ONEOK, INC.. 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.
Market Conditions - Volumes increased across our system in our Natural Gas Gathering and Processing and Natural Gas Liquids segments in 2019, compared with 2018, which resulted in higher fee-based earnings, primarily as a result of our completed capital-growth projects, continued drilling and producer improvements in production due to enhanced completion techniques, offset partially by natural production declines. We experienced fluctuating NGL location price differentials due to increased supply, increased demand in the Mid-Continent region, infrastructure constraints and slower demand growth in theGulf Coast due primarily to delays in the startup of petrochemical facilities and constrained NGL export facilities. The Conway-to-Mont Belvieu OPIS price differential for ethane in ethane/propane mix averaged$0.07 per gallon in 2019, compared with$0.15 per gallon in 2018, which resulted in lower 33
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earnings from our optimization and marketing activities in our Natural Gas Liquids segment. We expect narrower NGL location price differentials in 2020.
Ethane Opportunity - Ethane volumes under long-term contracts delivered to our NGL system averaged 385 MBbl/d in 2019, compared with 380 MBbl/d in 2018, and have generally been increasing since 2017, primarily as a result of NGL demand increasing from exports and petrochemical companies completing ethylene production projects and plant expansions. Our NGL capital-growth projects are expected to help alleviate system constraints, enabling additional NGLs, including ethane, to reach theMont Belvieu, Texas , market center.Northern Border Pipeline , which provides key natural gas takeaway capacity out of theWilliston Basin , recently notified shippers that it plans to place restrictions on the Btu content of the residue natural gas it receives in order to meet downstream pipeline specifications. When these restrictions take effect, natural gas processors in theWilliston Basin may recover incremental ethane into the NGL stream in order to lower the Btu content of the residue natural gas delivered toNorthern Border Pipeline . As a result, ethane deliveries to our NGL system may increase. Growth Projects - Our announced large capital-growth projects that have recently been completed or are currently under construction are outlined in the tables below: Approximate Expected Project Scope Costs (a) Completion Natural Gas Gathering and Processing (In millions) Demicks Lake I plant 200 MMcf/d processing plant and$400 Completed and related related gathering infrastructure in October 2019 infrastructure the core of the Williston Basin Supported by acreage dedications with long-term primarily fee-based contracts Demicks Lake II 200 MMcf/d processing plant and$410 Completed plant and related related gathering infrastructure in January 2020 infrastructure the core of the Williston Basin Supported by acreage dedications with long-term primarily fee-based contracts Bear Creek plant 200 MMcf/d processing plant$405 First Quarter 2021 expansion and expansion and related gathering related infrastructure in the Williston infrastructure Basin Supported by acreage dedications with long-term primarily fee-based contracts Demicks Lake III 200 MMcf/d processing plant and$305 Third Quarter 2021 plant and related related gathering infrastructure in infrastructure the core of the Williston Basin Supported by acreage dedications with primarily fee-based contracts
(a) - Excludes capitalized interest/AFUDC.
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Approximate Expected
Project Scope Costs (a) Completion
Natural Gas Liquids
Elk Creek pipeline 900-mile NGL pipeline from the $1,400 Completed
and related Williston Basin to the Mid-Continent December 2019
infrastructure region, with capacity of up to (b)
240 MBbl/d, and related
infrastructure
Anchored by long-term contracts
Expansion capability up to 400
MBbl/d with additional pump
facilities
Arbuckle II pipeline 530-mile NGL pipeline from the STACK $1,360 First Quarter
and related area to Mont Belvieu, Texas, with 2020
infrastructure initial capacity up to approximately
400 MBbl/d, and related
infrastructure
Supported by long-term contracts
Expansion capability up to 1 MMBbl/d
West Texas LPG Increasing mainline capacity by 80
2020
and Arbuckle II facilities and pipeline looping
connection Connecting West Texas LPG pipeline
system to the 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 125 MBbl/d NGL fractionator in Mont $575 First Quarter
and related Belvieu, Texas, and related 2020 (c)
infrastructure infrastructure, which includes
additional NGL storage in Mont
Belvieu
Fully contracted with long-term
contracts
Bakken NGL pipeline 75-mile NGL pipeline in the $100 Fourth Quarter
extension Williston Basin connecting to a 2020
third-party processing plant
Supported by a long-term contract
with a minimum volume commitment
Arbuckle II Provide additional takeaway capacity $240 First Quarter
extension project in the STACK area 2021
and additional
gathering Allow increasing volumes on the Elk
infrastructure Creek pipeline access to
fractionation capacity at Mont
Belvieu, Texas
Arbuckle II pipeline Increasing mainline capacity with
additional pump facilities 2021
Increases capacity to 500 MBbl/d
MB-5 fractionator 125 MBbl/d NGL fractionator in Mont $750 First Quarter
and related Belvieu, Texas, and related 2021
infrastructure infrastructure, which includes
additional NGL storage in Mont
Belvieu
Fully contracted with long-term
contracts
West Texas LPG Increasing mainline capacity by 40
2021
Supported by long-term dedicated
production from third-party
processing plants expected to
produce up to 45 MBbl/d
Mid-Continent 65 MBbl/d of expansions at our $150 First Quarter
fractionation Mid-Continent NGL facilities 2021 (d)
facility expansions
West Texas LPG Increasing mainline capacity by 100 $310 Second Quarter
pipeline expansion MBbl/d 2021
Fully contracted with long-term
dedicated production from
third-party processing plants
Elk Creek pipeline Increasing mainline capacity to 400 $305 Third Quarter
expansion MBbl/d with additional pump 2021 (e)
facilities
Supported by long-term dedicated
production from ONEOK and
third-party processing plants
(a) - Excludes capitalized interest/AFUDC.
