TALLGRASS ENERGY, LP The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes thereto included elsewhere in this Annual Report. The discussion and analysis for the year endedDecember 31, 2018 compared to the year endedDecember 31, 2017 can be found in our Annual Report on Form 10-K for the year endedDecember 31, 2018 and should be read in conjunction with the discussion and analysis below. Overview TGE is a limited partnership that owns, operates, acquires and develops midstream energy assets inNorth America and has elected to be treated as a corporation forU.S. federal income tax purposes. Our operations are conducted through, and our operating assets are owned by, our direct and indirect subsidiaries, including Tallgrass Equity, in which we directly own an approximate 63.75% membership interest as ofFebruary 12, 2020 . We are located in and provide services to certain keyUnited States hydrocarbon basins, including theDenver -Julesburg ,Powder River , Wind River, Permian and Hugoton-Anadarko Basins and the Niobrara, Mississippi Lime,Eagle Ford , Bakken, Marcellus, and Utica shale formations. 61 --------------------------------------------------------------------------------
Our reportable business segments are:
• Natural Gas Transportation-the ownership and operation of
interstate natural gas pipelines and an integrated natural gas storage
facility;
• Crude Oil Transportation-the ownership and operation of
crude oil pipeline systems; and
• Gathering, Processing & Terminalling-the ownership and operation of
natural gas gathering and processing facilities; crude oil storage and
terminalling facilities; the provision of water business services
primarily to the oil and gas exploration and production industry; the
transportation of NGLs; and the marketing of crude oil and NGLs.
Additional information about our operations and assets is contained in the
business overview included in Item 1.-Business under "Overview" and "Our
Assets."
Summary of Results for the Year Ended December 31, 2019
Net income for the year ended December 31, 2019 was $448.6 million , with
Adjusted EBITDA and Cash Available for Dividends (each as defined below under
"Non-GAAP Financial Measures") of $996.3 million and $798.2 million ,
respectively, compared to net income for the year ended December 31,
2018 of $467.7 million , with Adjusted EBITDA and Cash Available for Dividends
of $654.4 million and $548.7 million , respectively. The decrease in net income
and the increase in Adjusted EBITDA and Cash Available for Dividends was largely
driven by our increased ownership in TEP due to the TEP Merger.
Recent Developments
Take Private Proposal
As discussed in Item 1.-Business, "Organizational Structure," on December 16,
2019 , we and our general partner entered into the Take-Private Merger Agreement
pursuant to which the Take-Private Merger will occur. At the Effective Time,
each issued and outstanding Class A share other than the Class A shares owned by
the Sponsor Entities and certain of their permitted transferees, will be
converted into the right to receive $22.45 per Class A share in cash without any
interest thereon. Through the Take-Private Merger, the Sponsor Entities and the
limited partners of Buyer immediately prior to the Effective Time will become
the owners of all of the outstanding Class A shares and the Class A shares will
cease to be publicly traded upon closing of the Take-Private Merger.
The Take-Private Merger Agreement is subject to the satisfaction of customary
conditions, including approval of the merger by holders of a majority of the
outstanding Class A and Class B shares of TGE, voting together as a single
class, inclusive of the approximately 44.1% of the total Class A and Class B
shares held by the Sponsors Entities as of December 31, 2019 . As discussed
further in Item 7.-Management's Discussion and Analysis of Financial Condition
and Results of Operations, "Dividends," pursuant to the Take-Private Merger
Agreement, TGE has agreed not to pay dividends during the pendency of the
transactions contemplated by the Take-Private Merger Agreement.
Rockies Express Senior Notes Offerings
On January 31, 2020 , Rockies Express issued $750 million in aggregate principal
amount of senior notes. The issuance was composed of two tranches, $400 million
of 3.60% senior notes due 2025 and $350 million of 4.80% senior notes due 2030.
The proceeds of the issuance will be used to redeem the 5.625% senior notes due
April 15, 2020 in March 2020 .
Factors and Trends Impacting Our Business
We expect to continue to be affected by certain key factors and trends described
below. Our expectations are based on assumptions made by us and information
currently available to us. To the extent our underlying assumptions about, or
interpretations of, available information prove to be incorrect, our actual
results may vary materially from our expected results. See also Item 1A.-Risk
Factors.
Long-Term U.S. Crude Oil and Natural Gas Prospects
Crude oil, natural gas, and products derived from both continue to be critical
components of energy supply and demand in the United States . Crude oil and
natural gas prices have declined and experienced significant volatility in
recent years. While there have been periods of stability in crude oil and
natural gas prices during that time, price declines and volatility may continue
to occur in commodity markets in the future. Despite this volatility, we believe
long-term prospects for continued domestic crude oil and natural gas production
increases are favorable.
We believe long-term growth will be driven, in part, by a combination of
increased domestic demand resulting from population and economic growth, higher
industrial consumption in the U.S. spurred by the lower commodity price of
feedstock and fuel, and a desire to reduce domestic reliance on imports. One
example is that we expect natural gas to gradually displace coal-fired
electricity generation due to the low prices of natural gas and stricter
environmental regulations on the mining and
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burning of coal. Additionally, we believe that the U.S. will continue to
increase its total volume exported of both natural gas and crude oil as new and
additional infrastructure is developed to export these commodities. We expect
productivity of oil and natural gas wells to continue increasing over the
long-term in some basins across the United States because of the increasing
precision and efficiency of horizontal drilling and hydraulic fracturing in oil
and natural gas extraction. We also believe there is a substantial inventory of
drilled but uncompleted wells in the basins we serve, including the Bakken shale
and Denver -Julesburg basin, that are likely to be completed and turned into
production as commodity prices stabilize and continue to recover.
Current Commodity Environment
During the last several years, prices of crude oil, natural gas, and NGLs have
experienced periods of price stability as well as periods of decline and
significant volatility. To the extent some of our customers remain concerned
about extended unfavorably low prices as has been experienced with sustained
lower natural gas prices throughout 2019, it may be due to concerns over excess
supply, truncation of current OPEC production cuts and increased mainstream use
of alternative sources of energy.
Demand for our services depends, in part, on the development of additional
natural gas and crude oil reserves by third parties. This requires significant
capital expenditures by others to install facilities that extract natural gas
and crude oil. However, the possibility for low commodity prices may result in a
lack of available capital for these types of expenditures. To the extent our
customers cannot finance these activities, we expect they may be less likely to
enter into demand based, long-term firm fee contracts. Low commodity prices may
also negatively impact the financial condition of our customers and could impact
their ability to meet their financial obligations to us.
Additionally, lower commodity prices may lead to reduced utilization of our
assets. For example, reduced utilization could result in increased deficiency
balances held by customers of our Pony Express System. For additional
information, see Item 1A.-Risk Factors, "The Throughput and Deficiency
Agreements for the Pony Express System and some of our service agreements with
respect to our water business services contain provisions that can reduce the
cash flow stability that the agreements were designed to achieve." and "Any
significant decrease in available supplies of hydrocarbons in our areas of
operation, or redirection of existing hydrocarbon supplies to other markets,
could adversely affect our business and operating results. Persistent low
commodity prices could result in lower throughput volumes and reduced cash
flows."
