Western Gas Partners LP : MIDSTREAM OPERATING, LP Management's Discussion and Analysis of Financial Condition and Results of Operations (form 10-K)

The following discussion analyzes our financial condition and results of
operations and should be read in conjunction with the Consolidated Financial
Statements and Notes to Consolidated Financial Statements, wherein WES Operating
is fully consolidated, which are included under Part II, Item 8 of this Form
10-K, and the information set forth in Risk Factors under Part I, Item 1A of
this Form 10-K.
The Partnership's assets include assets owned and ownership interests accounted
for by us under the equity method of accounting, through our 98% partnership
interest in WES Operating, as of December 31, 2019 (see Note 10-Equity
Investments in the Notes to Consolidated Financial Statements under Part II,
Item 8 of this Form 10-K). We also own and control the entire non-economic
general partner interest in WES Operating GP, and our general partner is owned
by Occidental; therefore, prior asset acquisitions from Anadarko were classified
as transfers of net assets between entities under common control. As such,
assets acquired from Anadarko initially were recorded at Anadarko's historic
carrying value, which did not equate to the total acquisition price paid by us.
Further, subsequent to asset acquisitions from Anadarko, we were required to
recast our financial statements to include the activities of acquired assets
from the date of common control.
For reporting periods that required recast, the consolidated financial
statements for periods prior to the acquisition of assets from Anadarko were
prepared from Anadarko's historical cost-basis accounts and may not be
necessarily indicative of the actual results of operations that would have
occurred if we had owned the assets during the periods reported. For ease of
reference, we refer to the historical financial results of the Partnership's
assets prior to the acquisitions from Anadarko as being "our" historical
financial results.

                               EXECUTIVE SUMMARY

We currently own or have investments in assets located in the Rocky Mountains
(Colorado, Utah, and Wyoming), North-central Pennsylvania, Texas, and New
Mexico. We are engaged in the business of gathering, compressing, treating,
processing, and transporting natural gas; gathering, stabilizing, and
transporting condensate, NGLs, and crude oil; and gathering and disposing of
produced water. In our capacity as a natural-gas processor, we also buy and sell
natural gas, NGLs, and condensate on behalf of ourselves and as an agent for our
customers under certain contracts. We provide the above-described midstream
services for Occidental and third-party customers. As of December 31, 2019, our
assets and investments consisted of the following:
                                         Wholly
                                       Owned and     Operated    Non-Operated      Equity
                                        Operated    Interests      Interests     Interests
Gathering systems (1)                         17            2               3            2
Treating facilities                           37            3               -            3
Natural-gas processing plants/trains          25            3               -            5
NGLs pipelines                                 2            -               -            4
Natural-gas pipelines                          5            -               -            1
Crude-oil pipelines                            3            1               -            3



(1)  Includes the DBM water systems.




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December 2019 Agreements. On December 31, 2019, (i) WES and certain of its
subsidiaries, including WES Operating and WES Operating GP, entered into the
below-described agreements with Occidental and/or certain of its subsidiaries,
including Anadarko, and (ii) WES Operating also entered into the below-described
amendments to its debt agreements (collectively referred to as the "December
2019 Agreements").

• Exchange Agreement. WGRI, the general partner, and WES entered into a

partnership interests exchange agreement (the "Exchange Agreement"),

pursuant to which WES canceled the non-economic general partner

interest in WES and simultaneously issued a 2.0% general partner

interest to the general partner in exchange for which WGRI transferred

          9,060,641 WES common units to WES, which immediately canceled such
          units on receipt.

• Services, Secondment, and Employee Transfer Agreement. Occidental,

Anadarko, and WES Operating GP entered into the Services Agreement,

          pursuant to which Occidental, Anadarko, and their subsidiaries will (i)
          second certain personnel employed by Occidental to WES Operating GP, in
          exchange for which WES Operating GP will pay a monthly secondment and
          shared services fee to Occidental equivalent to the direct cost of the

seconded employees and (ii) continue to provide certain administrative

          and operational services to WES for up to a two-year transition period.
          The Services Agreement also includes provisions governing the transfer
          of certain employees to WES and WES's assumption of liabilities
          relating to those employees at the time of their transfer. In January
          2020, pursuant to the Services Agreement, Occidental made a one-time

cash contribution of $20.0 million to WES for anticipated transition

costs required to establish stand-alone human resources and information

          technology functions.



•         RCF amendment. WES Operating entered into an amendment to its RCF to,
          among other things, (i) effective on February 14, 2020, exercise the
          final one-year extension option to extend the maturity date of the RCF
          to February 14, 2025, for the extending lenders, and (ii) modify the
          change of control definition to provide, among other things, that,
          subject to certain conditions, if the limited partners of WES elect to

remove the general partner as the general partner of WES in accordance

with the terms of the partnership agreement, then such removal will not

          constitute a change of control under the RCF.

• Term loan facility amendment. WES Operating entered into an amendment

of its Term loan facility to, among other things, modify the change of

control definition to provide, among other things, that, subject to

certain conditions, if the limited partners of WES elect to remove the

          general partner as the general partner of WES in accordance with the
          terms of the partnership agreement, then such removal will not
          constitute a change of control under the Term loan facility.



•         Termination of debt-indemnification agreements. WES Operating GP and

certain wholly owned subsidiaries of Occidental mutually terminated the

          debt-indemnification agreements related to indebtedness incurred by WES
          Operating.

• Termination of omnibus agreements. WES and WES Operating entered into

          agreements with Occidental to terminate the WES and WES Operating
          omnibus agreements. See Note 6-Transactions with Affiliates in the
          Notes to Consolidated Financial Statements under Part II, Item 8 of

this Form 10-K for further information on the WES and WES Operating

          omnibus agreements.

Occidental Merger. On August 8, 2019, Anadarko, the indirect general partner and majority unitholder of WES, was acquired by Occidental pursuant to the Occidental Merger.

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Merger transactions. On February 28, 2019, WES, WES Operating, Anadarko, and
certain of their affiliates completed the transactions contemplated by the
Contribution Agreement and Agreement and Plan of Merger (the "Merger Agreement")
dated November 7, 2018, pursuant to which, among other things, Clarity Merger
Sub, LLC, a wholly owned subsidiary of WES, merged with and into WES Operating,
with WES Operating continuing as the surviving entity and as a subsidiary of WES
(the "Merger"). In connection with the Merger closing, (i) the common units of
WES Operating, which previously traded under the symbol "WES," ceased to trade
on the NYSE, (ii) the common units of WES, which previously traded under the
symbol "WGP," began to trade on the NYSE under the symbol "WES," (iii) WES
changed its name from Western Gas Equity Partners, LP to Western Midstream
Partners, LP, and (iv) WES Operating changed its name from Western Gas Partners,
LP to Western Midstream Operating, LP.
The Merger Agreement also provided that WES, WES Operating, and Anadarko cause
their respective affiliates to execute the following transactions, among others,
immediately prior to the Merger becoming effective in the following order: (1)
Anadarko E&P Onshore LLC and WGRAH (the "Contributing Parties") contribute to
WES Operating, and WES Operating subsequently contributes to WGR Operating, LP,
Kerr-McGee Gathering LLC, and DBM (each wholly owned by WES Operating), all of
their interests in each of Anadarko Wattenberg Oil Complex LLC, Anadarko DJ Oil
Pipeline LLC, Anadarko DJ Gas Processing LLC, Wamsutter Pipeline LLC, DBM Oil
Services, LLC, Anadarko Pecos Midstream LLC, Anadarko Mi Vida LLC, and APC Water
Holdings 1, LLC ("APCWH") in exchange for aggregate consideration of $1.814
billion of cash, less the outstanding amount payable pursuant to an intercompany
note (the "APCWH Note Payable") assumed by WES Operating in connection with the
transfer, and 45,760,201 WES Operating common units; (2) AMH transfers its
interests in Saddlehorn Pipeline Company, LLC, and Panola Pipeline Company, LLC
to WES Operating in exchange for $193.9 million of cash; (3) WES Operating
contributes cash in an amount equal to the outstanding balance of the APCWH Note
Payable immediately prior to the effective time of the Merger to APCWH, which in
turn uses the contributed cash to satisfy the APCWH Note Payable to Anadarko;
(4) the WES Operating Class C units convert into WES Operating common units on a
one-for-one basis; and (5) WES Operating and WES Operating GP convert the IDRs
and the 2,583,068 general partner units in WES Operating held by WES Operating
GP into a non-economic general partner interest in WES Operating and 105,624,704
WES Operating common units. The 45,760,201 WES Operating common units issued to
the Contributing Parties, less 6,375,284 WES Operating common units retained by
WGRAH, convert into the right to receive an aggregate of 55,360,984 common units
of WES at Merger completion. Each WES Operating common unit issued and
outstanding immediately prior to the closing of the Merger (other than WES
Operating common units owned by WES and WES Operating GP, and certain common
units held by subsidiaries of Anadarko) converts into the right to receive 1.525
common units of WES. See Note 13-Debt and Interest Expense in the Notes to
Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for
additional information.

Additional significant financial and operational events during the year ended December 31, 2019, included the following:

• We increased our per-unit distribution to $0.62200 for the fourth

quarter of 2019, representing a 0.3% increase over the third-quarter

          2019 distribution and a 3% increase over the fourth-quarter 2018
          distribution.

• In July 2019, WES Operating entered into an amendment to the Term loan

facility to (i) extend the maturity date from February 2020 to December

2020, and (ii) increase commitments available under the Term loan

facility from $2.0 billion to $3.0 billion, the incremental $1.0

billion of which was subsequently drawn by WES Operating on September

          13, 2019, and used to repay outstanding borrowings under the RCF. In
          December 2019, WES Operating amended certain provisions of the Term
          loan facility. See Liquidity and Capital Resources within this Item 7
          for additional information.

• In March 2019, WES Operating entered into additional interest-rate swap

          agreements with an aggregate notional principal amount of $375.0
          million. In November and December 2019, WES Operating entered into
          additional interest-rate swap agreements with an aggregate notional
          principal amount of $1,125.0 million, effectively offsetting those
          entered into in December 2018 and March 2019. In December 2019, all
          outstanding interest-rate swap agreements were cash-settled. See
          Liquidity and Capital Resources within this Item 7 for additional
          information.

• In March 2019, the WGP RCF matured and the outstanding borrowings were

          repaid. See Liquidity and Capital Resources within this Item 7 for
          additional information.




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• We commenced operations of Mentone Train II at the West Texas complex

          (with capacity of 200 MMcf/d) and Latham Train I at the DJ Basin
          complex (with capacity of 200 MMcf/d) at the end of the first and
          fourth quarters, respectively, of 2019.