(b) - In July 2019 , we completed the southern section of the pipeline from the
Powder River Basin to our existing Mid-Continent NGL facilities. In December
2019 , we completed the northern section of the pipeline from the Williston Basin
to the Powder River Basin .
(c) - We completed 75 MBbl/d in December 2019 , with the remaining 50 MBbl/d to
be completed in the first quarter 2020.
(d) - We expect to complete 15 MBbl/d in the third quarter 2020, with the
remaining 50 MBbl/d expected to be completed in the first quarter 2021.
(e) - We expect a portion of this incremental capacity to be available as early
as first quarter 2021.
Debt Issuances and Repayments - In August 2019 , we completed an underwritten
public offering of $2.0 billion senior unsecured notes consisting of $500
million , 2.75% senior notes due 2024; $750 million , 3.4% senior notes due 2029;
and $750 million , 4.45% senior notes due 2049. The net proceeds, after deducting
underwriting discounts, commissions and offering expenses, were $1.97 billion
and were used for general corporate purposes, including funding of capital
expenditures and repayment of existing indebtedness. Repayments included the
redemption of our $300 million , 3.8% senior notes due March
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2020 at a redemption price of
InMarch 2019 , we completed an underwritten public offering of$1.25 billion senior unsecured notes consisting of$700 million , 4.35% senior notes due 2029 and an additional issuance of$550 million of our existing 5.2% senior notes due 2048. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, and exclusive of accrued interest, were$1.23 billion . During the six months endedJune 30, 2019 , we drew the remaining$950 million under our$1.5 Billion Term Loan Agreement. The proceeds were used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures.
Also, in
Dividends - During 2019, we paid dividends totaling$3.53 per share, an increase of 9% from the$3.245 per share paid in 2018. InFebruary 2020 , we paid a quarterly dividend of$0.935 per share ($3.74 per share on an annualized basis), an increase of 9% compared with the same quarter in the prior year. Our dividend growth is due to the increase in cash flows resulting from the continued growth of our operations.
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
Years Ended December 31, 2019 vs. 2018 2018 vs. 2017
Financial Results 2019 2018 2017 Increase (Decrease)
(Millions of dollars)
Revenues
Commodity sales $ 8,916.1 $ 11,395.6 $ 9,862.7 $ (2,479.5 ) $ 1,532.9
Services 1,248.3 1,197.6 2,311.2 50.7 (1,113.6 )
Total revenues 10,164.4 12,593.2 12,173.9 (2,428.8 ) 419.3
Cost of sales and fuel
(exclusive of items shown
separately below) 6,788.0 9,422.7 9,538.0 (2,634.7 ) (115.3 )
Operating costs 982.9 907.0 822.7 75.9 84.3
Depreciation and
amortization 476.5 428.6 406.3 47.9 22.3
Impairment of long-lived
assets - - 16.0 - (16.0 )
(Gain) loss on sale of
assets 2.6 (0.6 ) (0.9 ) (3.2 ) (0.3 )
Operating income $ 1,914.4 $ 1,835.5 $ 1,391.8 $ 78.9 $ 443.7
Equity in net earnings
from investments $ 154.5 $ 158.4 $ 159.3 $ (3.9 ) $ (0.9 )
Impairment of equity
investments $ - $ - $ (4.3 ) $ - $ (4.3 )
Interest expense, net of
capitalized interest $ (491.8 ) $ (469.6 ) $ (485.7 ) $ 22.2 $ (16.1 )
Net income $ 1,278.6 $ 1,155.0 $ 593.5 $ 123.6 $ 561.5
Adjusted EBITDA $ 2,580.2 $ 2,447.5 $ 1,986.9 $ 132.7 $ 460.6
Capital expenditures $ 3,848.3 $ 2,141.5 $ 512.4 $ 1,706.8 $ 1,629.1 See reconciliation of net income to adjusted EBITDA in the "Adjusted EBITDA" section.