Growth Associated with Acquisitions and Expansion Projects
Growth associated with acquisitions
We believe that we are well-positioned to grow through accretive acquisitions
due to our stable financial profile and diverse asset base that presents many
logical strategic opportunities. In the past, we heavily relied on acquiring
assets from TD's portfolio of midstream assets. Now that TD has divested its
entire asset portfolio, our growth through acquisitions will rely almost
exclusively on buying assets or businesses from third parties. Third party
acquisitions present different risks than those associated with acquiring assets
from TD. Sourcing attractive, accretive opportunities and performing diligence
on those opportunities requires significantly more time from our employees. Most
third party acquisitions involve competition from other buyers, which generally
increases the purchase price. If we are able to execute a third-party
transaction, we may encounter challenges when integrating different work
cultures and operational systems. During 2019, we executed several third party
acquisitions and joint ventures, including the acquisition of CES and the Powder
River Gateway joint venture with Silver Creek . For additional information, see
Note 3 - Acquisitions and Dispositions.
Growth associated with expansion projects
We also believe that we are well positioned to increase volumes to our systems
through cost-effective capacity expansions and other methods for improving
efficiency. For example, in 2019, Powder River Gateway placed the Iron Horse
Pipeline in-service and we continued to execute the development and construction
of the Cheyenne Hub Enhancement Project at Rockies Express and the Cheyenne
Connector Pipeline with our joint venture partner DCP. In 2018, Pony Express
placed the Platteville Extension Project in-service and in 2017, Rockies Express
placed in-service the Zone 3 Capacity Enhancement Project , which added an
incremental 0.8 Bcf/d of east-to-west capacity within Zone 3 of the Rockies
Express Pipeline .
Energy Capital Markets and Interest Rates
In recent years, investors have required higher yields on our Class A shares,
which has led to decreased prices and limited our ability to complete equity
offerings at favorable pricing. As a result, we have had to alter financing
strategies and rely primarily on debt issuances and internally generated cash
flow to fund growth capital expenditures and acquisitions. In 2017 and 2018, TEP
was able to issue an additional $1.6 billion in aggregate principal amount of
senior notes with rates from 4.75% to 5.5%. In 2019 and 2020, Rockies Express
was able to issue an additional $1.3 billion in aggregate principal amount of
senior notes with rates from 3.60% to 4.95%. For additional information
regarding the impact of changes in interest rates on our existing debt, please
read Item 7A.-Quantitative and Qualitative Disclosures About Market Risk.
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How We Evaluate Our Operations
We evaluate our results using, among other measures, contract profile and
volumes, operating costs and expenses, Adjusted EBITDA and Cash Available for
Dividends. Adjusted EBITDA and Cash Available for Dividends are non-GAAP
measures and are defined below.
Contract Profile and Volumes
Our results are driven primarily by the volume of natural gas transportation and
storage capacity, crude oil transportation, storage, and terminalling capacity,
NGL transportation capacity, and water transportation, gathering, recycling and
disposal capacity under firm fee contracts, as well as the volume of natural gas
that we gather and process and the fees assessed for such services.
Operating Costs and Expenses
The primary components of operating costs and expenses that we evaluate include
cost of sales, cost of transportation services, operations and maintenance and
general and administrative costs. Operating expenses are driven primarily by
expenses related to the operation, maintenance and growth of our asset base.
Adjusted EBITDA and Cash Available for Dividends
Adjusted EBITDA and Cash Available for Dividends are non-GAAP supplemental
financial measures that management and external users of our consolidated
financial statements, such as industry analysts, investors, lenders and rating
agencies, may use to assess:
• our operating performance as compared to other publicly traded midstream
infrastructure companies, without regard to historical cost basis or, in
the case of Adjusted EBITDA, financing methods;
• the ability of our assets to generate sufficient cash flow to make
dividends to our shareholders;
• our ability to incur and service debt and fund capital expenditures; and
• the viability of acquisitions and other capital expenditure projects and
the returns on investment of various expansion and growth opportunities.
We believe that the presentation of Adjusted EBITDA and Cash Available for
Dividends provides useful information to investors in assessing our financial
condition and results of operations. Adjusted EBITDA and Cash Available for
Dividends should not be considered alternatives to net income, operating income,
net cash provided by operating activities or any other measure of financial
performance or liquidity presented in accordance with GAAP, nor should Adjusted
EBITDA and Cash Available for Dividends be considered alternatives to available
cash or other definitions in our partnership agreement. Adjusted EBITDA and Cash
Available for Dividends have important limitations as analytical tools because
they exclude some but not all items that affect net income and net cash provided
by operating activities. Additionally, because Adjusted EBITDA and Cash
Available for Dividends may be defined differently by other companies in our
industry, our definition of Adjusted EBITDA and Cash Available for Dividends may
not be comparable to similarly titled measures of other companies, thereby
diminishing their utility.
Non-GAAP Financial Measures
We generally define Adjusted EBITDA as net income excluding the impact of
interest, income taxes, depreciation and amortization, non-cash income or loss
related to derivative instruments, non-cash long-term compensation expense,
impairment losses, gains or losses on asset or business disposals or
acquisitions, gains or losses on the repurchase, redemption or early retirement
of debt, and earnings from unconsolidated investments, but including the impact
of distributions from unconsolidated investments and deficiency payments
received from or utilized by our customers. We also use Cash Available for
Dividends, which we generally define as Adjusted EBITDA, less cash interest
costs, maintenance capital expenditures, current income tax, and certain cash
reserves permitted by our governing documents. Adjusted EBITDA and Cash
Available for Dividends are both calculated and presented at the Tallgrass
Equity level, before consideration of noncontrolling interest associated with
the Exchange Right Holders or calculating distributions from Tallgrass Equity to
us, on one hand, and to the Exchange Right Holders, on the other. We believe
calculating these measures at Tallgrass Equity provides investors the most
complete and comparable picture of our overall financial and operational results
and provides a consistent metric for period over period comparisons that is not
impacted by any future exercises by the Exchange Right Holders of the Exchange
Right, which does not have a dilutive effect on TGE's net income per share.
Maintenance capital expenditures are cash expenditures incurred (including
expenditures for the construction or development of new capital assets) that we
expect to maintain our long-term operating income or operating capacity. These
expenditures typically include certain system integrity, compliance and safety
improvements, and are presented net of noncontrolling interest and
reimbursements.
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We collect deficiency payments for volumes committed by our customers to be
transported in a month but not physically received for transport or delivered to
the customers' agreed upon destination point. These deficiency payments are
recorded as a deferred liability until the barrels are physically transported
and delivered, or when the likelihood that the customer will utilize the
deficiency balance becomes remote.