• In February 2019, WES Operating increased the size of the RCF from $1.5

billion to $2.0 billion and extended the maturity date of the RCF to

February 2024. In December 2019, WES Operating extended the maturity

date of the RCF to February 2025 for the extending lenders and modified

the change of control definition in the RCF. See Liquidity and Capital

          Resources within this Item 7 for additional information.

• In January 2019, we acquired a 30% interest in Red Bluff Express from a

          third party. See Acquisitions and Divestitures under Part I, Items 1
          and 2 of this Form 10-K for additional information.



•         Natural-gas throughput attributable to WES totaled 4,248 MMcf/d for the
          year ended December 31, 2019, representing a 9% increase compared to
          the year ended December 31, 2018.



•         Crude-oil, NGLs, and produced-water throughput attributable to WES
          totaled 1,195 MBbls/d for the year ended December 31, 2019,
          representing a 57% increase compared to the year ended December 31,
          2018.



•         Operating income (loss) was $1,231.3 million for the year ended
          December 31, 2019, representing a 43% increase compared to the year
          ended December 31, 2018.



•         Adjusted gross margin for natural-gas assets (as defined under the
          caption How We Evaluate Our Operations within this Item 7) averaged
          $1.07 per Mcf for the year ended December 31, 2019, representing a 6%
          increase compared to the year ended December 31, 2018.



•         Adjusted gross margin for crude-oil, NGLs, and produced-water assets
          (as defined under the caption How We Evaluate Our Operations within
          this Item 7) averaged $1.77 per Bbl for the year ended December 31,
          2019, representing an 8% decrease compared to the year ended December
          31, 2018.



The following table provides additional information on throughput for the
periods presented below:
                                               Year Ended December 31,
                                        Inc/                      Inc/                     Inc/
                      2019     2018    (Dec)     2019    2018    (Dec)    2019    2018    (Dec)
                           Natural gas             Crude oil & NGLs        

  Produced water
                             (MMcf/d)                  (MBbls/d)                (MBbls/d)
Delaware Basin       1,226    1,041     18  %     150     132     14  %    556     239     133 %
DJ Basin             1,236    1,133      9  %     118     105     12  %      -       -       - %
Equity investments     398      291     37  %     343     241     42  %      -       -       - %
Other                1,563    1,603     (2 )%      52      58    (10 )%      -       -       - %
Total throughput     4,423    4,068      9  %     663     536     24  %    556     239     133 %






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           ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

Our historical results of operations and cash flows for the periods presented
may not be comparable to future or historic results of operations or cash flows
for the reasons described below. Refer to Operating Results within this Item 7
for a discussion of our results of operations as compared to the prior periods.

Gathering and processing agreements. Certain of the gathering agreements for the
West Texas complex, Springfield system, DJ Basin oil system, and Marcellus
Interest systems allow for rate resets that target an agreed-upon rate of return
over the life of the agreement. See Note 6-Transactions with Affiliates in the
Notes to Consolidated Financial Statements under Part II, Item 8 of this Form
10-K.

Noncontrolling interests. For periods subsequent to Merger completion, our
noncontrolling interests in the consolidated financial statements consist of (i)
the 25% third-party interest in Chipeta and (ii) the 2.0% Occidental
subsidiary-owned limited partner interest in WES Operating. For periods prior to
Merger completion, our noncontrolling interests in the consolidated financial
statements consisted of (i) the 25% third-party interest in Chipeta, (ii) the
publicly held limited partner interests in WES Operating, (iii) the common units
issued by WES Operating to subsidiaries of Anadarko as part of the consideration
paid for prior acquisitions from Anadarko, (iv) the Class C units issued by WES
Operating to a subsidiary of Anadarko as part of the funding for the acquisition
of DBM, and (v) the WES Operating Series A Preferred units issued to private
investors as part of the funding of the Springfield acquisition, until converted
into WES Operating common units in 2017.

Commodity-price swap agreements. During all periods presented, the consolidated
statements of operations and consolidated statements of equity and partners'
capital included the impacts of commodity-price swap agreements. See
Note 6-Transactions with Affiliates in the Notes to Consolidated Financial
Statements under Part II, Item 8 of this Form 10-K for further information
regarding the commodity-price swap agreements with Anadarko that expired without
renewal on December 31, 2018.

Income taxes. With respect to assets acquired from Anadarko, we recorded
Anadarko's historic current and deferred income taxes for the periods prior to
our ownership of the assets. For periods subsequent to asset acquisitions from
Anadarko, we are not subject to tax except for the Texas margin tax and,
accordingly, do not record current and deferred federal income taxes related to
such assets.

Acquisitions and divestitures. For the year ended December 31, 2019, there was a
net increase in Adjusted gross margin of $4.1 million related to our third-party
asset acquisition during 2019. For the year ended December 31, 2018, there was a
net increase in Adjusted gross margin of $40.5 million related to our
third-party asset acquisitions and divestitures during 2018. See
Note 3-Acquisitions and Divestitures in the Notes to Consolidated Financial
Statements under Part II, Item 8 of this Form 10-K for additional information
and How We Evaluate Our Operations within this Item 7 for the definition of
Adjusted gross margin.

Impairments. During 2018, we recognized impairments of $230.6 million, including
impairments of (i) $125.9 million at the Third Creek gathering system and $8.1
million at the Kitty Draw gathering system due to the shutdown of the systems,
(ii) $38.7 million at the Hilight system, and (iii) $34.6 million at the MIGC
system. During 2017, we recognized impairments of $180.1 million, including an
impairment of $158.8 million at the Granger complex due to a reduced throughput
fee as a result of a producer's bankruptcy. See Note 1-Summary of Significant
Accounting Policies and Note 8-Property, Plant, and Equipment in the Notes to
Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.


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DBM complex. In December 2015, there was an initial fire and secondary explosion
at the processing facility within the DBM complex. The majority of the damage
from the incident was to the liquid handling facilities and the amine-treating
units at the inlet of the complex. During the year ended December 31, 2017, a
$5.7 million loss was recorded in Gain (loss) on divestiture and other, net in
the consolidated statements of operations, related to a change in the estimate
of the amount that would be recovered under the property insurance claim based
on further discussions with insurers. During the second quarter of 2017, we
reached a settlement with insurers and final proceeds were received. During the
year ended December 31, 2017, we received $52.9 million in cash proceeds from
insurers, including $29.9 million in proceeds from business interruption
insurance claims and $23.0 million in proceeds from property insurance claims.
See Note 1-Summary of Significant Accounting Policies in the Notes to
Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Adoption of Topic 606. On January 1, 2018, we adopted Revenue from Contracts
with Customers (Topic 606) ("Topic 606"). The 2017 financial information was not
adjusted and is reported under Revenue Recognition (Topic 605). See
Note 1-Summary of Significant Accounting Policies in the Notes to Consolidated
Financial Statements under Part II, Item 8 of this Form 10-K for information on
our current revenue recognition policy.

                                 OUR OPERATIONS

Our results primarily are driven by the volumes of natural gas, NGLs, crude oil,
and produced water we service through our systems. In our operations, we
contract with customers to provide midstream services focused on natural gas,
NGLs, crude oil, and produced water. We gather natural gas from individual wells
or production facilities located near our gathering systems and the natural gas
may be compressed and delivered to a processing plant, treating facility, or
downstream pipeline, and ultimately to end users. We treat and process a
significant portion of the natural gas that we gather so that it will satisfy
required specifications for pipeline transportation. We gather crude oil from
individual wells or production facilities located near our gathering systems,
and in some cases, treat or stabilize the crude oil to satisfy required
specifications for pipeline transportation. We also gather and dispose of
produced water.
Currently we have operations in Colorado, Utah, Wyoming, North-central
Pennsylvania, Texas, and New Mexico, with a substantial portion of our business
concentrated in the Rocky Mountains and West Texas. For example, for the year
ended December 31, 2019, our DJ Basin and West Texas assets provided (i) 31% of
each of our throughput for natural-gas assets (excluding equity-investment
throughput), (ii) 13% and 81%, respectively, of our throughput for crude-oil,
NGLs, and produced-water assets (excluding equity-investment throughput), and
(iii) 36% and 44%, respectively, of Total revenues and other.
For the year ended December 31, 2019, 59% of Total revenues and other, 38% of
our throughput for natural-gas assets (excluding equity-investment throughput),
and 83% of our throughput for crude-oil, NGLs, and produced-water assets
(excluding equity-investment throughput) were attributable to transactions with
Occidental. In addition, Occidental supports our operations by providing
dedications and/or minimum-volume commitments.
For the year ended December 31, 2019, 93% of our wellhead natural-gas volume
(excluding equity investments) and 100% of our crude-oil, NGLs, and
produced-water throughput (excluding equity investments) were serviced under
fee-based contracts under which fixed and variable fees are received based on
the volume or thermal content of the natural gas and on the volume of NGLs,
crude oil, and produced water we gather, process, treat, transport, or dispose.
This type of contract provides us with a relatively stable revenue stream that
is not subject to direct commodity-price risk, except to the extent that (i) we
retain and sell drip condensate that is recovered during the gathering of
natural gas from the wellhead or production facilities or (ii) actual recoveries
differ from contractual recoveries under a limited number of processing
agreements.
We also have indirect exposure to commodity-price risk in that the relatively
volatile commodity-price environment has caused and may continue to cause
current or potential customers to delay drilling or shut-in production in
certain areas, which would reduce the volumes of hydrocarbons available to our
systems. We also bear limited commodity-price risk through the settlement of
imbalances. Read Item 7A. Quantitative and Qualitative Disclosures About Market
Risk under Part II of this Form 10-K.
As a result of previous acquisitions from Anadarko and third parties, our
results of operations, financial position, and cash flows may vary significantly
in future periods. See Items Affecting the Comparability of Our Financial
Results within this Item 7.


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                         HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze
our performance. These metrics are significant factors in assessing our
operating results and profitability and include (i) throughput, (ii) operating
and maintenance expenses, (iii) general and administrative expenses, (iv)
Adjusted gross margin (as defined below), (v) Adjusted EBITDA (as defined
below), and (vi) Distributable cash flow (as defined below).

Throughput. Throughput is a significant operating variable that we use to assess
our ability to generate revenues. To maintain or increase throughput on our
systems, we must connect to additional wells or production facilities. Our
success in maintaining or increasing throughput is impacted by the successful
drilling of new wells by producers that are dedicated to our systems,
recompletions of existing wells connected to our systems, our ability to secure
volumes from new wells drilled on non-dedicated acreage, and our ability to
attract natural-gas, crude-oil, NGLs, or produced-water volumes currently
serviced by our competitors.