Changes in commodity prices and sales volumes 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.
2019 vs. 2018 - Operating income increased primarily as a result of the
following:
• Natural Gas Gathering and Processing - an increase of
primarily to natural gas volume growth, offset partially by a decrease of
net of hedges;
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• Natural Gas Liquids - an increase of
due primarily to higher volumes and average fee rates, offset partially by
a decrease of
wider location price differentials in the prior year; and
• Natural Gas Pipelines - an increase of $56.5 million from higher
transportation services, offset partially by a decrease of
from lower net retained fuel and timing of equity gas sales; offset
partially by
• an increase of
employee-related costs associated with labor and benefits, spending on
routine maintenance projects and ad valorem taxes due to the growth of our
operations; and
• an increase of
projects placed in service.
Net income increased for the year endedDecember 31, 2019 , compared with the same period in 2018, due to the items discussed above and higher allowance for equity funds used during construction related to our capital-growth projects, offset partially by higher interest expense related to our underwritten public debt offerings in March andAugust 2019 .
Capital expenditures increased due primarily to spending on our announced capital-growth projects.
Additional information regarding our financial results and operating information is provided in the discussions for each of our segments.
Selected Financial Results and Operating Information the Year EndedDecember 31, 2018 vs. 2017 - The consolidated and segment financial results and operating information for the year endedDecember 31, 2018 , compared with the year endedDecember 31, 2017 , are included in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2018 Annual Report on Form 10-K, which is available via theSEC's website at www.sec.gov and our website at www.oneok.com.
Natural Gas Gathering and Processing
Growth Projects - Our Natural Gas Gathering and Processing segment is investing in growth projects in NGL-rich areas in theWilliston Basin 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
Years Ended December 31, 2019 vs. 2018 2018 vs. 2017
Financial Results 2019 2018 2017 Increase (Decrease)
(Millions of dollars)
NGL sales $ 1,024.3 $ 1,567.2 $ 1,208.0 $ (542.9 ) $ 359.2
Condensate sales 200.1 208.8 103.2 (8.7 ) 105.6Residue natural gas sales 966.1 1,084.2 856.3
(118.1 ) 227.9
Gathering, compression,
dehydration and processing
fees and other revenue 178.1 174.4 859.1 3.7 (684.7 )
Cost of sales and fuel
(exclusive of depreciation
and operating costs) (1,302.3 ) (2,041.4 ) (2,216.4 ) (739.1 ) (175.0 )
Operating costs, excluding
noncash compensation
adjustments (352.8 ) (357.7 ) (302.6 ) (4.9 ) 55.1
Equity in net earnings
(loss) from investments,
excluding noncash
impairment charges (6.3 ) 0.4 12.1 (6.7 ) (11.7 )
Other (4.5 ) (4.3 ) (1.2 ) (0.2 ) (3.1 )
Adjusted EBITDA $ 702.7 $ 631.6 $ 518.5 $ 71.1 $ 113.1
Impairment of equity
investments $ - $ - $ (4.3 ) $ - $ (4.3 )
Capital expenditures $ 926.5 $ 694.6 $ 284.2 $ 231.9 $ 410.4 See reconciliation of net income to adjusted EBITDA in the "Adjusted EBITDA" section.
Changes in commodity prices and sales volumes affect both revenue and cost of
sales and fuel, and, therefore, the impact is largely offset between these line
items.
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2019 vs. 2018 - Adjusted EBITDA increased$71.1 million , primarily as a result of the following: • an increase of$95.5 million due primarily to natural gas volume growth in
the
production declines; and
• a decrease of
outside services and materials and supplies, offset partially by higher
employee-related costs and ad valorem taxes due primarily to the growth of
our operations; offset partially by
• a decrease of $20.9 million due primarily to lower realized NGL and
natural gas prices, net of hedges; and
• a decrease of
from investments due to a decrease in supply volumes in the dry natural
gas area of the
Capital expenditures increased due primarily to spending on our announced
capital-growth projects.