Adjusted EBITDA and Cash Available for Dividends are not presentations made in
accordance with GAAP. The following table presents a reconciliation of Adjusted
EBITDA to Net income (loss) attributable to TGE and net cash provided by
operating activities and a reconciliation of Cash Available for Dividends to net
cash provided by operating activities, the most directly comparable GAAP
financial measures, for each of the periods indicated:
Year Ended December 31,
2019 2018 2017
(in thousands)
Reconciliation of Tallgrass Equity Adjusted
EBITDA to Net income (loss) attributable to TGE
Net income (loss) attributable to TGE $ 248,809 $ 137,127 $ (128,729 )
Add:
Interest expense, net (1) 161,429 95,465 29,403
Depreciation and amortization expense (1) 127,503 74,998
26,131
Distributions from unconsolidated investments (1) 470,981 302,364
86,551
Deficiency payments, net (1) 16,992 14,443
7,701
Non-cash compensation expense (1)(2) 31,563 8,634 2,682 Loss on debt retirement - 2,245 - Income tax expense (1) 70,578 55,709 208,458 Net income attributable to Exchange Right Holders 193,961 208,618
137,849
Less:
Equity in earnings of unconsolidated investments (1) (325,385 ) (237,197 ) (66,922 ) Other non-cash (gain) (724 ) - - Loss (gain) on disposal of assets (1) 354 (4,630 ) (189 ) Non-cash loss (gain) related to derivative instruments (1) 272 (3,340 )
64
(Gain) on remeasurement of unconsolidated investment (1) - - (2,744 ) Tallgrass Equity Adjusted EBITDA$ 996,333 $ 654,436 $ 300,255 Reconciliation of Tallgrass Equity Adjusted EBITDA and Cash Available for Dividends to Net Cash Provided by Operating Activities Net cash provided by operating activities$ 679,006 $ 672,525 $ 571,396 Add: Interest expense, net (1) 161,429 95,465
29,403
Other, including changes in operating working capital (1) 155,898 (113,554 ) (300,544 ) Tallgrass Equity Adjusted EBITDA$ 996,333 $ 654,436 $ 300,255 Less: Cash interest cost (1) (155,174 ) (91,590 ) (27,669 ) Maintenance capital expenditures, net (1) (42,287 ) (14,176 ) (4,179 ) Current income tax expense (1) (672 ) - -
Tallgrass Equity Cash Available for Dividends
$ 268,407 (1) Net of noncontrolling interest associated with less than wholly-owned subsidiaries of Tallgrass Equity.
(2) Represents TGE's portion of non-cash compensation expense related to Equity
Participation Shares and TEP's Equity Participation Units, excluding amounts
allocated to Tallgrass Development prior to the TD Merger on February 7,
2018 .
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The following table presents a reconciliation of Adjusted EBITDA by segment to
segment operating income, the most directly comparable GAAP financial measure,
for each of the periods indicated:
Year Ended December 31,
2019 2018 2017
(in thousands)
Reconciliation of Tallgrass Equity Adjusted
EBITDA to Operating Income in the Natural Gas
Transportation Segment (1)
Operating income $ 66,200 $ 69,586 $ 67,434
Add:
Depreciation and amortization expense (2) 19,773 13,102 5,421
Distributions from unconsolidated investments (2) 458,739 297,496 85,994 Less: Other, net (2) (1,205 ) 2,359 1,424 Adjusted EBITDA attributable to noncontrolling interests - (5,319 ) 20,738 Non-cash (gain) related to derivative instruments (2) - - (33 ) Tallgrass Equity Segment Adjusted EBITDA$ 543,507 $ 377,224 $ 180,978 Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Crude Oil Transportation Segment (1) Operating income$ 273,303 $ 258,308 $ 190,170 Add: Depreciation and amortization expense (2) 55,699 36,578
16,156
Deficiency payments, net (2) 9,867 4,858
7,967
Distributions from unconsolidated investments 5,464 - -
Less:
Adjusted EBITDA attributable to noncontrolling interests - (60,414 ) (73,385 ) Non-cash (gain) related to derivative instruments (2) - - (123 ) Tallgrass Equity Segment Adjusted EBITDA$ 344,333 $ 239,330 $ 140,785 Reconciliation of Tallgrass Equity Adjusted EBITDA to Operating Income in the Gathering, Processing & Terminalling Segment (1) Operating income$ 60,787 $ 51,565 $ 33,453 Add: Depreciation and amortization expense (2) 48,730 21,665
4,554
Non-cash loss (gain) related to derivative instruments (2) 272 (3,340 ) 750 Distributions from unconsolidated investments (2) 6,778 4,868
557
Deficiency payments, net (2) 9,356 8,540 (458 ) Loss (gain) on disposal of assets (2) 354 (4,630 ) (189 ) Other, net (2) 1,384 182 142 Less: Other non-cash (gain) (724 ) - - Adjusted EBITDA attributable to noncontrolling interests (5,778 ) (19,647 ) (22,726 ) Tallgrass Equity Segment Adjusted EBITDA$ 121,159 $ 59,203 $ 16,083 Total Tallgrass Equity Segment Adjusted EBITDA$ 1,008,999 $ 675,757 $ 337,846 Corporate general and administrative costs (12,666 ) (21,321 ) (37,591 ) Total Tallgrass Equity Adjusted EBITDA$ 996,333 $ 654,436
(1) Segment results as presented represent total operating income and Adjusted
EBITDA, including intersegment activity, for the Natural Gas Transportation,
Crude Oil Transportation, and Gathering, Processing & Terminalling segments.
For reconciliations to the consolidated financial data, see Note 21 -
Reportable Segments to the accompanying consolidated financial statements.
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(2) Net of noncontrolling interest associated with less than wholly-owned
subsidiaries of Tallgrass Equity.
Results of Operations
The following provides a summary of our average daily operating metrics for the
periods indicated:
Year Ended December 31,
2019 2018 2017
(in thousands, except operating data)
Natural Gas Transportation Segment:
TIGT and Trailblazer average firm contracted
volumes (MMcf/d) (1) 1,850 1,636 1,711
Rockies Express average firm contracted volumes
(MMcf/d) (2) 4,101 4,101 4,101
Crude Oil Transportation Segment:
Pony Express average contracted capacity
(Bbls/d) 311,101 306,936 301,936
Pony Express average throughput (Bbls/d) 358,442 336,314 267,734
Gathering, Processing & Terminalling Segment:
Natural gas processing inlet volumes (MMcf/d) 118 122 109
Freshwater average volumes (Bbls/d) 52,133 17,849 69,139
Produced water gathering and disposal average
volumes (Bbls/d) 182,292 98,489 31,511
(1) Volumes contracted under firm fee contracts, excluding Rockies Express.
(2) Volumes contracted under long-term firm fee contracts.