Operating and maintenance expenses. We monitor operating and maintenance
expenses to assess the impact of these costs on asset profitability and to
evaluate the overall efficiency of our operations. Operating and maintenance
expenses include, among other things, field labor, insurance, repair and
maintenance, equipment rentals, contract services, utility costs, and services
provided to us or on our behalf. For periods commencing on the date of and
subsequent to the acquisition of assets from Anadarko, certain of these expenses
are incurred under our services and secondment agreement with Occidental, which
was amended and restated on December 31, 2019 (see Executive Summary-December
2019 Agreements within this Item 7).

General and administrative expenses. To assess the appropriateness of our
general and administrative expenses and maximize our cash available for
distribution, we monitor such expenses by way of comparison to prior periods and
to the annual budget approved by our Board of Directors. Pursuant to the WES and
WES Operating omnibus agreements, Occidental and our general partner performed
centralized corporate functions for us. General and administrative expenses for
periods prior to the acquisition of assets from Anadarko included costs
allocated by Anadarko through a management services fee. For periods subsequent
to the acquisition of assets from Anadarko, allocations and reimbursements of
general and administrative expenses were determined by Occidental in its
reasonable discretion, in accordance with our partnership and omnibus
agreements. Amounts required to be reimbursed to Occidental under the omnibus
agreements also included any expenses attributable to our status as a publicly
traded partnership, which were paid by Occidental and may include the following:

• expenses associated with annual and quarterly reporting;

• tax return and Schedule K-1 preparation and distribution expenses;

• expenses associated with listing on the NYSE; and

• independent auditor fees, legal expenses, investor relations expenses,

director fees, and registrar and transfer agent fees.

The WES and WES Operating omnibus agreements were terminated in connection with
the execution of the December 2019 Agreements. Pursuant to the Services
Agreement entered into as part of the December 2019 Agreements, Occidental (i)
seconds certain personnel employed by Occidental to WES Operating GP, in
exchange for which WES Operating GP pays a monthly secondment and shared
services fee to Occidental equivalent to the direct cost of the seconded
employees and (ii) continues to provide certain administrative and operational
services to us for up to a two-year transition period. See further detail in
Executive Summary-December 2019 Agreements within this Item 7 and
Note 6-Transactions with Affiliates in the Notes to Consolidated Financial
Statements under Part II, Item 8 of this Form 10-K.


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Non-GAAP financial measures

Adjusted gross margin. We define Adjusted gross margin attributable to Western
Midstream Partners, LP ("Adjusted gross margin") as total revenues and other
(less reimbursements for electricity-related expenses recorded as revenue), less
cost of product, plus distributions from equity investments, and excluding the
noncontrolling interests owners' proportionate share of revenues and cost of
product. We believe Adjusted gross margin is an important performance measure of
our operations' profitability and performance as compared to other companies in
the midstream industry. Cost of product expenses include (i) costs associated
with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds,
percent-of-product, and keep-whole contracts, (ii) costs associated with the
valuation of gas imbalances, and (iii) costs associated with our obligations
under certain contracts to redeliver a volume of natural gas to shippers, which
is thermally equivalent to condensate retained by us and sold to third parties.
To facilitate investor and industry analyst comparisons between us and our
peers, we also disclose per-Mcf Adjusted gross margin for natural-gas assets and
per-Bbl Adjusted gross margin for crude-oil, NGLs, and produced-water assets.
See Key Performance Metrics within this Item 7.

Adjusted EBITDA. We define Adjusted EBITDA attributable to Western Midstream
Partners, LP ("Adjusted EBITDA") as net income (loss), plus distributions from
equity investments, non-cash equity-based compensation expense, interest
expense, income tax expense, depreciation and amortization, impairments, and
other expense (including lower of cost or market inventory adjustments recorded
in cost of product), less gain (loss) on divestiture and other, net, income from
equity investments, interest income, income tax benefit, other income, and the
noncontrolling interests owners' proportionate share of revenues and expenses.
We believe the presentation of Adjusted EBITDA provides information useful to
investors in assessing our financial condition and results of operations and
that Adjusted EBITDA is a widely accepted financial indicator of a company's
ability to incur and service debt, fund capital expenditures, and make
distributions. Adjusted EBITDA is a supplemental financial measure that
management and external users of our consolidated financial statements, such as
industry analysts, investors, commercial banks, and rating agencies, use, among
other measures, to assess the following:

• our operating performance as compared to other publicly traded

       partnerships in the midstream industry, without regard to financing
       methods, capital structure, or historical cost basis;

• the ability of our assets to generate cash flow to make distributions; and

• the viability of acquisitions and capital expenditures and the returns on

investment of various investment opportunities.

Distributable cash flow. We define "Distributable cash flow" as Adjusted EBITDA,
plus interest income and the net settlement amounts from the sale and/or
purchase of natural gas, condensate, and NGLs under WES Operating's
commodity-price swap agreements to the extent such amounts are not recognized as
Adjusted EBITDA, less Service revenues - fee based recognized in Adjusted EBITDA
in excess of (less than) customer billings, net cash paid (or to be paid) for
interest expense (including amortization of deferred debt issuance costs
originally paid in cash and offset by non-cash capitalized interest),
maintenance capital expenditures, WES Operating Series A Preferred unit
distributions, income taxes, and Distributable cash flow attributable to
noncontrolling interests to the extent such amounts are not excluded from
Adjusted EBITDA. We compare Distributable cash flow to the cash distributions we
expect to pay our unitholders. Using this measure, management determines the
Coverage ratio of Distributable cash flow to planned cash distributions. We
believe Distributable cash flow is useful to investors because this measurement
is used by many companies, analysts, and others in the industry as a performance
measurement tool to evaluate our operating and financial performance as compared
to the performance of other publicly traded partnerships.
Distributable cash flow is a measure we use to assess our ability to make
distributions to our unitholders; however, this measure should not be viewed as
indicative of the actual amount of cash available for distributions or planned
for distribution for a given period. Furthermore, to the extent Distributable
cash flow includes realized amounts recorded as capital contributions from
Anadarko attributable to activity under our commodity-price swap agreements, it
is not a reflection of our ability to generate cash from operations.


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Reconciliation of non-GAAP financial measures. Adjusted gross margin, Adjusted
EBITDA, and Distributable cash flow are not defined in GAAP. The GAAP measure
used by us that is most directly comparable to Adjusted gross margin is
operating income (loss). Net income (loss) and net cash provided by operating
activities are the GAAP measures used by us that are most directly comparable to
Adjusted EBITDA. The GAAP measure used by us that is most directly comparable to
Distributable cash flow is net income (loss). Our non-GAAP financial measures of
Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow should not
be considered as alternatives to the GAAP measures of operating income (loss),
net income (loss), net cash provided by operating activities, or any other
measure of financial performance presented in accordance with GAAP. Adjusted
gross margin, Adjusted EBITDA, and Distributable cash flow have important
limitations as analytical tools because they exclude some, but not all, items
that affect operating income (loss), net income (loss), and net cash provided by
operating activities. Adjusted gross margin, Adjusted EBITDA, and Distributable
cash flow should not be considered in isolation or as a substitute for analysis
of our results as reported under GAAP. Our definitions of Adjusted gross margin,
Adjusted EBITDA, and Distributable cash flow may not be comparable to similarly
titled measures of other companies in our industry, thereby diminishing their
utility as comparative measures.
Management compensates for the limitations of Adjusted gross margin, Adjusted
EBITDA, and Distributable cash flow as analytical tools by reviewing the
comparable GAAP measures, understanding the differences between Adjusted gross
margin, Adjusted EBITDA, and Distributable cash flow compared to (as applicable)
operating income (loss), net income (loss), and net cash provided by operating
activities, and incorporating this knowledge into its decision-making processes.
We believe that investors benefit from having access to the same financial
measures that our management considers in evaluating our operating results.

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The following tables present (a) a reconciliation of the GAAP financial measure
of our operating income (loss) to the non-GAAP financial measure of Adjusted
gross margin, (b) a reconciliation of the GAAP financial measures of our net
income (loss) and our net cash provided by operating activities to the non-GAAP
financial measure of Adjusted EBITDA, and (c) a reconciliation of the GAAP
financial measure of our net income (loss) to the non-GAAP financial measure of
Distributable cash flow:
                                                                Year Ended December 31,
thousands                                                2019            2018            2017
Reconciliation of Operating income (loss) to
Adjusted gross margin
Operating income (loss)                              $ 1,231,343     $   861,282     $   801,698
Add:
Distributions from equity investments                    264,828         216,977         148,752
Operation and maintenance                                641,219         480,861         345,617
General and administrative                               114,591          67,195          53,949
Property and other taxes                                  61,352          51,848          53,147
Depreciation and amortization                            483,255         389,164         318,771
Impairments                                                6,279         230,584         180,051
Less:
Gain (loss) on divestiture and other, net                 (1,406 )         1,312         132,388
Proceeds from business interruption insurance
claims                                                         -               -          29,882
Equity income, net - affiliates                          237,518         

195,469 115,141 Reimbursed electricity-related charges recorded as revenues

                                                  74,629          66,678          56,860
Adjusted gross margin attributable to
noncontrolling interests (1)                              64,049          56,247          47,845
Adjusted gross margin                                $ 2,428,077     $ 1,978,205     $ 1,519,869
Adjusted gross margin for natural-gas assets         $ 1,656,041     $ 1,443,466     $ 1,256,160
Adjusted gross margin for crude-oil, NGLs, and
produced-water assets                                    772,036         534,739         263,709



(1)  For all periods presented, includes (i) the 25% third-party interest in
     Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner

interest in WES Operating, which collectively represent WES's noncontrolling

interests as of December 31, 2019. For a discussion of the impact to

noncontrolling interests as a result of the Merger closing, see

Noncontrolling interests within Note 1-Summary of Significant Accounting

     Policies in the Notes to Consolidated Financial Statements under Part II,
     Item 8 of this Form 10-K.