Years Ended December 31,
Operating Information (a) 2019 2018 2017
Natural gas gathered (BBtu/d) 2,753 2,546 2,211
Natural gas processed (BBtu/d) (b) 2,555 2,382
2,056
NGL sales (MBbl/d) 224 198
187
Residue natural gas sales (BBtu/d) (b) 1,201 1,088 896 Average fee rate ($MMBtu)$ 0.92 $ 0.90 $ 0.86
(a) - Includes volumes for consolidated entities only. (b) - Includes volumes at company-owned and third-party facilities.
2019 vs. 2018 - Natural gas gathered, natural gas processed, NGL sales and residue natural gas sales volumes increased in 2019, compared with 2018, due primarily to our capital-growth projects and continued producer improvements in production due to enhanced completion techniques, offset partially by natural production declines.
Commodity Price Risk - See discussion regarding our commodity price risk under "Commodity Price Risk" in Item 7A, Quantitative and Qualitative Disclosures about Market Risk.
Natural Gas Liquids
Growth Projects - Our Natural Gas Liquids segment invests in projects to transport, fractionate, store and deliver to market centers NGL supply from shale and other resource development areas. Our growth strategy is focused around connecting diversified supply basins from theRocky Mountain region through the Mid-Continent region and thePermian Basin with NGL product demand from the petrochemical industry and NGL export demand in theGulf Coast . Growing crude oil, natural gas and NGL production together with higher petrochemical and export demand have resulted in us making additional capital investments to expand our infrastructure and alleviate system constraints. 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 andPermian Basin with end-use markets. In 2019, we connected seven third-party natural gas processing plants and one affiliate natural gas processing plant to our NGL system, five in the Mid-Continent region, one in thePermian Basin and two in theRocky Mountain region. In addition, six third-party natural gas processing plants connected to our system were expanded, two in the Mid-Continent region, two in thePermian Basin and two in theRocky Mountain region.
For a discussion of our capital expenditure financing, see "Capital Expenditures" in the "Liquidity and Capital Resources" section.
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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
Years Ended December 31, 2019 vs. 2018 2018 vs. 2017
Financial Results 2019 2018 2017 Increase (Decrease)
(Millions of dollars)
NGL and condensate sales $ 7,910.8 $ 10,319.9 $ 8,998.9 $ (2,409.1 ) $ 1,321.0
Exchange service revenues
and other 424.2 415.7 1,430.3 8.5 (1,014.6 )
Transportation and storage
revenues 197.5 199.0 197.0 (1.5 ) 2.0
Cost of sales and fuel
(exclusive of depreciation
and operating costs) (6,690.9 ) (9,176.8 ) (9,176.5 ) (2,485.9 ) 0.3
Operating costs, excluding
noncash compensation
adjustments (434.4 ) (378.3 ) (351.3 ) 56.1 27.0
Equity in net earnings from
investments 65.1 67.1 59.9 (2.0 ) 7.2
Other (6.5 ) (6.0 ) (3.4 ) (0.5 ) (2.6 )
Adjusted EBITDA $ 1,465.8 $ 1,440.6 $ 1,154.9 $ 25.2 $ 285.7
Capital expenditures $ 2,796.6 $ 1,306.3 $ 114.3 $ 1,490.3 $ 1,192.0 See reconciliation of net income to adjusted EBITDA in the "Adjusted EBITDA" section.
Changes in commodity prices and sales volumes affect both revenues and cost of sales and fuel, and, therefore, the impact is largely offset between these line items. 2019 vs. 2018 - Adjusted EBITDA increased$25.2 million , primarily as a result of the following: • an increase of$148.1 million in exchange services due to$150.2 million
in higher volumes primarily in the
Basin and the STACK and SCOOP areas, and
fee rates primarily in the
offset partially by
transportation and fractionation costs,
narrower product price differentials and
unfractionated NGLs in inventory; offset partially by
• a decrease of
a decrease of
in the prior year, particularly in the third quarter 2018, and
million in lower earnings related primarily to product price
differentials, offset partially by higher marketing earnings of
held in inventory; and
• an increase of
employee-related costs associated with labor and benefits due to the
growth of our operations, and spending on routine maintenance projects.
Capital expenditures increased due primarily to our announced capital-growth
projects.
Years Ended December 31,
Operating Information 2019 2018 2017
Raw feed throughput (MBbl/d) (a) 1,079 1,010 895
NGLs transported - gathering lines (MBbl/d) (b) 988 912 812
NGLs fractionated (MBbl/d) (c) 726 715 621
Average Conway-to-Mont Belvieu OPIS price
differential -
ethane in ethane/propane mix ($/gallon) $ 0.07 $
0.15
(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.