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The following provides a summary of our consolidated results of operations for
the periods indicated:
Year Ended December 31,
2019 2018 2017
(in thousands)
Revenues:
Crude oil transportation services $ 417,106 $ 398,334 $ 345,733
Natural gas transportation services 129,620 126,894 122,364
Sales of natural gas, NGLs, and crude oil 171,729 168,586
108,503
Processing and other revenues 150,093 99,445 79,298
Total Revenues 868,548 793,259 655,898
Operating Costs and Expenses:
Cost of sales 94,816 114,815 91,213
Cost of transportation services 63,258 53,068 46,200
Operations and maintenance 88,474 72,460
62,069
Depreciation and amortization 128,825 110,862
90,800
General and administrative 104,373 70,656
65,536
Taxes, other than income taxes 35,669 31,810
28,832
Loss (gain) on disposal of assets 373 (11,043 ) (599 ) Total Operating Costs and Expenses 515,788 442,628
384,051
Operating Income 352,760 350,631
271,847
Other Income (Expense): Equity in earnings of unconsolidated investments 325,385 306,819 237,110 Interest expense, net (161,407 ) (133,319 ) (89,348 ) Other income (expense), net 2,410 (751 ) 12,834 Total Other Income (Expense) 166,388 172,749 160,596 Net income before tax 519,148 523,380 432,443 Income tax expense (70,593 ) (55,709 ) (208,458 ) Net income 448,555 467,671 223,985 Net income attributable to noncontrolling interests (199,746 ) (330,544 ) (352,714 ) Net income (loss) attributable to TGE$ 248,809 $ 137,127
Year EndedDecember 31, 2019 Compared to the Year EndedDecember 31, 2018 Revenues. Total revenues were$868.5 million for the year endedDecember 31, 2019 compared to$793.3 million for the year endedDecember 31, 2018 , which represents an increase of$75.3 million , or 9%, in total revenues. The overall increase in revenue was largely driven by increased revenues of$56.2 million and$42.2 million in the Gathering, Processing & Terminalling and Crude Oil Transportation segments, respectively, partially offset by a$22.4 million increase in eliminations of intersegment revenue and decreased revenues of$0.7 million in the Natural Gas Transportation segment, as discussed further below. Operating costs and expenses. Operating costs and expenses were$515.8 million for the year endedDecember 31, 2019 compared to$442.6 million for the year endedDecember 31, 2018 , which represents an increase of$73.2 million , or 17%. The overall increase in operating costs and expenses was driven by increased operating costs and expenses of$47.0 million ,$27.2 million , and$2.7 million in the Gathering, Processing & Terminalling, Crude Oil Transportation, and Natural Gas Transportation segments, respectively, partially offset by decreased operating costs and expenses of$3.7 million in the Corporate and Other segment. The decrease in Corporate and Other expenses was primarily driven by a$22.4 million increase in eliminations of intersegment operating costs and expenses, partially offset by a$20.2 million increase in corporate general and administrative costs due to an increase in equity-based compensation costs related to the accelerated vesting of certain Equity Participation Shares as a result of theMarch 2019 Blackstone Acquisition and other events that occurred in 2019. 68 -------------------------------------------------------------------------------- Equity in earnings of unconsolidated investments. Equity in earnings of unconsolidated investments was$325.4 million and$306.8 million for the years endedDecember 31, 2019 and 2018, respectively. Equity in earnings of unconsolidated investments of$325.4 million for the year endedDecember 31, 2019 primarily reflects our portion of earnings and the$34.0 million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies Express, as well as equity in earnings related to our 51% membership interests inPawnee Terminal and Powder River Gateway of$5.9 million and$3.1 million , respectively. Equity in earnings of unconsolidated investments of$306.8 million for the year endedDecember 31, 2018 primarily reflects our portion of earnings and the$35.9 million of amortization of a negative basis difference associated with our aggregate 75% membership interest in Rockies Express, inclusive of the additional 25.01% membership interest acquired inFebruary 2018 , as well as$4.2 million of equity in earnings related to our 51% membership interest inPawnee Terminal . The overall increase was primarily driven by a$13.0 million increase in equity in earnings from Rockies Express as a result of lower interest expense due to the repayment of Rockies Express'$550 million of 6.85% senior notes dueJuly 15, 2018 and the refinancing of Rockies Express'$525 million of 6.00% senior notes dueJanuary 15, 2019 , the additional 25.01% membership interest acquired inFebruary 2018 , and the proceeds from the contract termination discussed in Note 20 - Legal and Environmental Matters. These increases were partially offset by lower west-end revenue as a result of contract expirations and the tax expense recognized during the year endedDecember 31, 2019 as a result of theOhio Supreme Court decision discussed in Note 20 - Legal and Environmental Matters. Interest expense, net. Interest expense of$161.4 million for the year endedDecember 31, 2019 was primarily composed of interest and fees associated with the Senior Notes and TEP revolving credit facility, as defined in Note 10 - Long-term Debt. Interest expense of$133.3 million for the year endedDecember 31, 2018 was primarily composed of interest and fees associated with the TEP and Tallgrass Equity revolving credit facilities and the 2024 Notes and 2028 Notes, as defined in Note 10 - Long-term Debt. The increase in interest and fees is primarily due to increased borrowings to fund a portion of our 2018 and 2019 acquisitions and a special contribution to Rockies Express to fund our pro rata portion of the repayment of Rockies Express'$550 million of 6.85% senior notes dueJuly 15, 2018 , as well as the higher borrowing rate on the 2023 Notes, the proceeds of which were used to repay borrowings under the revolving credit facility. Other income (expense), net. Other income (expense), net typically includes rental income and other income related to capital costs incurred to build new connections to our systems. Other income for the year endedDecember 31, 2019 was$2.4 million compared to other expense of$0.8 million for the year endedDecember 31, 2018 . Other expense of$0.8 million for the year endedDecember 31, 2018 also included a$2.2 million loss on debt retirement associated with the write off of deferred financing costs associated with the Amendment to the TEP revolving credit facility and the termination of the Tallgrass Equity revolving credit facility. Income tax expense. Income tax expense for the year endedDecember 31, 2019 was$70.6 million , compared to income tax expense of$55.7 million for the year endedDecember 31, 2018 . The increase in income tax expense was primarily due to our increased ownership in TEP effectiveJune 30, 2018 as a result of the TEP Merger and the exercise of the Exchange Right effectiveMarch 11, 2019 and the resulting increase in income allocated to TGE. 69 --------------------------------------------------------------------------------
The following provides a summary of our Natural Gas Transportation segment results of operations for the periods indicated: Segment Financial Data - Natural Gas
Year Ended December 31,
Transportation (1) 2019 2018 2017
(in thousands)
Revenues:
Natural gas transportation services $ 131,799 $ 131,555 $ 129,058
Sales of natural gas, NGLs, and crude oil 542 1,195 3,412
Processing and other revenues 7,411 7,709 8,551
Total revenues 139,752 140,459 141,021
Operating costs and expenses:
Cost of sales 1,218 1,382 2,767
Cost of transportation services 1,940 2,990 2,852
Operations and maintenance 28,734 27,185
28,910
Depreciation and amortization 19,773 19,442
19,180
General and administrative 16,962 15,279
15,385
Taxes, other than income taxes 4,925 4,595
4,493
Total operating costs and expenses 73,552 70,873 73,587 Operating income$ 66,200 $ 69,586 $ 67,434
(1) Segment results as presented represent total revenue and operating income,
including intersegment activity. For reconciliations to the consolidated
financial data, see Note 21 - Reportable Segments.