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                                                                Year Ended December 31,
thousands                                                2019            2018            2017
Reconciliation of Net income (loss) to Adjusted
EBITDA
Net income (loss)                                    $   807,700     $   630,654     $   737,385
Add:
Distributions from equity investments                    264,828         216,977         148,752
Non-cash equity-based compensation expense                14,392           7,310           5,194
Interest expense                                         303,286         183,831         142,520
Income tax expense                                        13,472          58,934          20,483
Depreciation and amortization                            483,255         389,164         318,771
Impairments                                                6,279         230,584         180,051
Other expense                                            161,813           8,264             145
Less:
Gain (loss) on divestiture and other, net                 (1,406 )         1,312         132,388
Equity income, net - affiliates                          237,518         195,469         115,141
Interest income - affiliates                              16,900          16,900          16,900
Other income                                              37,792           2,749           1,384
Income tax benefit                                             -               -          80,406
Adjusted EBITDA attributable to noncontrolling
interests (1)                                             45,131          42,843          37,431
Adjusted EBITDA                                      $ 1,719,090     $ 1,466,445     $ 1,169,651
Reconciliation of Net cash provided by operating
activities to Adjusted EBITDA
Net cash provided by operating activities            $ 1,324,100     $ 1,348,175     $ 1,042,715
Interest (income) expense, net                           286,386         166,931         125,620
Uncontributed cash-based compensation awards              (1,102 )           879              25
Accretion and amortization of long-term
obligations, net                                          (8,441 )        (5,943 )        (4,932 )
Current income tax (benefit) expense                       5,863         (80,114 )        (6,785 )
Other (income) expense, net (2)                          106,136          

(3,209 ) (1,384 ) Distributions from equity investments in excess of cumulative earnings - affiliates

                          30,256          29,585          31,659
Changes in assets and liabilities:
Accounts receivable, net                                  45,033          60,502          16,244
Accounts and imbalance payables and accrued
liabilities, net                                          30,866         (45,605 )           937
Other items, net                                         (54,876 )        38,087           2,983
Adjusted EBITDA attributable to noncontrolling
interests (1)                                            (45,131 )       (42,843 )       (37,431 )
Adjusted EBITDA                                      $ 1,719,090     $ 1,466,445     $ 1,169,651
Cash flow information
Net cash provided by operating activities            $ 1,324,100     $ 1,348,175     $ 1,042,715
Net cash used in investing activities                 (3,387,853 )    (2,210,813 )    (1,133,324 )
Net cash provided by (used in) financing
activities                                             2,071,573         875,192        (188,875 )



(1)  For all periods presented, includes (i) the 25% third-party interest in
     Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner

interest in WES Operating, which collectively represent WES's noncontrolling

interests as of December 31, 2019. For a discussion of the impact to

noncontrolling interests as a result of the Merger closing, see

Noncontrolling interests within Note 1-Summary of Significant Accounting

     Policies in the Notes to Consolidated Financial Statements under Part II,
     Item 8 of this Form 10-K.


(2)  Excludes net non-cash losses on interest-rate swaps of $25.6 million and

$8.0 million for the years ended December 31, 2019 and 2018, respectively.

See Note 13-Debt and Interest Expense in the Notes to Consolidated Financial

     Statements under Part II, Item 8 of this Form 10-K.



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                                                                Year Ended December 31,
thousands except Coverage ratio                          2019            2018            2017
Reconciliation of Net income (loss) to
Distributable cash flow and calculation of the
Coverage ratio
Net income (loss)                                    $   807,700     $   630,654     $   737,385
Add:
Distributions from equity investments                    264,828         216,977         148,752
Non-cash equity-based compensation expense                14,392           7,310           5,194
Non-cash settled interest expense, net                        39               -              71
Income tax (benefit) expense                              13,472          58,934         (59,923 )
Depreciation and amortization                            483,255         389,164         318,771
Impairments                                                6,279         230,584         180,051
Above-market component of swap agreements with
Anadarko (1)                                               7,407          51,618          58,551
Other expense                                            161,813           8,264             145
Less:
Recognized Service revenues - fee based in excess
of (less than) customer billings                         (28,764 )        62,498               -
Gain (loss) on divestiture and other, net                 (1,406 )         1,312         132,388
Equity income, net - affiliates                          237,518         195,469         115,141
Cash paid for maintenance capital expenditures           124,548         120,865          77,557
Capitalized interest                                      26,980          32,479           9,074
Cash paid for (reimbursement of) income taxes                 96           2,408           1,194
WES Operating Series A Preferred unit
distributions                                                  -               -           7,453
Other income                                              37,792           2,749           1,384
Distributable cash flow attributable to
noncontrolling interests (2)                              36,976          36,138          33,956
Distributable cash flow (3)                          $ 1,325,445     $ 1,139,587     $ 1,010,850
Distributions declared
Distributions from WES Operating                     $ 1,128,309

Less: Cash reserve for the proper conduct of WES's business

                                                   9,360
Distributions to WES unitholders (4)                 $ 1,118,949
Coverage ratio                                              1.18   x



(1)  See Note 6-Transactions with Affiliates in the Notes to Consolidated
     Financial Statements under Part II, Item 8 of this Form 10-K.


(2)  For all periods presented, includes (i) the 25% third-party interest in
     Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner

interest in WES Operating, which collectively represent WES's noncontrolling

interests as of December 31, 2019. For a discussion of the impact to

noncontrolling interests as a result of the Merger closing, see

Noncontrolling interests within Note 1-Summary of Significant Accounting

     Policies in the Notes to Consolidated Financial Statements under Part II,
     Item 8 of this Form 10-K.


(3)  For the year ended December 31, 2019, excludes cash payments of $107.7
     million related to the settlement of interest-rate swap agreements. See

Note 13-Debt and Interest Expense in the Notes to Consolidated Financial

Statements under Part II, Item 8 of this Form 10-K.

(4) Reflects cash distributions of $2.47000 per unit declared for the year ended

December 31, 2019, including the cash distribution of $0.62200 per unit paid

     on February 13, 2020, for the fourth-quarter 2019 distribution.




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                           GENERAL TRENDS AND OUTLOOK

We expect our business to continue to be affected by the following key trends
and uncertainties. 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 incorrect, our actual
results may vary materially from expected results.

Impact of crude-oil, natural-gas, and NGLs prices. Crude-oil, natural-gas, and
NGLs prices can fluctuate significantly, and have done so over time.
Commodity-price fluctuations affect the overall level of our customers' activity
and how our customers allocate capital within their own asset portfolio. The
relatively volatile commodity-price environment over the past decade has
impacted drilling activity in several of the basins in which we operate. Many of
our customers, including Occidental, have shifted capital spending toward
opportunities with superior economics and reduced activity in other areas. To
the extent possible, and to maintain throughput on our systems, we will continue
to connect new wells or production facilities to our systems to mitigate the
impact of natural production declines. However, our success in connecting
additional wells or production facilities is dependent on the activity levels of
our customers. Additionally, we will continue to evaluate the crude-oil, NGLs,
and natural-gas price environments and adjust our capital spending plans to
reflect our customers' anticipated activity levels, while maintaining
appropriate liquidity and financial flexibility.

Liquidity and access to capital markets. Under the terms of our partnership
agreement, we are required to distribute all of our available cash to our
unitholders, which makes us dependent on our ability to raise capital to fund
growth projects and acquisitions. Historically, we have accessed the debt and
equity capital markets to raise money for growth projects and acquisitions. From
time to time, capital market turbulence and investor sentiment towards MLPs have
raised our cost of capital and, in some cases, temporarily made certain sources
of capital unavailable. If we are either unable to access the capital markets or
find alternative sources of capital at reasonable costs, our growth strategy
will become more challenging to execute.

Changes in regulations. Our operations and the operations of our customers have
been, and will continue to be, affected by political developments and federal,
state, tribal, local, and other laws and regulations that are becoming more
numerous, more stringent, and more complex. These laws and regulations include,
among other things, limitations on hydraulic fracturing and other oil and gas
operations, pipeline safety and integrity requirements, permitting requirements,
environmental protection measures such as limitations on methane and other GHG
emissions, and restrictions on produced-water disposal wells. In addition, in
certain areas in which we operate, public protests of oil and gas operations are
becoming more frequent. The number and scope of the regulations with which we
and our customers must comply has a meaningful impact on our and their
businesses, and new or revised regulations, reinterpretations of existing
regulations, and permitting delays or denials could adversely affect the
throughput on and profitability of our assets.

Impact of inflation. Although inflation in the United States has been relatively
low in recent years, the U.S. economy could experience significant inflation,
which could increase our operating costs and capital expenditures materially and
negatively impact our financial results. To the extent permitted by regulations
and escalation provisions in certain of our existing agreements, we have the
ability to recover a portion of increased costs in the form of higher fees.

Impact of interest rates. Overall, short- and long-term interest rates decreased
during 2019 and remained low relative to historical averages. Short-term
interest rates experienced a sharp decrease in response to the Federal Open
Market Committee ("FOMC") lowering its target range for the federal funds rate
three separate times during 2019. Any future increases in the federal funds rate
likely will result in an increase in short-term financing costs. Additionally,
as with other yield-oriented securities, our unit price could be impacted by our
implied distribution yield relative to market interest rates. Therefore, changes
in interest rates, either positive or negative, may affect the yield
requirements of investors who invest in our units, and a rising interest-rate
environment could have an adverse impact on our unit price and our ability to
issue additional equity, or increase the cost of issuing equity, to make
acquisitions, reduce debt, or for other purposes. However, we expect our cost of
capital to remain competitive, as our competitors face similar interest-rate
dynamics.

Acquisition opportunities. We may pursue certain asset acquisitions where such
acquisitions complement our existing asset base or allow us to capture
operational efficiencies. However, if we do not make additional acquisitions on
an economically accretive basis, our future growth could be limited, and the
acquisitions we make could reduce, rather than increase, our per-unit cash flows
from operations.

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                                EQUITY OFFERINGS

See Note 5-Equity and Partners' Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional information.

WES common and general partner units. Under the Exchange Agreement, 9,060,641
common units were canceled and 9,060,641 general partner units were issued to
the general partner. In February 2019, we issued 234,053,065 common units in
connection with the Merger closing. See Note 1-Summary of Significant Accounting
Policies and Note 5-Equity and Partners' Capital in the Notes to Consolidated
Financial Statements under Part II, Item 8 of this Form 10-K for additional
information.

WES Operating common units. In February 2019, WES Operating (i) converted the
IDRs and general partner units into 105,624,704 common units in connection with
the Merger closing, and (ii) issued 45,760,201 common units as part of the AMA
acquisition.

WES Operating Class C units. All outstanding Class C units converted into WES
Operating common units on a one-for-one basis immediately prior to the Merger
closing.

WES Operating Series A Preferred units. In 2016, WES Operating issued 21,922,831
Series A Preferred units to private investors. Pursuant to an agreement between
WES Operating and the holders of the WES Operating Series A Preferred units, 50%
of the WES Operating Series A Preferred units converted into WES Operating
common units on a one-for-one basis on March 1, 2017, and all remaining WES
Operating Series A Preferred units converted into WES Operating common units on
a one-for-one basis on May 2, 2017. See Note 5-Equity and Partners' Capital in
the Notes to Consolidated Financial Statements under Part II, Item 8 of this
Form 10-K for additional information.