2019 vs. 2018 - Raw feed throughput volumes increased primarily in theRocky Mountain region, thePermian Basin and the STACK and SCOOP areas as a result of our completed capital-growth projects, continued drilling and producer improvements in production due to enhanced completion techniques, offset partially by natural production declines and lower volumes in the Mid-Continent region due primarily to lower ethane volumes. 39
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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 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 expanded our natural gas pipeline infrastructure inOklahoma and thePermian Basin . The projects included an eastbound expansion of ourONEOK Gas Transportation system by 150 MMcf/d from the STACK and SCOOP areas to an interstate pipeline delivery point in easternOklahoma , a westbound expansion of our ONEOK Gas Transportation system by 100 MMcf/d from the STACK area to multiple interstate pipeline delivery points in westernOklahoma and an expansion of our WesTex Transmission system by 300 MMcf/d from thePermian Basin to interstate pipeline delivery points in the TexasPanhandle . Additionally, we completed an expansion project on our Roadrunner joint venture to make the pipeline bidirectional, which resulted in approximately 1.0 Bcf/d of eastbound transportation capacity from theDelaware 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
Years Ended December 31, 2019 vs. 2018 2018 vs. 2017
Financial Results 2019 2018 2017 Increase (Decrease)
(Millions of dollars)
Transportation revenues $ 393.7 $ 343.0 $ 327.9 $ 50.7 $ 15.1
Storage revenues 72.6 72.0 66.5 0.6 5.5
Natural gas sales and other
revenues 5.7 16.7 25.5 (11.0 ) (8.8 )
Cost of sales and fuel
(exclusive of depreciation
and operating costs) (4.6 ) (16.0 ) (43.4 ) (11.4 ) (27.4 )
Operating costs, excluding
noncash compensation
adjustments (150.8 ) (139.2 ) (123.1 ) 11.6 16.1
Equity in net earnings from
investments 95.7 90.8 87.3 4.9 3.5
Other (3.5 ) (1.0 ) (0.9 ) (2.5 ) (0.1 )
Adjusted EBITDA $ 408.8 $ 366.3 $ 339.8 $ 42.5 $ 26.5
Capital expenditures $ 99.2 $ 119.2 $ 95.6 $ (20.0 ) $ 23.6 See reconciliation of net income to adjusted EBITDA in the "Adjusted EBITDA" section.
2019 vs. 2018 - Adjusted EBITDA increased$42.5 million primarily as a result of the following: • an increase of$56.5 million from higher transportation services due
primarily to firm transportation capacity contracted due to our completed
expansion projects; and
• an increase of $4.9 million from higher equity in net earnings dueprimarily to firm transportation capacity contracted on Roadrunner; offset
partially by
• an increase of $11.6 million in operating costs due primarily toemployee-related costs associated with labor and benefits and ad valorem
taxes due to the growth of our operations; and
• a decrease of $9.1 million from lower net retained fuel and timing of
equity gas sales.
Capital expenditures decreased due primarily to timing of maintenance projects
and capital-growth projects.
Years Ended December 31,
Operating Information (a) 2019 2018 2017
Natural gas transportation capacity contracted
(MDth/d) 7,618 6,846 6,611
Transportation capacity contracted 98 % 96
% 94 %
(a) - Includes volumes for consolidated entities only.
2019 vs. 2018 - Natural gas transportation capacity contracted increased due to our completed expansion projects on our ONEOK Gas Transportation and WesTex Transmission systems, which are both substantially contracted.
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Roadrunner, in which we have a 50% ownership interest, has contracted all of its westbound capacity through 2041.
InJune 2019 , our subsidiary,Viking Gas Transmission Company , filed a proposed change in rates pursuant to Section 4 of the Natural Gas Act with theFERC . InFebruary 2020 , all parties agreed to a settlement in principle and plan to present it toFERC for approval. We do not expect the ultimate outcome to impact materially our results of operations.
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. 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 share 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) 2019 2018 2017
Reconciliation of net income to adjusted EBITDA (Thousands of dollars)
Net income $ 1,278,577 $ 1,155,032 $ 593,519
Add:
Interest expense, net of capitalized interest 491,773 469,620 485,658
Depreciation and amortization 476,535 428,557 406,335
Income taxes 372,414 362,903 447,282
Impairment charges - - 20,240
Noncash compensation expense 26,699 37,954 13,421
Equity AFUDC and other noncash items (a) (65,811 ) (6,545 ) 20,398
Adjusted EBITDA $ 2,580,187 $ 2,447,521 $ 1,986,853
Reconciliation of segment adjusted EBITDA to
adjusted EBITDA
Segment adjusted EBITDA:
Natural Gas Gathering and Processing $ 702,650 $ 631,607 $ 518,472
Natural Gas Liquids 1,465,765 1,440,605 1,154,939
Natural Gas Pipelines 408,816 366,251 339,818
Other (b) 2,956 9,058 (26,376 )
Adjusted EBITDA $ 2,580,187 $ 2,447,521 $ 1,986,853
(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.