Year EndedDecember 31, 2019 Compared to the Year EndedDecember 31, 2018 Revenues. Natural Gas Transportation segment revenues were$139.8 million for the year endedDecember 31, 2019 compared to$140.5 million for the year endedDecember 31, 2018 , which represents a decrease of$0.7 million in segment revenues driven by a$0.7 million decrease in sales of natural gas due to decreased volumes sold and lower natural gas prices. Operating costs and expenses. Operating costs and expenses in the Natural Gas Transportation segment were$73.6 million for the year endedDecember 31, 2019 compared to$70.9 million for the year endedDecember 31, 2018 , which represents an increase of$2.7 million , or 4%. The overall increase in operating costs and expenses was primarily due to a$1.7 million increase in general and administrative costs driven by an increase in labor costs and a$1.5 million increase in operations and maintenance costs driven by increased pipeline integrity work. 70 --------------------------------------------------------------------------------
The following provides a summary of our Crude Oil Transportation segment results of operations for the periods indicated:
Year Ended December 31,
Segment Financial Data - Crude Oil Transportation (1) 2019 2018 2017
(in thousands)
Revenues:
Crude oil transportation services$ 474,987 $ 437,653 $ 353,395 Sales of natural gas, NGLs, and crude oil 10,830 6,290 11,179 Processing and other revenues 830 511 - Total revenues 486,647 444,454 364,574 Operating costs and expenses: Cost of sales 11,025 8,334 9,680 Cost of transportation services 80,122 68,184 57,284 Operations and maintenance 15,321 12,896 11,838 Depreciation and amortization 55,699 54,237 52,364 General and administrative 24,059 18,486 20,906 Taxes, other than income taxes 27,118 24,009 22,332 Total operating costs and expenses 213,344 186,146 174,404 Operating income$ 273,303 $ 258,308 $ 190,170
(1) Segment results as presented represent total revenue and operating income,
including intersegment activity. For reconciliations to the consolidated
financial data, see Note 21 - Reportable Segments.
Year EndedDecember 31, 2019 Compared to the Year EndedDecember 31, 2018 Revenues. Crude Oil Transportation segment revenues were$486.6 million for the year endedDecember 31, 2019 compared to$444.5 million for the year endedDecember 31, 2018 , which represents an increase of$42.2 million , or 9%, in segment revenues driven by a$37.3 million increase in crude oil transportation services and a$4.5 million increase in sales of crude oil due to increased volumes sold, partially offset by lower crude oil prices during the year endedDecember 31, 2019 . The increase in crude oil transportation services revenue was primarily due to a$19.2 million increase in walk-up shipper revenue and a$17.2 million increase in committed shipper revenues, both driven by increased throughput volumes and theFERC annual index adjustments effectiveJuly 1, 2018 and 2019. Operating costs and expenses. Operating costs and expenses in the Crude Oil Transportation segment were$213.3 million for the year endedDecember 31, 2019 compared to$186.1 million for the year endedDecember 31, 2018 , which represents an increase of$27.2 million , or 15%. The overall increase in operating costs and expenses was primarily due to a$11.9 million increase in cost of transportation services driven by higher throughput volumes during the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 , resulting in higher costs for drag reducing agents and pump station electrical costs as well as increased terminalling costs, a$5.6 million increase in general and administrative costs driven by an increase in insurance and labor costs, a$3.1 million increase in taxes, other than income taxes driven by an increase in property tax assessment estimates, a$2.7 million increase in cost of sales due to increased volumes sold partially offset by lower crude oil prices, and a$2.4 million increase in operations and maintenance costs driven by increased pipeline integrity work. 71 --------------------------------------------------------------------------------
The following provides a summary of our Gathering, Processing & Terminalling segment results of operations for the periods indicated: Segment Financial Data - Gathering, Processing
Year Ended December 31,
& Terminalling (1) 2019 2018 2017
(in thousands)
Revenues:
Sales of natural gas, NGLs, and crude oil
$ 93,998 Processing and other revenues 175,538 118,564 92,213 Total revenues 335,895 279,665 186,211 Operating costs and expenses: Cost of sales 82,981 105,985 80,088 Cost of transportation services 74,534 52,327
20,650
Operations and maintenance 44,419 32,379
21,321
Depreciation and amortization 50,052 32,369
19,256
General and administrative 19,123 12,877
10,035
Taxes, other than income taxes 3,626 3,206
2,007
Loss (gain) on disposal of assets 373 (11,043 ) (599 ) Total operating costs and expenses 275,108 228,100 152,758 Operating income$ 60,787 $ 51,565 $ 33,453
(1) Segment results as presented represent total revenue and operating income,
including intersegment activity. For reconciliations to the consolidated
financial data, see Note 21 - Reportable Segments.
Year EndedDecember 31, 2019 Compared to the Year EndedDecember 31, 2018 Revenues. Gathering, Processing & Terminalling segment revenues were$335.9 million for the year endedDecember 31, 2019 compared to$279.7 million for the year endedDecember 31, 2018 , which represents a$56.2 million , or 20%, increase in segment revenues. The increase in segment revenues was due to a$57.0 million increase in processing and other revenues, partially offset by a$0.7 million decrease in sales of natural gas, NGLs, and crude oil. The increase in processing and other revenues was driven by (i) increased water business services revenue of$50.0 million driven by the consolidation of BNN Colorado inDecember 2018 , the acquisitions of NGL Water Solutions Bakken inNovember 2018 and CES inMay 2019 , and increased produced water disposal and fresh water transportation volumes and (ii) increased terminal services revenue of$5.7 million driven by theBuckingham Terminal expansion, theNatoma Terminal placed into service inApril 2018 , theGrasslands Terminal placed into service inAugust 2019 , and increased throughput on the Pony Express System. The decrease in sales of natural gas, NGLs, and crude oil was driven by decreased sales of NGLs of$33.1 million , primarily due to lower NGL prices partially offset by higher volumes sold, partially offset by increased crude oil sales of$26.1 million at Stanchion and increased sales of natural gas of$6.4 million due to higher volumes sold, partially offset by lower natural gas prices. Operating costs and expenses. Operating costs and expenses in the Gathering, Processing & Terminalling segment were$275.1 million for the year endedDecember 31, 2019 compared to$228.1 million for the year endedDecember 31, 2018 , which represents an increase of$47.0 million , or 21%. The increase in operating costs and expenses was primarily driven by (i) an increase of$22.2 million in the cost of transportation services due to crude oil transportation fees and the acquisitions of BNN North Dakota inJanuary 2018 and NGL Water Solutions Bakken inNovember 2018 , (ii) increases of$17.7 million ,$12.0 million , and$6.2 million in depreciation and amortization, operations and maintenance, and general and administrative costs, respectively, each primarily due to acquisitions and assets placed into service in 2018 and 2019 at Water Solutions and Terminals, and (iii)$0.4 million loss on the disposal of assets during the year endedDecember 31, 2019 , compared to the$11.0 million gain on disposal of assets, primarily driven by the gain on disposal of Tallgrass Crude Gathering during the year endedDecember 31, 2018 . These increases were partially offset by a$23.0 million decrease in cost of sales. The decrease in cost of sales was driven by lower NGL prices, partially offset by higher volumes processed, increased settlements to producers as a result of higher sales of residue gas from the Douglas Gathering System, and the consolidation of BNNColorado inDecember 2018 and the acquisitions of BNN North Dakota inJanuary 2018 and NGL Water Solutions Bakken inNovember 2018 . 72 -------------------------------------------------------------------------------- Liquidity and Capital Resources Overview Our primary sources of liquidity for the year endedDecember 31, 2019 were cash generated from operations and borrowings under our revolving credit facility. We expect our sources of liquidity in the future to include: • cash generated from our operations;
• borrowing capacity available under our revolving credit facility; and
• future issuances of additional debt securities.