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                             RESULTS OF OPERATIONS

OPERATING RESULTS

The following tables and discussion present a summary of our results of
operations:
                                                                Year Ended December 31,
thousands                                                2019            2018            2017
Total revenues and other (1)                         $ 2,746,174     $ 2,299,658     $ 2,429,614
Equity income, net - affiliates                          237,518         195,469         115,141
Total operating expenses (1)                           1,750,943       1,635,157       1,905,327
Gain (loss) on divestiture and other, net                 (1,406 )         1,312         132,388
Proceeds from business interruption insurance
claims (2)                                                     -               -          29,882
Operating income (loss)                                1,231,343         861,282         801,698
Interest income - affiliates                              16,900          16,900          16,900
Interest expense                                        (303,286 )      (183,831 )      (142,520 )
Other income (expense), net                             (123,785 )        (4,763 )         1,384
Income (loss) before income taxes                        821,172         689,588         677,462
Income tax (benefit) expense                              13,472          58,934         (59,923 )
Net income (loss)                                        807,700         630,654         737,385
Net income attributable to noncontrolling
interests                                                110,459          79,083         196,595
Net income (loss) attributable to Western
Midstream Partners, LP (3)                           $   697,241     $   551,571     $   540,790
Key performance metrics (4)
Adjusted gross margin                                $ 2,428,077     $ 1,978,205     $ 1,519,869
Adjusted EBITDA                                        1,719,090       1,466,445       1,169,651
Distributable cash flow                                1,325,445       1,139,587       1,010,850



(1)  Revenues and other include amounts earned from services provided to our

affiliates and from the sale of residue gas and NGLs to our affiliates.

Operating expenses include amounts charged by our affiliates for services

and reimbursements of amounts paid by affiliates to third parties on our

behalf. See Note 6-Transactions with Affiliates in the Notes to Consolidated

     Financial Statements under Part II, Item 8 of this Form 10-K.


(2)  See Note 1-Summary of Significant Accounting Policies in the Notes to

Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(3) For reconciliations to comparable consolidated results of WES Operating, see

Items Affecting the Comparability of Financial Results with WES Operating

within this Item 7.

(4) Adjusted gross margin, Adjusted EBITDA, and Distributable cash flow are

defined under the caption How We Evaluate Our Operations within this Item 7.

For reconciliations of these non-GAAP financial measures to their most

directly comparable financial measures calculated and presented in

accordance with GAAP, see How We Evaluate Our Operations-Reconciliation of

non-GAAP financial measures within this Item 7.

For purposes of the following discussion, any increases or decreases "for the
year ended December 31, 2019" refer to the comparison of the year ended
December 31, 2019, to the year ended December 31, 2018, and any increases or
decreases "for the year ended December 31, 2018" refer to the comparison of the
year ended December 31, 2018, to the year ended December 31, 2017.


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Throughput
                                                          Year Ended December 31,
                                                                    Inc/                   Inc/
                                            2019        2018       (Dec)       2017       (Dec)
Throughput for natural-gas assets
(MMcf/d)
Gathering, treating, and
transportation (1)                            528         546        (3 )%       958       (43 )%
Processing (1)                              3,497       3,231         8  %     2,592        25  %
Equity investment (2)                         398         291        37  %       290         -  %
Total throughput                            4,423       4,068         9  %     3,840         6  %
Throughput attributable to
noncontrolling interests (3)                  175         170         3  %       179        (5 )%
Total throughput attributable to WES
for natural-gas assets                      4,248       3,898         9  %     3,661         6  %
Throughput for crude-oil, NGLs, and
produced-water assets (MBbls/d)
Gathering, treating, transportation,
and disposal                                  876         534        64  %       258       107  %
Equity investment (4)                         343         241        42  %       148        63  %
Total throughput                            1,219         775        57  %       406        91  %
Throughput attributable to
noncontrolling interests (3)                   24          15        60  %         8       88%
Total throughput attributable to WES
for crude-oil, NGLs, and produced-water
assets                                      1,195         760        57  %       398        91  %

(1) The combination of the DBM complex and DBJV and Haley systems, effective

January 1, 2018, into a single complex now is referred to as the "West Texas

complex," and resulted in DBJV and Haley systems throughput previously

reported as "Gathering, treating, and transportation" now being reported as

"Processing."

(2) Represents the 14.81% share of average Fort Union throughput, 22% share of

average Rendezvous throughput, 50% share of average Mi Vida and Ranch Westex

     throughput, and 30% share of average Red Bluff Express throughput.


(3)  For all periods presented, includes (i) the 25% third-party interest in
     Chipeta and (ii) the 2.0% Occidental subsidiary-owned limited partner

interest in WES Operating, which collectively represent WES's noncontrolling

interests as of December 31, 2019. For a discussion of the impact to

noncontrolling interests as a result of the Merger closing, see

Noncontrolling interests within Note 1-Summary of Significant Accounting

     Policies in the Notes to Consolidated Financial Statements under Part II,
     Item 8 of this Form 10-K.


(4)  Represents the 10% share of average White Cliffs throughput; 25% share of
     average Mont Belvieu JV throughput; 20% share of average TEG, TEP,
     Whitethorn, and Saddlehorn throughput; 33.33% share of average FRP
     throughput; and 15% share of average Panola and Cactus II throughput.

Natural-gas assets

Gathering, treating, and transportation throughput decreased by 18 MMcf/d for
the year ended December 31, 2019, primarily due to production declines in areas
around the Springfield gas-gathering system. This decrease was partially offset
by (i) increased throughput on the MIGC system due to new third-party customer
volumes beginning in the second quarter of 2019 and (ii) increased production in
areas around the Marcellus Interest systems.
Gathering, treating, and transportation throughput decreased by 412 MMcf/d for
the year ended December 31, 2018, primarily due to (i) the combination of the
DBM complex and DBJV and Haley systems into a single complex now referred to as
the "West Texas complex," which resulted in DBJV and Haley systems throughput
previously reported as "Gathering, treating, and transportation" now being
reported as "Processing" (decrease of 258 MMcf/d) and (ii) the divestiture of
the Non-Operated Marcellus Interest as part of the March 2017 Property Exchange
(decrease of 158 MMcf/d).

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Processing throughput increased by 266 MMcf/d for the year ended December 31,
2019, primarily due to (i) the start-up of Mentone Trains I and II at the West
Texas complex in November 2018 and March 2019, respectively, and (ii) increased
production in areas around the West Texas and DJ Basin complexes. These
increases were partially offset by (i) volumes being diverted away from the
Granger straddle plant beginning in the fourth quarter of 2019 resulting from
changes to the product mix of a third-party customer and (ii) downstream
constraints during the third quarter of 2019 that impacted our DJ Basin complex.
Processing throughput increased by 639 MMcf/d for the year ended December 31,
2018, primarily due to (i) the combination of the DBM complex and DBJV and Haley
systems into the West Texas complex, (ii) increased production in the areas
around the DJ Basin and West Texas complexes, (iii) the start-up of Train VI at
the West Texas complex in December 2017, (iv) increased throughput at the West
Texas complex due to the acquisition of the Additional DBJV System Interest as
part of the March 2017 Property Exchange, and (v) increased throughput at the
MGR assets due to increased uptime compared to 2017. These increases were
partially offset by lower throughput at the Chipeta complex due to downstream
fractionation capacity constraints in the third quarter of 2018 and the
expiration and non-renewal of a contract in September 2017.
Equity-investment throughput increased by 107 MMcf/d for the year ended
December 31, 2019, primarily due to the acquisition of the interest in Red Bluff
Express in January 2019, partially offset by decreased throughput at the Mi Vida
and Ranch Westex plants due to affiliate volumes being diverted to the West
Texas complex for processing following the start-up of Mentone Trains I and II
in November 2018 and March 2019, respectively.

Crude-oil, NGLs, and produced-water assets

Gathering, treating, transportation, and disposal throughput increased by 342
MBbls/d for the year ended December 31, 2019, primarily due to (i) increased
throughput at the DBM water systems due to new water-disposal systems that
commenced operations during the third and fourth quarters of 2018, (ii)
increased throughput at the DBM oil system due to the commencement of ROTF
operations in the second quarter of 2018 and increased production in the area,
and (iii) increased production in areas around the DJ Basin oil system.
Gathering, treating, transportation, and disposal throughput increased by 276
MBbls/d for the year ended December 31, 2018, primarily due to (i) increased
throughput from the DBM water systems that commenced operations beginning in the
second quarter of 2017 and (ii) increased throughput at the DBM oil system due
to the commencement of ROTF operations beginning in the second quarter of 2018.
Equity-investment throughput increased by 102 MBbls/d for the year ended
December 31, 2019, primarily due to (i) the acquisition of our interest in
Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline due
to additional committed volumes in 2019, (ii) the acquisition of our interest in
Cactus II in June 2018, which began delivering crude oil during the third
quarter of 2019, and (iii) increased volumes on the Saddlehorn pipeline due to
incentive tariffs and additional committed volumes effective beginning in the
third quarter of 2019.
Equity-investment throughput increased by 93 MBbls/d for the year ended
December 31, 2018, primarily due to (i) the acquisition of our interest in
Whitethorn LLC in June 2018 and (ii) increased volumes on TEP and FRP as a
result of increased NGLs production in the DJ Basin area.


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Service Revenues
                                                     Year Ended December 31,
                                                                  Inc/                    Inc/
thousands except percentages           2019           2018       (Dec)        2017       (Dec)
Service revenues - fee based       $ 2,388,191    $ 1,905,728     25  %   $ 1,357,876      40 %
Service revenues - product based        70,127         88,785    (21 )%             -      NM
 Total service revenues            $ 2,458,318    $ 1,994,513     23  %   $ 1,357,876      47 %



NM-Not Meaningful

Service revenues - fee based

Service revenues - fee based increased by $482.5 million for the year ended
December 31, 2019, primarily due to increases of (i) $266.8 million at the West
Texas complex due to a higher average gathering fee effective January 2019
($186.3 million) and increased throughput ($80.5 million), (ii) $106.1 million
at the DBM water systems due to increased throughput and new gathering and
disposal agreements effective July 1, 2018, (iii) $67.9 million at the DJ Basin
complex due to increased throughput and a higher average processing fee, (iv)
$48.6 million at the DBM oil system due to increased throughput and a higher
average gathering fee due to a new agreement effective May 2018, and (v) $37.2
million at the DJ Basin oil system due to increased throughput, a higher average
gathering fee, and an annual cost-of-service rate adjustment made during the
fourth quarter of 2019. These increases were partially offset by a decrease of
$32.6 million at the Springfield system due to decreased volumes and an annual
cost-of-service rate adjustment in the fourth quarter of 2019.
Service revenues - fee based increased by $547.9 million for the year ended
December 31, 2018, primarily due to increases of (i) $154.5 million from the
adoption of Topic 606, as discussed under Items Affecting the Comparability of
Our Financial Results within this Item 7, (ii) $141.3 million, $71.5 million,
and $19.1 million at the West Texas complex and DBM and DJ Basin oil systems,
respectively, due to increased throughput, (iii) $112.7 million at the DJ Basin
complex due to increased throughput ($91.3 million) and a higher processing fee
($21.4 million), and (iv) $78.4 million at the DBM water systems that commenced
operations beginning in the second quarter of 2017. These increases were
partially offset by decreases of (i) $22.1 million due to the divestiture of the
Non-Operated Marcellus Interest as part of the March 2017 Property Exchange and
(ii) $10.4 million at the Springfield system due to a lower cost-of-service
rate.