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 affect adversely our consolidated results of operations, financial position or cash flows.
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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 to decrease in 2020 relative to 2019 due to our completed capital-growth projects. We expect dividends paid to continue to increase due to earnings growth from capital projects and higher anticipated dividends per share, subject to declaration by our Board of Directors. We expect our sources of cash inflows 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, which expires inJune 2024 , provides 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 and the ability to issue equity and other securities under our universal shelf registration statement. We manage interest-rate risk through the use of fixed-rate debt, floating-rate debt and interest-rate swaps. 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 toFERC 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 and our$2.5 Billion Credit Agreement. As ofDecember 31, 2019 , we were in compliance with all covenants of the$2.5 Billion Credit Agreement. AtDecember 31, 2019 , we had no borrowings outstanding under our$2.5 Billion Credit Agreement,$220 million of commercial paper outstanding and$21.0 million of cash and cash equivalents. We had working capital (defined as current assets less current liabilities) deficits of$550.0 million and$709.8 million as ofDecember 31, 2019 , andDecember 31, 2018 , respectively. Although working capital is influenced by several factors, including, among other things: (i) the timing of (a) debt and equity issuances, (b) the funding of capital expenditures, (c) scheduled debt payments, and (d) the collection and payment of accounts receivable and payable; and (ii) the volume and cost of inventory and commodity imbalances; our working capital deficit atDecember 31, 2019 , was driven primarily by short-term borrowings and accrued interest and atDecember 31, 2018 , by current maturities of long-term debt. 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. Our decision to utilize short-term borrowings rather than long-term debt was due to more favorable interest rates. We do not expect this working capital deficit to affect adversely 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 - InAugust 2019 , we completed an underwritten public offering of$2.0 billion senior unsecured notes consisting of$500 million , 2.75% senior notes due 2024;$750 million , 3.4% senior notes due 2029; and$750 million , 4.45% senior notes due 2049. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, were 42
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InMarch 2019 , we completed an underwritten public offering of$1.25 billion senior unsecured notes consisting of$700 million , 4.35% senior notes due 2029 and an additional issuance of$550 million of our existing 5.2% senior notes due 2048. The net proceeds, after deducting underwriting discounts, commissions and offering expenses, and exclusive of accrued interest, were$1.23 billion . The proceeds were used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures. InNovember 2018 , we entered into our$1.5 Billion Term Loan Agreement with a syndicate of banks, which was fully drawn as ofJune 30, 2019 . We repaid$250 million of our outstanding balance inAugust 2019 and have$1.25 billion drawn as ofDecember 31, 2019 . Our$1.5 Billion Term Loan Agreement matures inNovember 2021 and bears interest at LIBOR plus 112.5 basis points based on our current credit ratings. The agreement contains substantially the same covenants as those contained in our$2.5 Billion Credit Agreement. The proceeds were used for general corporate purposes, including repayment of existing indebtedness and funding capital expenditures. Debt Repayments - InSeptember 2019 , we redeemed our$300 million , 3.8% senior notes dueMarch 2020 at a redemption price of$308.0 million , including the outstanding principal, plus accrued and unpaid interest, with cash on hand from our public offering of$2.0 billion senior unsecured notes inAugust 2019 .
In
In
For additional information on our long-term debt, see Note F of the Notes to Consolidated Financial Statements in this Annual Report.
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 and short- and long-term debt.
The following table sets forth our growth and maintenance capital expenditures, excluding AFUDC and capitalized interest, for the periods indicated: Capital Expenditures
2019 2018 2017
(Millions of dollars)
Natural Gas Gathering and Processing $ 926.5 $ 694.6 $ 284.2
Natural Gas Liquids 2,796.6 1,306.3 114.3
Natural Gas Pipelines 99.2 119.2 95.6
Other 26.0 21.4 18.3
Total capital expenditures $ 3,848.3 $ 2,141.5 $ 512.4
Capital expenditures increased in 2019, compared with 2018, due primarily to
capital-growth projects in progress. We expect our 2020 capital expenditures to
decrease relative to 2019 due to our completed capital-growth projects. See
discussion of our announced capital-growth projects in the "Recent Developments"
section.