We believe that cash on hand, cash generated from operations, and availability under our revolving credit facility will be adequate to meet our operating needs, our planned short-term maintenance capital and debt service requirements, and our planned cash distributions by TEP to Tallgrass Equity during the pendency of the transactions contemplated by the Take-Private Merger Agreement. For additional information regarding our planned cash distributions, see Item 7.-Management's Discussion and Analysis of Financial Condition and Results of Operations, "Dividends." We believe that future internal growth projects or potential acquisitions will be funded primarily through a combination of cash generated from operations, borrowings under our revolving credit facility and issuances of debt securities. For additional information regarding our revolving credit facility and senior unsecured notes, see Note 10 - Long-term Debt. For additional information regarding our equity transactions, see Note 11 - Partnership Equity. Our total liquidity as ofDecember 31, 2019 and 2018 was as follows: December 31, 2019 December 31, 2018 (in thousands) Cash on hand (1) $ 9,394 $ 9,596
Total capacity under the revolving credit facility 2,250,000
2,250,000
Less: Outstanding borrowings under the revolving credit facility (1,456,000 )
(1,224,000 ) Less: Letters of credit issued under the revolving credit facility
(94 ) (94 )
Available capacity under the revolving credit
facility 793,906 1,025,906
Total liquidity $ 803,300 $ 1,035,502
(1) Includes cash on hand at TGE and its consolidated subsidiaries.
Working Capital
Working capital is the amount by which current assets exceed current
liabilities. While various other factors may impact our working capital
requirements from period to period, our working capital requirements have
typically been, and we expect will continue to be, driven by changes in accounts
receivable, accounts payable and deferred revenue. We manage our working capital
needs through borrowings and repayments of borrowings under our revolving credit
facility. Factors impacting changes in accounts receivable and accounts payable
could include the timing of collections from customers, payments to suppliers,
and the level of spending for capital expenditures. Changes in the market prices
of energy commodities that we buy and sell in the normal course of business can
also impact the timing of changes in accounts receivable and accounts payable.
Factors impacting deferred revenue include the volume of barrels transported,
the amount of deficiency payments received, and the volume of prior deficiencies
utilized during the period.
As of December 31, 2019 , we had a working capital deficit of $131.8 million
compared to a working capital deficit of $146.9 million at December 31, 2018 ,
which represents an increase in working capital of $15.1 million . The
overall increase in working capital was primarily attributable to changes in the
following components:
• an increase in accounts receivable of $88.2 million primarily due to crude
oil sales at Stanchion and related party receivables related to
construction costs paid on behalf of joint ventures; and
• an increase in inventories of $14.8 million primarily due to crude oil
purchases at Stanchion.
These working capital increases were partially offset by:
• an increase in accounts payable and accrued liabilities of
primarily due to crude oil purchases at Stanchion, an increase in employee
compensation accruals, and an increase in the provision for rate refunds
at Trailblazer, partially offset by lower capital accruals; and
• an increase in deferred revenue of
payments collected by Pony Express and Water Solutions.
73
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A material adverse change in operations, available financing under our revolving
credit facility, or available financing from the equity or debt capital markets
could impact our ability to fund our requirements for liquidity and capital
resources in the future.
Cash Flows
The following table and discussion presents a summary of our cash flow for the
periods indicated:
Year Ended December 31,
2019 2018 2017
(in thousands)
Net cash provided by (used in):
Operating activities $ 679,006 $ 672,525 $ 571,396
Investing activities $ (287,284 ) $ (987,212 ) $ (898,541 )
Financing activities $ (391,924 ) $ 321,690 $ 327,279
Year Ended December 31, 2019 Compared to the Year Ended December 31, 2018
Operating Activities. Cash flows provided by operating activities were $679.0
million and $672.5 million for the years ended December 31, 2019 and 2018,
respectively. The increase in net cash flows provided by operating activities of
$6.5 million was primarily driven by a $19.1 million increase in distributions
received from unconsolidated affiliates, primarily Rockies Express, as well as
the increase in operating results, as discussed above. These increases were
partially offset by a net decrease in cash flows from changes in working capital
driven by an increase in net cash outflows from other current assets and
liabilities, primarily due to crude oil inventory purchases at Stanchion.
Investing Activities. Cash flows used in investing activities were $287.3
million for the year ended December 31, 2019 , primarily driven by:
• capital expenditures of $285.7 million , primarily due to Pony Express
expansion projects, Cheyenne Connector prior to the deconsolidation of
Cheyenne Connector in
infrastructure;
• contributions to unconsolidated investments in the amount of
million, primarily to fund our share of capital projects at Rockies
Express, Powder River Gateway, and Cheyenne Connector;
• net cash outflows of
• cash outflows of
formation of the Powder River Gateway joint venture.
These cash outflows were partially offset by cash inflows of:
•
in excess of cumulative earnings recognized, primarily from Rockies
Express; and
•
Connector.
Cash flows used in investing activities were$987.2 million for the year endedDecember 31, 2018 , primarily driven by: • contributions to unconsolidated investments in the amount of$473.9
million, primarily to fund our portion of the repayment of Rockies
Express'
to fund our share of capital projects at Iron Horse and BNN Colorado;
• capital expenditures of
Cheyenne Connector, additional water gathering infrastructure located in
of the
Natoma, and Grasslands Terminals, and pipe replacement and remediation
work on the Trailblazer Pipeline system as discussed in Note 20 - Legal
and Environmental Matters;
• cash outflows of
• cash outflows of
Bakken;
• cash outflows of
formation of PLT;
• cash outflows of
interest in Pawnee Terminal ; and
74--------------------------------------------------------------------------------
• cash outflows of
interest in Deeprock North.
These cash outflows were partially offset by cash inflows of:
•
excess of cumulative earnings recognized, primarily from Rockies Express;
and
•
Financing Activities. Cash flows used in financing activities were
• distributions to noncontrolling interests of
Tallgrass Equity distributions to the Exchange Right Holders of
million and distributions to
• tax payments funded by shares tendered by employees to satisfy tax
withholding obligations of
A shares under our LTIP plan.
These cash outflows were partially offset by net borrowings under the revolving credit facility of$232.0 million . Cash flows provided by financing activities were$321.7 million for the year endedDecember 31, 2018 , primarily driven by: • proceeds from TEP's issuance of$500.0 million in aggregate principal
amount of 2023 Notes; and
• net borrowings under the revolving credit facilities of
These cash inflows were partially offset by cash outflows of:
• distributions to noncontrolling interests of
consisted of Tallgrass Equity distributions to the Exchange Right Holders
of
distributions to
interests of
• dividends paid to Class A shareholders of
• cash outflows of
membership interest in Pony Express.