Service revenues - product based

Service revenues - product based decreased by $18.7 million for the year ended
December 31, 2019, primarily due to (i) a decrease in volumes and pricing across
several systems and (ii) a third-party producer contract termination at the West
Texas complex at the end of the first quarter of 2019.
Service revenues - product based increased by $88.8 million for the year ended
December 31, 2018, due to the adoption of Topic 606. As discussed under Items
Affecting the Comparability of Our Financial Results within this Item 7, under
Topic 606, certain of our customer agreements result in revenues being
recognized when the natural gas and/or NGLs are received from the customer as
non-cash consideration for services provided. In addition, retained proceeds
from sales of customer products, where we are acting as their agent, are
included in Service revenues - product based.


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Product Sales
                                                              Year Ended December 31,
thousands except percentages and                                        Inc/                       Inc/
per-unit amounts                             2019          2018        (Dec)         2017         (Dec)
Natural-gas sales (1)                     $  66,557     $  85,015       (22 )%   $   391,393       (78 )%
NGLs sales (1)                              219,831       218,005         1  %       659,817       (67 )%
Total Product sales                       $ 286,388     $ 303,020        (5 )%   $ 1,051,210       (71 )%
Per-unit gross average sales price (1):
Natural gas (per Mcf)                     $    1.65     $    2.16       (24 )%   $      2.92       (26 )%
NGLs (per Bbl)                                20.93         31.55       (34 )%         23.88        32  %

(1) For the years ended December 31, 2018 and 2017, includes the effects of

commodity-price swap agreements for the MGR assets and DJ Basin complex,

excluding the amounts considered above market with respect to these swap

agreements that were recorded as capital contributions in the consolidated

statements of equity and partners' capital. See Note 6-Transactions with

Affiliates in the Notes to Consolidated Financial Statements under Part II,

Item 8 of this Form 10-K.

Natural-gas sales

Natural-gas sales decreased by $18.5 million for the year ended December 31,
2019, primarily due to decreases of $24.0 million and $7.2 million at the West
Texas and DJ Basin complexes, respectively, due to decreases in average prices,
partially offset by increases in volumes sold. These decreases were partially
offset by an increase of $13.7 million at the Hilight system primarily due to
the reversal of a portion of an accrual for anticipated product-purchase costs
recorded in 2018 associated with the shutdown of the Kitty Draw gathering system
(see Note 1-Summary of Significant Accounting Policies in the Notes to
Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
Natural-gas sales decreased by $306.4 million for the year ended December 31,
2018, primarily due to decreases of (i) $258.9 million from the adoption of
Topic 606, as discussed under Items Affecting the Comparability of Our Financial
Results within this Item 7, (ii) $24.6 million at the West Texas complex due to
a decrease in average price, partially offset by an increase in volumes sold,
and (iii) $5.7 million due to a decrease in average price and $9.3 million due
to the shutdown of the Kitty Draw gathering system, both at the Hilight system.

NGLs sales

NGLs sales increased by $1.8 million for the year ended December 31, 2019,
primarily due to increases of (i) $17.7 million at the DJ Basin complex due to
an increase in volumes sold, (ii) $7.1 million related to commodity-price swap
agreements that expired in December 2018, and (iii) $3.2 million at the DBM
water systems due to an increase in volumes sold related to byproducts from the
treatment of produced water. These increases were partially offset by decreases
of (i) $14.3 million and $7.6 million at the MGR assets and Granger complex,
respectively, due to decreases in average prices and volumes sold, and (ii) $6.1
million at the Chipeta complex due to a decrease in average price.
NGLs sales decreased by $441.8 million for the year ended December 31, 2018,
primarily due to a decrease of $844.0 million from the adoption of Topic 606, as
discussed under Items Affecting the Comparability of Our Financial Results
within this Item 7. This decrease was partially offset by increases of (i)
$256.8 million at the West Texas complex due to an increase in volumes sold,
partially offset by a decrease in average price, (ii) $48.2 million at the DJ
Basin complex due to an increase in the swap market price and volumes sold,
(iii) $39.0 million at the DJ Basin oil system due to an increase in average
price and volumes sold, (iv) $23.8 million at the Brasada complex due to volumes
sold under a new sales agreement beginning January 1, 2018, and (v) $12.8
million at the DBM water systems due to an increase in volumes sold related to
byproducts from the treatment of produced water.

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Other Revenues
                                            Year Ended December 31,
                                                      Inc/                 Inc/
thousands except percentages     2019       2018     (Dec)      2017      (Dec)
Other revenues                 $ 1,468    $ 2,125    (31 )%   $ 20,528    (90 )%



For the year ended December 31, 2018, Other revenues decreased by $18.4 million,
primarily due to deficiency fees of $8.8 million at the Chipeta complex and $7.2
million at the DBM water systems in 2017. Upon adoption of Topic 606 on January
1, 2018, deficiency fees are recorded as Service revenues - fee based in the
consolidated statements of operations (see Note 1-Summary of Significant
Accounting Policies in the Notes to Consolidated Financial Statements under
Part II, Item 8 of this Form 10-K).

Equity Income, Net - Affiliates

                                                 Year Ended December 31,
                                                             Inc/                  Inc/

thousands except percentages 2019 2018 (Dec) 2017 (Dec) Equity income, net - affiliates $ 237,518 $ 195,469 22 % $ 115,141 70 %

Equity income, net - affiliates increased by $42.0 million for the year ended
December 31, 2019, primarily due to (i) the acquisition of our interest in
Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline due
to additional committed volumes in 2019, (ii) increased volumes at FRP and the
Saddlehorn pipeline, and (iii) the acquisition of our interest in Cactus II in
June 2018, which began delivering crude oil during the third quarter of 2019.
These increases were partially offset by a decrease in volumes at TEP.
Equity income, net - affiliates increased by $80.3 million for the year ended
December 31, 2018, primarily due to (i) the acquisition of our interest in
Whitethorn LLC in June 2018 and (ii) increased volumes at the TEFR Interests,
Saddlehorn pipeline, Mi Vida, and Ranch Westex. These increases were partially
offset by a decrease in volumes at the Fort Union system.

Cost of Product and Operation and Maintenance Expenses

                                                            Year Ended 

December 31,

                                                                       Inc/                       Inc/
thousands except percentages               2019           2018        (Dec)         2017         (Dec)
NGLs purchases (1)                     $   331,872     $ 292,698        13  %   $   573,309       (49 )%
Residue purchases (1)                      100,570       125,106       (20 )%       367,179       (66 )%
Other                                       11,805        (2,299 )      NM           13,304      (117 )%
Cost of product                            444,247       415,505         7  %       953,792       (56 )%
Operation and maintenance                  641,219       480,861        33  %       345,617        39  %
Total Cost of product and Operation
and maintenance expenses               $ 1,085,466     $ 896,366        21  %   $ 1,299,409       (31 )%

(1) For the year ended December 31, 2017, includes the effects of the

commodity-price swap agreements for the MGR assets and DJ Basin complex,

excluding the amounts considered above market with respect to these swap

agreements that were recorded as capital contributions in the consolidated

statements of equity and partners' capital. See Note 6-Transactions with

Affiliates in the Notes to Consolidated Financial Statements under Part II,

     Item 8 of this Form 10-K.




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NGLs purchases

NGLs purchases increased by $39.2 million for the year ended December 31, 2019,
primarily due to increases of (i) $48.1 million and $10.6 million at the West
Texas and DJ Basin complexes, respectively, primarily due to increases in
volumes purchased and (ii) $3.3 million at the DBM water systems due to an
increase in volumes purchased related to byproducts from the treatment of
produced water. These increases were partially offset by decreases of (i) $9.8
million and $6.3 million at the MGR assets and Granger complex, respectively,
due to decreases in average prices and volumes purchased and (ii) $7.4 million
at the Chipeta complex due to a decrease in average price.
NGLs purchases decreased by $280.6 million for the year ended December 31, 2018,
primarily due to a decrease of $690.2 million from the adoption of Topic 606, as
discussed under Items Affecting the Comparability of Financial Results within
this Item 7, partially offset by increases of (i) $269.5 million at the West
Texas complex due to an increase in volumes purchased, (ii) $50.4 million and
$40.4 million at the DJ Basin complex and DJ Basin oil system, respectively, due
to increases in average prices and volumes purchased, (iii) $22.0 million at the
Brasada complex due to volumes purchased under a new purchase agreement
beginning January 1, 2018, and (iv) $11.8 million at the DBM water systems,
which commenced operation beginning in the second quarter of 2017.

Residue purchases

Residue purchases decreased by $24.5 million for the year ended December 31,
2019, primarily due to decreases of (i) $16.8 million at the West Texas complex
due to a decrease in average price, partially offset by an increase in volumes
purchased, (ii) $3.8 million at the MGR assets due to a decrease in volumes
purchased, and (iii) $2.7 million at the Hilight system due to decreases in
volumes purchased and average price.
Residue purchases decreased by $242.1 million for the year ended December 31,
2018, primarily due to decreases of (i) $222.6 million from the adoption of
Topic 606, as discussed under Items Affecting the Comparability of Financial
Results within this Item 7, (ii) $12.9 million at the West Texas complex due to
a decrease in average price, partially offset by an increase in volumes
purchased, (iii) $6.8 million at the MGR assets due to decreases in average
price and volumes purchased, and (iv) $5.0 million at the Hilight system due to
a decrease in volumes purchased. These decreases were partially offset by an
increase of $5.7 million at the DJ Basin complex due to an increase in volumes
purchased, partially offset by a decrease in average price.

Other items

Other items increased by $14.1 million for the year ended December 31, 2019,
primarily due to increases of (i) $8.4 million at the West Texas complex due to
changes in imbalance positions and an increase in volumes purchased and (ii)
$4.0 million at the DJ Basin complex due to an increase in transportation costs.
Other items decreased by $15.6 million for the year ended December 31, 2018,
primarily due to decreases of (i) $9.8 million from the adoption of Topic 606,
as discussed under Items Affecting the Comparability of Financial Results within
this Item 7 and (ii) $6.6 million from changes in imbalance positions primarily
at the West Texas complex.

