the items identified in the preceding paragraph, the information concerning possible or assumed future results of our operations and other statements contained or incorporated in this Annual Report identified by words such as “anticipate,” “estimate,” “expect,” “project,” “intend,” “plan,” “believe,” “should,” “goal,” “forecast,” “guidance,” “could,” “may,” “continue,” “might,” “potential,” “scheduled” and other words and terms of similar meaning.
One should not place undue reliance on forward-looking statements. Known and unknown risks, uncertainties and other factors may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by forward-looking statements. Those factors may affect our operations, markets, products, services and prices. In addition to any assumptions and other factors referred to specifically in connection with the forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward-looking statement include, among others, the following:
| • | competition from other United States and foreign energy suppliers and transporters, as well as alternative forms of energy, including, but not limited to, solar power, wind power, geothermal energy and biofuels such as ethanol and biodiesel; |
| • | the capital intensive nature of our businesses; |
| • | the profitability of assets or businesses acquired or constructed by us; |
| • | our ability to make cost-saving changes in operations; |
| • | risks of marketing, trading and hedging activities, including the risks of changes in energy prices or the financial condition of our counterparties; |
| • | the uncertainty of estimates, including accruals and costs of environmental remediation; |
| • | the effects of changes in governmental policies and regulatory actions, including changes with respect to income and other taxes, pipeline safety, environmental compliance, climate change initiatives and authorized rates of recovery of natural gas and natural gas transportation costs; |
| • | the impact on drilling and production by factors beyond our control, including the demand for natural gas and crude oil; producers’ desire and ability to obtain necessary permits; reserve performance; and capacity constraints on the pipelines that transport crude oil, natural gas and NGLs from producing areas and our facilities; |
| • | difficulties or delays experienced by trucks, railroads or pipelines in delivering products to or from our terminals or pipelines; |
| • | the effects of weather and other natural phenomena, including climate change, on our operations, demand for our services and energy prices; |
| • | changes in demand for the use of natural gas, NGLs and crude oil because of market conditions caused by concerns about climate change; |
| • | the impact of unforeseen changes in interest rates, debt and equity markets, inflation rates, economic recession and other external factors over which we have no control, including the effect on pension and postretirement expense and funding resulting from changes in equity and bond market returns; |
| • | our indebtedness and guarantee obligations could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds and/or place us at competitive disadvantages compared with our competitors that have less debt or have other adverse consequences; |
| • | actions by rating agencies concerning our credit; |
| • | the results of administrative proceedings and litigation, regulatory actions, rule changes and receipt of expected clearances involving any local, state or federal regulatory body, including the FERC, the National Transportation Safety Board, the PHMSA, the EPA and CFTC; |
| • | our ability to access capital at competitive rates or on terms acceptable to us; |
| • | risks associated with adequate supply to our gathering, processing, fractionation and pipeline facilities, including production declines that outpace new drilling or extended periods of ethane rejection; |
| • | the risk that material weaknesses or significant deficiencies in our internal controls over financial reporting could emerge or that minor problems could become significant; |
| • | the impact and outcome of pending and future litigation; |
| • | the timing and extent of changes in energy commodity prices; |
| • | the ability to market pipeline capacity on favorable terms, including the effects of: |
| – | future demand for and prices of natural gas, NGLs and crude oil; |
| – | competitive conditions in the overall energy market; |
| – | availability of supplies of Canadian and United States natural gas and crude oil; and |
| – | availability of additional storage capacity; |
| • | performance of contractual obligations by our customers, service providers, contractors and shippers; |
| • | the timely receipt of approval by applicable governmental entities for construction and operation of our pipeline and other projects and required regulatory clearances; |
| • | our ability to acquire all necessary permits, consents or other approvals in a timely manner, to promptly obtain all necessary materials and supplies required for construction, and to construct gathering, processing, storage, fractionation and transportation facilities without labor or contractor problems; |
| • | the mechanical integrity of facilities operated; |
| • | demand for our services in the proximity of our facilities; |
| • | our ability to control operating costs; |
| • | acts of nature, sabotage, terrorism or other similar acts that cause damage to our facilities or our suppliers’ or shippers’ facilities; |
| • | economic climate and growth in the geographic areas in which we do business; |
| • | the risk of a prolonged slowdown in growth or decline in the United States or international economies, including liquidity risks in United States or foreign credit markets; |
| • | the impact of recently issued and future accounting updates and other changes in accounting policies; |
| • | the possibility of future terrorist attacks or the possibility or occurrence of an outbreak of, or changes in, hostilities or changes in the political conditions throughout the world; |
| • | the risk of increased costs for insurance premiums, security or other items as a consequence of terrorist attacks; |
| • | risks associated with pending or possible acquisitions and dispositions, including our ability to finance or integrate any such acquisitions and any regulatory delay or conditions imposed by regulatory bodies in connection with any such acquisitions and dispositions; |
| • | the impact of uncontracted capacity in our assets being greater or less than expected; |
| • | the ability to recover operating costs and amounts equivalent to income taxes, costs of property, plant and equipment and regulatory assets in our state and FERC-regulated rates; |
| • | the composition and quality of the natural gas and NGLs we gather and process in our plants and transport on our pipelines; |
| • | the efficiency of our plants in processing natural gas and extracting and fractionating NGLs; |
| • | the impact of potential impairment charges; |
| • | the risk inherent in the use of information systems in our respective businesses, implementation of new software and hardware, and the impact on the timeliness of information for financial reporting; |
| • | our ability to control construction costs and completion schedules of our pipelines and other projects; and |
| • | the risk factors listed in the reports we have filed and may file with the SEC, which are incorporated by reference. |
These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on our future results. These and other risks are described in greater detail in Part I, Item 1A, Risk Factors, in this Annual Report and in our other filings that we make with the SEC, which are available via the SEC’s website at www.sec.gov and our website at www.oneok.com. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these factors. Any such forward-looking statement speaks only as of the date on which such statement is made, and other than as required under securities laws, we undertake no obligation to update publicly any forward-looking statement whether as a result of new information, subsequent events or change in circumstances, expectations or otherwise.
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