Dividends
Dividends to our Class A shareholders. We distribute 100% of TGE's available cash at the end of each quarter to Class A shareholders of record beginning with the quarter endedJune 30, 2015 . Available cash at TGE is generally defined in our partnership agreement as all cash and cash equivalents on hand at the date of determination in respect of such quarter less reserves established in the discretion of our general partner for future requirements. For a discussion of factors and trends impacting our business, which in turn impacts our ability to pay dividends to our Class A shareholders, please see "-Factors and Trends Impacting Our Business" above. As a result of the Take-Private Merger Agreement, TGE has agreed to not pay dividends with respect to its Class A shares and to not permit Tallgrass Equity to pay any distributions on its TE Units during the pendency of the transactions contemplated by the Take-Private Merger Agreement, in each case, without the prior written consent of Buyer. Therefore, no dividends have been declared for the three months endedDecember 31, 2019 . However, in the event the Take-Private Merger Agreement is terminated, the board of directors of our general partner will promptly fix a record date and declare and pay a dividend to the holders of Class A shares in an amount equal to the amount of dividends that otherwise would have been paid during the pendency of the transactions contemplated by the Take-Private Merger Agreement, all in accordance with our partnership agreement. Capital Requirements The midstream energy business can be capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of, the following: • maintenance capital expenditures, which are cash expenditures incurred
(including expenditures for the construction or development of new capital
assets) that we expect to maintain our long-term operating income or
operating capacity. These expenditures typically include certain system
integrity, compliance and safety improvements; and
75--------------------------------------------------------------------------------
• expansion capital expenditures, which are cash expenditures we expect will
increase our operating income or operating capacity over the long-term.
Expansion capital expenditures typically include acquisitions or capital
improvements (such as additions to or improvements on the capital assets
owned, or acquisition or construction of new capital assets).
The determination of capital expenditures as maintenance or expansion is made at the individual asset level during our budgeting process and as we approve, execute, and monitor our capital spending. We expect to incur approximately$130 million for expansion capital projects and approximately$40 million for maintenance capital expenditures in 2020. The following table summarizes the maintenance and expansion capital expenditures incurred at our consolidated entities: Year Ended December 31, 2019 2018 2017 (in thousands)
Maintenance capital expenditures
Capital expenditures incurred represent capital expenditures paid and accrued during the period. Maintenance capital expenditures were$42.4 million for the year endedDecember 31, 2019 compared to$21.0 million for the year endedDecember 31, 2018 . Maintenance capital expenditures on our assets occur on a regular schedule, but most major maintenance projects are not required every year so the level of maintenance capital expenditures naturally varies from year to year and from quarter to quarter. Expansion capital expenditures were$230.8 million for the year endedDecember 31, 2019 compared to$353.7 million for the year endedDecember 31, 2018 . Expansion capital expenditures for the year endedDecember 31, 2019 consisted primarily of spending on the Pony Express expansion, Cheyenne Connector prior to the deconsolidation of the project inNovember 2019 , and additional natural gas gathering infrastructure. Expansion capital expenditures for the year endedDecember 31, 2018 consisted primarily of spending on the Cheyenne Connector, additional water gathering infrastructure located inNorth Dakota , PLT, a 55-mile extension on the Pony Express System, construction of theBuckingham Terminal expansion, construction of the Guernsey, Natoma, and Grasslands Terminals, and pipe replacement and remediation work on the Trailblazer Pipeline system as discussed in Note 20 - Legal and Environmental Matters. During the years endedDecember 31, 2019 , 2018, and 2017, we invested cash of$115.5 million ,$473.9 million , and$45.9 million , respectively, in unconsolidated affiliates, including Rockies Express, Powder River Gateway, Cheyenne Connector subsequent to the deconsolidation inNovember 2019 , Iron Horse prior to our contribution of Iron Horse to the Powder River Gateway joint venture inJanuary 2019 , and BNN Colorado prior to our consolidation of BNNColorado inDecember 2018 , to fund our share of capital projects, including a special contribution of approximately$412.5 million to fund our portion of the repayment of Rockies Express'$550 million of 6.85% senior notes dueJuly 15, 2018 . In addition, we have made commitments of approximately$60 million to fund our portion of capital costs at Cheyenne Connector subsequent to closing of the joint venture in the fourth quarter of 2019. As discussed in "-Dividends," TGE has agreed not to pay dividends during the pendency of the transaction contemplated by the Take-Private Merger Agreement. Contractual Obligations Following is a summary of our contractual cash obligations in future periods, representing amounts that were fixed and determinable as ofDecember 31, 2019 : Payments Due By Period Less Than 1 More Than 5
Contractual Obligations Total Year 1-3 Years 3-5 Years Years
(in thousands)
Debt obligations (1) $ 3,456,000 $ - $ 1,456,000 $ 1,250,000 $ 750,000
Interest on debt
obligations (2) 732,698 155,143 281,534 170,667 125,354 Operating lease obligations (3) 20,329 2,247 2,582
1,856 13,644
Finance lease obligations (4) 19,567 449 898 917 17,303
Service contracts and other
purchase commitments (5) 81,302 41,329 12,754 6,964 20,255
Total $ 4,309,896 $ 199,168 $ 1,753,768 $ 1,430,404 $ 926,556
76--------------------------------------------------------------------------------
(1) Debt obligations atDecember 31, 2019 consisted of borrowings under the
revolving credit facility and the Senior Notes. For additional information,
see Note 10 - Long-term Debt.
(2) Interest on debt obligations is estimated using current borrowings and
interest rates as of
10 - Long-term Debt.
(3) Operating leases consist of leases for crude oil storage and terminalling,
office space, and equipment. For additional information, see Note 13 -
Leases.
(4) Finance lease obligations consist of the PLT land site lease. For additional
information, see Note 13 - Leases.
(5) Other purchase commitments primarily relate to service contracts,
right-of-way contracts, planned non-reimbursable capital expenditures, and
operating and maintenance expenditures. For additional information, see Note
14 - Commitments & Contingent Liabilities.
All of our employees are employed byTallgrass Management, LLC ("Tallgrass Management"), a wholly-owned subsidiary of Tallgrass Equity. As a result, the costs of employer and director compensation and benefits are incurred directly by Tallgrass Equity. Prior toJuly 1, 2018 , Tallgrass Management was a wholly-owned subsidiary ofTallgrass Energy Holdings . In connection with the closing of the TEP initial public offering onMay 17, 2013 , TEP and TEP GP entered into an Omnibus Agreement withTallgrass Energy Holdings and certain of its affiliates (the "TEP Omnibus Agreement"). The TEP Omnibus Agreement provided that, among other things, TEP will reimburseTallgrass Energy Holdings and its affiliates for all expenses they incur and payments they make on TEP's behalf, including the costs of employee and director compensation and benefits as well as the cost of the provision of certain centralized corporate functions performed by Tallgrass Energy Holdings and its affiliates, including legal, accounting, cash management, insurance administration and claims processing, risk management, health, safety and environmental, information technology and human resources in each case to the extent reasonably allocable to TEP. In addition, in connection with the closing of the TGE initial public offering onMay 12, 2015 (the "TGE IPO"), TGE entered into an Omnibus Agreement (the "TGE Omnibus Agreement") withTallgrass Energy GP, LLC (formerly known asTEGP Management, LLC ),Tallgrass Equity and Tallgrass Energy Holdings . The TEP Omnibus Agreement and TGE Omnibus Agreement were terminated effectiveMarch 11, 2019 in connection with the closing of theMarch 2019 Blackstone Acquisition. Off-Balance Sheet Arrangements We do not have any off-balance sheet arrangements. Critical Accounting Estimates Our significant accounting policies and the anticipated impact of recently issued accounting standards are described in Note 2 - Summary of Significant Accounting Policies. Management's discussion and analysis of financial condition and results of operations are based upon our financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses and the related disclosure of contingent assets and liabilities. The accounting policies discussed below are considered by management to be critical to an understanding of our financial statements as their application places the most significant demands on management's judgment. Due to the inherent uncertainties involved with this type of judgment, actual results could differ significantly from estimates and may have a material adverse impact on our results of operations, equity or cash flows. For additional information concerning our other accounting policies, please read the notes to the financial statements included in this report. 77 --------------------------------------------------------------------------------
Effect if Actual Results
Description Judgments and Uncertainties Differ from Assumptions
Business Combinations
For each acquired We measure the fair value If estimates or assumptions
entity we estimate the of assets acquired and used to estimate the fair
fair value of the liabilities assumed in value of acquired assets,
assets acquired and business combinations using liabilities assumed, and
liabilities assumed widely accepted valuation noncontrolling interests are
based on their techniques, such as the materially incorrect, the
estimated fair values income, cost, and market fair values assigned to
at the date of approaches. These types of assets acquired and
acquisition. If the analyses require us to make liabilities assumed could
initial accounting for assumptions and estimates significantly differ. Such a
the business regarding industry and difference would impact
combination is economic factors and the future earnings through
incomplete when the profitability of future depreciation and
combination occurs, an business strategies. These amortization expense. In
estimate will be analyses require management addition, if forecasts
recorded. We recognize to apply significant supporting the valuation of
intangible assets judgment in estimating the long-lived assets or
separately from future cash flows as well goodwill are not achieved,
goodwill if those as fair values of impairments could arise.