Operation and maintenance expense

Operation and maintenance expense increased by $160.4 million for the year ended
December 31, 2019, primarily due to increases of (i) $51.1 million at the DBM
water systems due to new water-disposal systems that commenced operations during
the third and fourth quarters of 2018 and higher surface-use fees, (ii) $39.0
million, $32.3 million, and $17.9 million at the West Texas complex, DJ Basin
complex, and DBM oil system, respectively, primarily due to increases in surface
maintenance and plant repairs, salaries and wages, utilities expense, and
contract labor and consulting services, (iii) $6.9 million at the DJ Basin oil
system due to increases in surface maintenance and plant repairs, salaries and
wages, and utilities expense, and (iv) $5.9 million at the Springfield system
due to increases in surface maintenance and plant repairs and safety expense.
Operation and maintenance expense increased by $135.2 million for the year ended
December 31, 2018, primarily due to increases of (i) $62.2 million at the West
Texas complex due to increases in salaries and wages, surface maintenance and
plant repairs, utilities expense, and equipment rentals, (ii) $29.2 million at
the DBM water systems, which commenced operation beginning in the second quarter
of 2017, (iii) $25.4 million at the DJ Basin complex due to increases in
utilities expense, surface maintenance and plant repairs, and salaries and
wages, and (iv) $14.8 million at the DBM oil system due to increases in surface
maintenance and plant repairs, salaries and wages, and chemicals and treating
services.


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Other Operating Expenses
                                                Year Ended December 31,
                                                            Inc/                  Inc/
thousands except percentages        2019         2018      (Dec)       2017      (Dec)

General and administrative (1) $ 114,591 $ 67,195 71 % $ 53,949 25 % Property and other taxes

            61,352       51,848     18  %      53,147     (2 )%
Depreciation and amortization      483,255      389,164     24  %     318,771     22  %
Impairments                          6,279      230,584    (97 )%     

180,051 28 % Total other operating expenses $ 665,477 $ 738,791 (10 )% $ 605,918 22 %

(1) Includes general and administrative expenses incurred on and subsequent to

     the date of the acquisition of assets from Anadarko, and a management
     services fee for expenses incurred by Anadarko for periods prior to the
     acquisition of such assets.

General and administrative expenses

General and administrative expenses increased by $47.4 million for the year
ended December 31, 2019, primarily due to increases of (i) $46.1 million of
personnel costs for which we reimbursed Occidental pursuant to the omnibus
agreements, primarily as a result of the rate-redetermination provisions in the
omnibus agreements with Occidental, resulting in a 30% increase in
reimbursements for general and administrative expenses incurred on our behalf,
which took effect January 1, 2019, and (ii) $6.3 million of expenses related to
equity awards. These amounts were partially offset by a decrease of $4.4 million
in legal and consulting fees.
General and administrative expenses increased by $13.2 million for the year
ended December 31, 2018, primarily due to (i) legal and consulting fees incurred
in 2018 and (ii) personnel costs for which we reimbursed Occidental pursuant to
the omnibus agreements. These increases were partially offset by a decrease in
bad debt expense.

Property and other taxes

Property and other taxes increased by $9.5 million for the year ended
December 31, 2019, primarily due to ad valorem tax increases (i) at the West
Texas complex due to the start-up of Mentone Train I in November 2018 and (ii)
at the DJ Basin complex due to the completion of capital projects.
Property and other taxes decreased by $1.3 million for the year ended December
31, 2018, primarily due to ad valorem tax decreases of $5.8 million at the DJ
Basin complex caused by revisions in estimated tax liabilities, offset by
increases of $2.5 million and $2.1 million at the West Texas complex and the DJ
Basin oil system, respectively.

Depreciation and amortization expense

Depreciation and amortization expense increased by $94.1 million for the year
ended December 31, 2019, primarily due to increases of (i) $36.4 million at the
West Texas complex, (ii) $24.8 million at the DBM water systems, (iii) $13.6
million at the DBM oil system, and (iv) $8.2 million at the DJ Basin complex,
all due to capital projects being placed into service. In addition, for the year
ended December 31, 2019, there was an increase of $7.5 million at the Hilight
system, primarily due to an acceleration of depreciation expense and revisions
in cost estimates related to asset retirement obligations. For further
information regarding capital projects, see Liquidity and Capital
Resources-Capital expenditures within this Item 7.
Depreciation and amortization expense increased by $70.4 million for the year
ended December 31, 2018, primarily due to increases of (i) $30.4 million, $12.9
million, and $10.8 million at the West Texas complex, DBM water systems, and DBM
oil system, respectively, due to capital projects being placed into service and
(ii) $17.1 million at the DJ Basin complex related to the shutdown of the Third
Creek gathering system (see Note 1-Summary of Significant Accounting Policies in
the Notes to Consolidated Financial Statements under Part II, Item 8 of this
Form 10-K).


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Impairment expense

Impairment expense for the year ended December 31, 2019, was primarily due to
impairments of $4.9 million at the DJ Basin complex.
Impairment expense for the year ended December 31, 2018, was primarily due to
impairments of (i) $125.9 million at the Third Creek gathering system and $8.1
million at the Kitty Draw gathering system (see Note 1-Summary of Significant
Accounting Policies in the Notes to Consolidated Financial Statements under
Part II, Item 8 of this Form 10-K), (ii) $38.7 million at the Hilight system,
(iii) $34.6 million at the MIGC system, (iv) $10.9 million at the GNB NGL
pipeline, (v) $5.6 million at the Chipeta complex, and (vi) $2.6 million at the
DBM oil system.
Impairment expense for the year ended December 31, 2017, included (i) a $158.8
million impairment at the Granger complex, (ii) an $8.2 million impairment at
the Hilight system, (iii) a $3.7 million impairment at the Granger straddle
plant, (iv) a $3.1 million impairment at the Fort Union system, (v) a $2.0
million impairment of an idle facility in northeast Wyoming, and (vi) an
impairment related to the cancellation of a pipeline project in West Texas.
For further information on impairment expense for the periods presented, see
Note 8-Property, Plant, and Equipment in the Notes to Consolidated Financial
Statements under Part II, Item 8 of this Form 10-K.

Interest Income - Affiliates and Interest Expense

                                                           Year Ended 

December 31,

                                                                       Inc/                      Inc/
thousands except percentages               2019           2018        (Dec)         2017        (Dec)
Note receivable - Anadarko             $   16,900     $   16,900         -  %   $   16,900         -  %
Interest income - affiliates           $   16,900     $   16,900         -  %   $   16,900         -  %
Third parties
Long-term debt                         $ (315,872 )   $ (200,454 )      58  %   $ (143,400 )      40  %
Amortization of debt issuance costs
and commitment fees                       (12,424 )       (9,110 )      36  %       (7,970 )      14  %
Capitalized interest                       26,980         32,479       (17 )%        9,074        NM
Affiliates
APCWH Note Payable                         (1,833 )       (6,746 )     (73 )%         (153 )      NM
Finance lease liabilities                    (137 )            -        NM               -        NM
Deferred purchase price obligation -
Anadarko                                        -              -        NM             (71 )    (100 )%
Interest expense                       $ (303,286 )   $ (183,831 )      65  %   $ (142,520 )      29  %



Interest expense increased by $119.5 million for the year ended December 31,
2019, primarily due to (i) $74.9 million of interest incurred on the Term loan
facility entered into in December 2018, (ii) $23.4 million of interest incurred
on the 4.750% Senior Notes due 2028 and 5.500% Senior Notes due 2048 that were
issued in August 2018, (iii) $18.5 million due to higher outstanding borrowings
on the RCF in 2019, and (iv) $9.5 million due to interest incurred on the 4.500%
Senior Notes due 2028 and 5.300% Senior Notes due 2048 that were issued in March
2018.
Interest expense increased by $41.3 million for the year ended December 31,
2018, primarily due to (i) $46.3 million of interest incurred on the 4.500%
Senior Notes due 2028 and 5.300% Senior Notes due 2048 that were issued in March
2018, (ii) $15.3 million of interest incurred on the 4.750% Senior Notes due
2028 and 5.500% Senior Notes due 2048 that were issued in August 2018, and (iii)
$6.6 million of interest incurred on the APCWH Note Payable. These increases
were partially offset by an increase in capitalized interest of $23.4 million,
primarily due to continued construction and expansion at (i) the DJ Basin
complex, including construction of the Latham processing plant beginning in
2018, (ii) the West Texas complex, including construction of the Mentone
processing plant beginning in the fourth quarter of 2017, and (iii) the DBM oil
system, including construction of the ROTFs that commenced operations in 2018.


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Other Income (Expense), Net
                                             Year Ended December 31,
                                                           Inc/               Inc/
thousands except percentages       2019          2018      (Dec)     2017     (Dec)
Other income (expense), net    $ (123,785 )   $ (4,763 )      NM   $ 1,384       NM



Other income (expense), net decreased by $119.0 million for the year ended
December 31, 2019, primarily due to a net loss of $125.3 million on
interest-rate swaps that were cash-settled in December 2019. See Note 13-Debt
and Interest Expense in the Notes to Consolidated Financial Statements under
Part II, Item 8 of this Form 10-K for additional information.
Other income (expense), net decreased by $6.1 million for the year ended
December 31, 2018, primarily due to a non-cash loss of $8.0 million on
interest-rate swaps entered into in December 2018. See Note 13-Debt and Interest
Expense in the Notes to Consolidated Financial Statements under Part II, Item 8
of this Form 10-K for additional information.

Income Tax (Benefit) Expense
                                                     Year Ended December 31,
                                                                 Inc/                   Inc/
thousands except percentages           2019          2018       (Dec)       2017        (Dec)
Income (loss) before income taxes   $ 821,172     $ 689,588      19  %   $ 677,462        2  %
Income tax (benefit) expense           13,472        58,934     (77 )%     (59,923 )   (198 )%
Effective tax rate                          2 %           9 %                   NM



We are not a taxable entity for U.S. federal income tax purposes. However, our
income apportionable to Texas is subject to Texas margin tax. For the periods
presented, the variance from the federal statutory rate, which is zero percent
as a non-taxable entity, is primarily due to federal and state taxes on
pre-acquisition income attributable to assets previously acquired from Anadarko,
and our share of Texas margin tax.
During the year ended December 31, 2017, AMA recognized a one-time deferred tax
benefit of $87.3 million due to the impact of the U.S. Tax Cuts and Jobs Act
signed into law on December 22, 2017. This was offset by federal and state taxes
on pre-acquisition income attributable to the AMA assets acquired from Anadarko
and our share of Texas margin tax.
Income attributable to the AMA assets prior to and including February 2019 was
subject to federal and state income tax. Income earned on the AMA assets for
periods subsequent to February 2019 was only subject to Texas margin tax on
income apportionable to Texas.