The following table summarizes our 2020 projected growth and maintenance capital expenditures, excluding AFUDC and capitalized interest:
2020 Projected Capital Expenditures
(Millions of dollars)
Growth $2,250-$2,730
Maintenance $200-$220 Total projected capital expenditures
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Credit Ratings - Our long-term debt credit ratings as ofFebruary 18, 2020 , are shown in the table below: Rating Agency Long-Term Rating Short-Term Rating Outlook Moody's Baa3 Prime-3 Positive 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 our$2.5 Billion Credit Agreement and our$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$2.5 Billion Credit Agreement, which expires in 2024. 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 2019, we paid dividends of$3.53 per share, an increase of 9% compared with the prior year. InFebruary 2020 , we paid a quarterly dividend of$0.935 per share ($3.74 per share on an annualized basis), an increase of 9% 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% per year. In 2019, we paid dividends of$1.1 million for the Series E Preferred Stock. InFebruary 2020 , we paid quarterly dividends totaling$0.3 million for the Series E Preferred Stock. For the years endedDecember 31, 2019 and 2018, cash flows from operations exceeded cash dividends paid by$489.2 million and$851.7 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.
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The following table sets forth the changes in cash flows by operating, investing and financing activities for the periods indicated:
Years Ended December 31,
2019 2018 2017
(Millions of dollars)
Total cash provided by (used in):
Operating activities $ 1,946.8 $ 2,186.7 $ 1,315.4
Investing activities (3,768.8 ) (2,114.9 ) (567.6 )
Financing activities 1,831.0 (97.0 ) (959.5 )
Change in cash and cash equivalents 9.0 (25.2 ) (211.7 )
Cash and cash equivalents at beginning of period 12.0 37.2 248.9
Cash and cash equivalents at end of period
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. 2019 vs. 2018 - Cash flows from operating activities, before changes in operating assets and liabilities, increased$130.4 million due primarily to higher earnings resulting from volume growth in theRocky Mountain region, STACK and SCOOP areas and thePermian Basin in our Natural Gas Liquids segment and theWilliston Basin and STACK and SCOOP areas in our Natural Gas Gathering and Processing segment, as discussed in "Financial Results and Operating Information." The changes in operating assets and liabilities decreased operating cash flows$163.9 million for 2019, compared with an increase of$206.4 million for 2018. This change is due primarily to the change in the fair value of our risk-management assets and liabilities; 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 natural gas and NGLs in storage, which vary both from period to period and with the changes in commodity prices.
Investing Cash Flows
2019 vs. 2018 - Cash used in investing activities increased
Financing Cash Flows
2019 vs. 2018 - Cash from financing activities increased
Cash Flow Analysis for the Year EndedDecember 31, 2018 vs. 2017 - The cash flow analysis for the year endedDecember 31, 2018 , compared with the year endedDecember 31, 2017 , is included in Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of our 2018 Annual Report on Form 10-K, which is available via theSEC's website at www.sec.gov and our website at www.oneok.com.
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
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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. Our commodity price risk includes basis risk, which is the difference in price between various locations where commodities are purchased and sold. We record all derivative instruments at fair value, except for normal purchases and normal sales transactions that are expected to result in physical delivery. Many of the contracts in our derivative portfolio are executed in liquid markets where price transparency exists. Our fair value measurements classified as Level 3 are composed predominantly of exchange-cleared and over-the-counter derivatives to hedge NGL price risk and natural gas basis risk between various transaction locations and the NYMEX Henry Hub. These measurements are based on inputs that may include one or more unobservable inputs, including internally developed commodity price curves, that incorporate market data from broker quotes and third-party pricing services. 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 atDecember 31, 2019 , 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 ofGoodwill and Long-Lived Assets, Including Intangible Assets - We assess our goodwill for impairment at least annually onJuly 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. Update - Upon adoption of ASU 2017-04 inJanuary 2020 , the requirement to calculate the implied fair value of goodwill under the two-step impairment test was eliminated. See Note A of the Notes to Consolidated Financial Statements in this Annual Report for more information. Our qualitative goodwill impairment analysis performed as ofJuly 1, 2019 , 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. 46
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The following table sets forth our goodwill, by segment, for the periods indicated:
December 31, December 31,
2019 2018
(Thousands of dollars)
Natural Gas Gathering and Processing $ 153,404 $ 153,404
Natural Gas Liquids 371,217 371,217
Natural Gas Pipelines 156,375 156,479
Total goodwill $ 680,996 $ 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 certain 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 2019, 2018 or 2017. 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.