assets are determined individual assets, Further, if customer
to exist. Any excess including forecasting relationships terminate
of the purchase price useful lives of the assets, prior to the expected useful
over the fair value of assessing the probability life, we will be required to
the net tangible and of different outcomes, record a charge to
identifiable including anticipated operations to write-off any
intangible assets volumes, contract renewals remaining unamortized
acquired, as well as and changes in our balance of the intangible
noncontrolling regulated rates, and asset assigned to that
interest, if selecting the discount rate customer.
applicable, is that reflects the risk
recognized as inherent in future cash
goodwill. flows.
Impairment of Long-lived Assets
We periodically We review our long-lived Using the impairment review
evaluate whether the assets for impairment methodology described
carrying value of whenever events or changes herein, we have not recorded
long-lived assets has in circumstances indicate any impairment charges on
been impaired when that the carrying amount of long-lived assets during the
circumstances indicate an asset may not be year ended December 31,
the carrying value of recoverable. Our impairment 2019. If actual results are
those assets may not analyses require management not consistent with our
be recoverable. If we to apply judgment in the assumptions and estimates or
conclude an asset determination of whether our assumptions and
group needs to be circumstances indicate a estimates change due to new
tested for recoverability test should information, we may be
recoverability, this be performed, and if so, in exposed to an impairment
evaluation is based on estimating future cash charge. A prolonged period
undiscounted cash flow flows as well as asset fair of lower commodity prices
projections expected values, including may adversely affect our
to be realized over forecasting useful lives of estimate of future operating
the remaining useful the assets, assessing the results, which could result
life of the primary probability of different in future impairment due to
asset. The carrying outcomes, including the potential impact on our
amount is not anticipated volumes, operations and cash flows.
recoverable if it contract renewals and
exceeds the sum of changes in our regulated
undiscounted cash rates. If the asset group
flows expected to fails the recoverability
result from the use test, we generally
and eventual determine its respective
disposition of the fair value using an income
asset. If the carrying approach, and therefore
value is not must select a discount rate
recoverable, the that reflects the risk
impairment loss is inherent in future cash
measured as the excess flows. However, we may use
of the asset's other commonly accepted
carrying value over techniques to estimate fair
its fair value. value.
78--------------------------------------------------------------------------------
Effect if Actual Results
Description Judgments and Uncertainties Differ from Assumptions
Business Combinations
Impairment of Goodwill
We evaluate goodwill We use either the If our assumptions are not
for impairment qualitative assessment appropriate, or future
annually in the third option or proceed directly events indicate that our
quarter, and whenever to the quantitative goodwill is impaired, our
events or changes in impairment test depending net income would be impacted
circumstances indicate on facts and circumstances by the amount by which the
it is more likely than of the reporting unit, carrying value exceeds the
not that the fair including the last time we fair value of the reporting
value of a reporting performed a quantitative unit, to the extent of the
unit is less than its assessment of fair value balance of goodwill. A
carrying amount. and the excess of that fair prolonged period of lower
value over carrying value, commodity prices may
changes in the business and adversely affect our
overall economic estimate of future operating
environment, and factors results, which could result
specific to the respective in future goodwill
reporting unit. If a impairment for reporting
quantitative assessment is units due to the potential
performed we may estimate impact on our operations and
the fair value of the cash flows. We completed our
reporting unit using an impairment testing of
income approach, which goodwill in the third
requires estimates and quarter of 2019 using the
judgments around the methodology described
forecasted useful lives of herein, and determined there
the assets, the probability was no impairment.
of different outcomes, Approximately $79.2 million
anticipated volumes, of goodwill is allocated to
contract renewals, changes the Midstream Facilities
in our regulated rates, reporting unit, which is a
forecasts of commodity component of our Gathering,
prices and the discount Processing & Terminalling
rate that reflects the risk segment. As a result of
inherent in future cash current market conditions,
flows. We may also use a certain producers from which
market approach to estimate the Midstream Facilities
the fair value of the reporting unit receives
reporting unit. Key natural gas for processing
assumptions in the analysis have recently indicated that
include the use of an they currently expect to
appropriate discount rate, deliver lower volumes than
terminal year multiples, previously anticipated. The
and estimated future cash results of the Midstream
flows, including an Facilities reporting unit's
estimate of operating and impairment testing as of
general and administrative August 31, 2019 indicate
costs. It is our policy to that the fair value of the
conduct impairment testing reporting unit exceeds the
based on our current carrying value by
business strategy in light approximately 17%. As a
of present industry and result, no impairment charge
economic conditions, as was recorded. However our
well as future analysis includes
expectations. assumptions related to the
discount rate used to
discount future cash flows,
and reflects a gradual
recovery of commodity prices
and a corresponding increase
in volumes over time. This
reporting unit is sensitive
to changes in the discount
rate, as such increases in
the discount rate, could
result in a future
impairment. Additionally, if
our outlook is not realized,
or our producers further
decrease volumes, we may
recognize an impairment in
the future.
Revenue Recognition
The majority of our We review our deferred If actual results are not
revenue is derived revenue (contract consistent with our
from long-term liabilities) at each assumptions and estimates,
contracts that can balance sheet date to or our assumptions and
span several years. determine the probability estimates change due to new
Accounting for that our customers will information, the timing of
long-term contracts exercise their remaining our revenue recognition with
involves the use of rights. We recognize respect to deferred revenue
various techniques to revenue when the could be impacted and we may
estimate total probability becomes remote experience material changes
contract revenue and that the customer will in revenue.
determine the timing exercise its remaining
of revenue rights. Our evaluation
recognition. We requires management to
periodically evaluate apply judgment in contract
our estimates with renewal assumptions, along
respect to the with the accounting for the
probability of our renewal given the facts and
customers exercising circumstances of each
their rights and contract, estimating future
recognize revenue system capacity and the
associated with ability of our customers to
contract liabilities utilize that capacity.
when the probability
becomes remote that
the customer will
exercise its remaining
rights.
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