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CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS
The following table sets forth our contractual obligations related to debt, leases and other long-term obligations as ofDecember 31, 2019 . For additional discussion of the debt and lease agreements, see Notes F and O of the Notes to Consolidated Financial Statements in this Annual Report. Payments Due by Period Contractual Obligations Total 2020 2021 2022 2023 2024 Thereafter (Millions of dollars) Senior notes$ 11,322.4 $ - $ -$ 1,447.4 $ 925.0 $ 500.0 $ 8,450.0 Commercial paper borrowings 220.0 220.0 - - - - -$1.5 Billion Term Loan Agreement 1,250.0 - 1,250.0 - - - - Guardian Pipeline senior notes 21.3 7.7 7.7 5.9 - - - Interest payments on debt 8,754.2 610.2 601.2 530.8 487.2 442.5 6,082.3 Operating leases 19.6 2.5 2.1 2.0 1.9 1.9 9.2 Finance lease 39.6 4.5 4.5 4.5 4.5 4.5 17.1 Firm transportation and storage contracts 398.4 61.6 48.1 40.1 36.4 34.3 177.9 Financial and physical derivatives 188.1 168.0 20.1 - - - - Employee benefit plans 81.8 14.1 14.6 13.1 14.5 13.8 11.7 Purchase commitments and other 312.7 54.1 53.9 53.2 50.8 37.8 62.9 Total$ 22,608.1 $ 1,142.7 $ 2,002.2 $ 2,097.0 $ 1,520.3 $ 1,034.8 $ 14,811.1
Senior notes,
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 certain buildings, warehouses, office space, pipeline capacity, land and equipment, including pipeline equipment, rail cars and information technology equipment. As ofDecember 31, 2019 , we entered into an additional operating lease that had not yet commenced with total lease payments of$87.8 million over a lease term of 10 years, which is excluded from our table above.
Finance lease - We lease certain compression facilities under a finance 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 atDecember 31, 2019 . 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$12.1 million to our defined benefit pension plan inJanuary 2020 and expect to make$2.0 million in contributions to our other postretirement plans in 2020. 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
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natural gas and NGL pipelines, processing and fractionation 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," "believe," "continue," "could," "estimate," "expect," "forecast," "goal," "guidance," "intend," "may," "might," "outlook," "plan," "potential," "project," "scheduled," "should," "will," 'would," 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: • 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 drill and obtain necessary permits; regulatory compliance;
reserve performance; and capacity constraints on the pipelines that
transport crude oil, natural gas and NGLs from producing areas and our
facilities;
• 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;
• 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;
• demand for our services and products in the proximity of our facilities;
• 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
- availability of additional storage capacity;
• the effects of weather and other natural phenomena, including climate
change, on our operations, demand for our services and energy prices;
• acts of nature, sabotage, terrorism or other similar acts that cause
damage to our facilities or our suppliers', customers' or shippers'
facilities;
• the possibility of future terrorist attacks or the possibility oroccurrence of an outbreak of, or changes in, hostilities or changes in the
political conditions throughout the world;
• economic climate and growth in the geographic areas in which we do business;
• the timing and extent of changes in energy commodity prices;
• 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 profitability of assets or businesses acquired or constructed by us;
• the risk of a slowdown in growth or decline in
international economies, including liquidity risks in
foreign credit markets;
• 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;
• 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 uncontracted capacity in our assets being greater or less
than expected;
• 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;
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• our ability to control construction costs and completion schedules of our
pipelines and other projects;
• 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 ability to recover operating costs and amounts equivalent to income
taxes, costs of property, plant and equipment and regulatory assets in our
state and
• the results of administrative proceedings and litigation, regulatory
actions, executive orders, 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 the CFTC;
• difficulties or delays experienced by trucks, railroads or pipelines in
delivering products to or from our terminals or pipelines;
• the capital-intensive nature of our businesses;
• the mechanical integrity of facilities operated;
• 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 risk that material weaknesses or significant deficiencies in ourinternal controls over financial reporting could emerge or that minor
problems could become significant;
• 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;
• our ability to access capital at competitive rates or on terms acceptable
to us;
• the impact and outcome of pending and future litigation;
• performance of contractual obligations by our customers, service
providers, contractors and shippers;
• our ability to control operating costs and make cost-saving changes;
• the impact of recently issued and future accounting updates and other
changes in accounting policies;
• the risk of increased costs for insurance premiums, security or other
items as a consequence of terrorist attacks;
• the risk inherent in the use of information systems in our respective
businesses and those of our counterparties and service providers,
implementation of new software and hardware, and the impact on the
timeliness of information for financial reporting;
• the impact of potential impairment charges; and
• the risk factors listed in the reports we have filed and may file with the
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 affect adversely 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 theSEC , which are available via theSEC'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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