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KEY PERFORMANCE METRICS
                                                            Year Ended December 31,
thousands except percentages and                                         Inc/                      Inc/
per-unit amounts                           2019            2018         (Dec)         2017         (Dec)
Adjusted gross margin for
natural-gas assets (1)                 $ 1,656,041     $ 1,443,466        15  %   $ 1,256,160        15 %
Adjusted gross margin for crude-oil,
NGLs, and produced-water assets (1)        772,036         534,739        44  %       263,709       103 %
Adjusted gross margin (1) (2)            2,428,077       1,978,205        23  %     1,519,869        30 %
Per-Mcf Adjusted gross margin for
natural-gas assets (3)                        1.07            1.01         6  %          0.94         7 %
Per-Bbl Adjusted gross margin for
crude-oil, NGLs, and produced-water
assets (4)                                    1.77            1.93        (8 )%          1.82         6 %
Adjusted EBITDA (2)                      1,719,090       1,466,445        17  %     1,169,651        25 %
Distributable cash flow (2)              1,325,445       1,139,587        

16 % 1,010,850 13 %

(1) Adjusted gross margin is calculated as total revenues and other (less

reimbursements for electricity-related expenses recorded as revenue), less

     cost of product, plus distributions from our equity investments, and
     excluding the noncontrolling interests owners' proportionate share of
     revenues and cost of product.

(2) For a reconciliation of Adjusted gross margin, Adjusted EBITDA, and

Distributable cash flow to the most directly comparable financial measure

calculated and presented in accordance with GAAP, see the descriptions under

How We Evaluate Our Operations-Reconciliation of non-GAAP financial measures

within this Item 7.

(3) Average for period. Calculated as Adjusted gross margin for natural-gas

     assets, divided by total throughput (MMcf/d) attributable to WES for
     natural-gas assets.

(4) Average for period. Calculated as Adjusted gross margin for crude-oil, NGLs,

     and produced-water assets, divided by total throughput (MBbls/d)
     attributable to WES for crude-oil, NGLs, and produced-water assets.



Adjusted gross margin. Adjusted gross margin increased by $449.9 million for the
year ended December 31, 2019, primarily due to (i) increased throughput at the
West Texas and DJ Basin complexes, (ii) the start-up of new water-disposal
systems during the third and fourth quarters of 2018, (iii) increased throughput
and a higher average gathering fee due to a new agreement effective May 2018 at
the DBM oil system, (iv) increased throughput, a higher average gathering fee,
and an annual cost-of-service rate adjustment made during the fourth quarter of
2019 at the DJ Basin oil system, and (v) the acquisition of our interest in
Whitethorn LLC in June 2018 and increased volumes on the Whitethorn pipeline.
These increases were partially offset by decreased throughput and an annual
cost-of-service rate adjustment in the fourth quarter of 2019 at the Springfield
system (see Revenue and cost of product under Note 1-Summary of Significant
Accounting Policies in the Notes to Consolidated Financial Statements under
Part II, Item 8 of this Form 10-K).
Adjusted gross margin increased by $458.3 million for the year ended December
31, 2018, primarily due to (i) increased throughput at the West Texas complex
and DBM oil system, (ii) increased throughput and an annual cost-of-service rate
adjustment in the fourth quarter of 2018 at the DJ Basin oil system, (iii)
increased throughput and a higher processing fee at the DJ Basin complex, (iv)
the start-up of the DBM water systems beginning in the second quarter of 2017,
(v) the acquisition of our interest in Whitethorn LLC in June 2018, (vi) the
March 2017 Property Exchange, and (vii) an annual cost-of-service rate
adjustment at the Springfield system in the fourth quarter of 2018 (see Revenue
and cost of product under Note 1-Summary of Significant Accounting Policies in
the Notes to Consolidated Financial Statements under Part II, Item 8 of this
Form 10-K). These increases were partially offset by a decrease due to the
shutdown of the Kitty Draw gathering system (part of the Hilight system) in 2018
(see Note 1-Summary of Significant Accounting Policies in the Notes to
Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.06 for the
year ended December 31, 2019, primarily due to increased throughput at the West
Texas complex, which has a higher-than-average per-Mcf margin as compared to our
other natural-gas assets.
Per-Mcf Adjusted gross margin for natural-gas assets increased by $0.07 for the
year ended December 31, 2018, primarily due to (i) increased throughput at the
West Texas complex, which has a higher-than-average per-Mcf margin as compared
to our other natural-gas assets, (ii) the March 2017 Property Exchange, and
(iii) an annual cost-of-service rate adjustment at the Springfield gas-gathering
system in the fourth quarter of 2018.


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Per-Bbl Adjusted gross margin for crude-oil, NGLs, and produced-water assets
decreased by $0.16 for the year ended December 31, 2019, primarily due to
increased throughput at the DBM water systems, which has a lower per-Bbl margin
than our other crude-oil and NGLs assets. This decrease was partially offset by
(i) increased throughput, a higher average gathering fee, and an annual
cost-of-service rate adjustment made during the fourth quarter of 2019 at the DJ
Basin oil system, (ii) increased throughput and a higher average gathering fee
due to a new agreement effective May 2018 at the DBM oil system, and (iii) the
acquisition of our interest in Whitethorn LLC in June 2018 and increased volumes
on the Whitethorn pipeline.
Per-Bbl Adjusted gross margin for crude-oil, NGLs, and produced-water assets
increased by $0.11 for the year ended December 31, 2018, primarily due to (i)
increased throughput and an annual cost-of-service rate adjustment in the fourth
quarter of 2018 at the DJ Basin oil system, (ii) increased throughput at the DBM
oil system, (iii) the acquisition of our interest in Whitethorn LLC in June
2018, (iv) higher distributions received from the TEFR Interests and the Mont
Belvieu JV, and (v) an annual cost-of-service rate adjustment at the Springfield
oil-gathering system in the fourth quarter of 2018. These increases were
partially offset by increased throughput at the DBM water systems, which has a
lower per-Bbl margin than our other crude-oil and NGLs assets.

Adjusted EBITDA. Adjusted EBITDA increased by $252.6 million for the year ended
December 31, 2019, primarily due to (i) an increase of $446.5 million in total
revenues and other and (ii) an increase of $47.9 million in distributions from
equity investments. These amounts were partially offset by (i) an increase of
$160.4 million in operation and maintenance expenses, (ii) an increase of $40.3
million in general and administrative expenses excluding non-cash equity-based
compensation expense, (iii) an increase of $29.3 million in cost of product (net
of lower of cost or market inventory adjustments), and (iv) an increase of $9.5
million in property taxes.
Adjusted EBITDA increased by $296.8 million for the year ended December 31,
2018, primarily due to (i) a $538.9 million decrease in cost of product (net of
lower of cost or market inventory adjustments) and (ii) a $68.2 million increase
in distributions from equity investments. These amounts were partially offset by
(i) a $135.2 million increase in operation and maintenance expenses, (ii) a
$130.0 million decrease in total revenues and other, (iii) a $29.9 million
decrease in business interruption proceeds, and (iv) an $11.1 million increase
in general and administrative expenses excluding non-cash equity-based
compensation expense.

Distributable cash flow. Distributable cash flow increased by $185.9 million for
the year ended December 31, 2019, primarily due to (i) an increase of $252.6
million in Adjusted EBITDA and (ii) $91.3 million of customer billings in excess
of the amount recognized as Service revenues - fee based. These amounts were
partially offset by (i) an increase of $113.9 million in net cash paid for
interest expense, (ii) a decrease of $44.2 million in the above-market component
of the swap agreements with Anadarko, and (iii) an increase of $3.7 million in
cash paid for maintenance capital expenditures. For the year ended December 31,
2019, Distributable cash flow excludes cash payments of $107.7 million related
to the settlement of interest-rate swap agreements. See the definition of
Distributable cash flow under How We Evaluate Our Operations within this Item 7
and see Note 13-Debt and Interest Expense in the Notes to Consolidated Financial
Statements under Part II, Item 8 of this Form 10-K.
Distributable cash flow increased by $128.7 million for the year ended
December 31, 2018, primarily due to (i) a $296.8 million increase in Adjusted
EBITDA and (ii) a $7.5 million decrease in WES Operating Series A Preferred unit
distributions. These amounts were partially offset by (i) a $64.8 million
increase in net cash paid for interest expense, (ii) $62.5 million of customer
billings less than the amount recognized as Service revenues - fee based, (iii)
a $43.3 million increase in cash paid for maintenance capital expenditures, and
(iv) a $6.9 million decrease in the above-market component of the swap
agreements with Anadarko.


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                        LIQUIDITY AND CAPITAL RESOURCES

Our primary cash requirements are for capital expenditures, debt service,
customary operating expenses, quarterly distributions, distributions to our
noncontrolling interest owners, and strategic acquisitions. Our sources of
liquidity as of December 31, 2019, included cash and cash equivalents, cash
flows generated from operations, interest income on our $260.0 million note
receivable from Anadarko, available borrowing capacity under the RCF, and
issuances of additional equity or debt securities. We believe that cash flows
generated from these sources will be sufficient to satisfy our short-term
working capital requirements, and long-term maintenance and expansion capital
expenditure requirements. The amount of future distributions to unitholders will
depend on our results of operations, financial condition, capital requirements,
and other factors, and will be determined by the Board of Directors on a
quarterly basis. Due to our cash distribution policy, we expect to rely on
external financing sources, including equity and debt issuances, to fund
expansion capital expenditures and future acquisitions. However, we also may use
operating cash flows to fund expansion capital expenditures or acquisitions,
which could result in subsequent borrowings under the RCF to pay distributions
or to fund other short-term working capital requirements.
Our partnership agreement requires that we distribute all of our available cash
(as defined in our partnership agreement) within 55 days following each
quarter's end. Our cash flow and resulting ability to make cash distributions
are completely dependent on our ability to generate favorable cash flow from
operations. Generally, our available cash is our cash on hand at the end of a
quarter after the payment of our expenses and the establishment of cash reserves
and cash on hand resulting from working capital borrowings made after the end of
the quarter. We have made cash distributions to our unitholders each quarter
since our IPO in 2012 and have increased our quarterly distribution each quarter
since the fourth quarter of 2012. The Board of Directors declared a cash
distribution to unitholders for the fourth quarter of 2019 of $0.62200 per unit,
or $281.8 million in the aggregate. The cash distribution was paid on
February 13, 2020, to our unitholders of record at the close of business on
January 31, 2020.
Management continuously monitors our leverage position and coordinates our
capital expenditure program, quarterly distributions, and acquisition strategy
with our expected cash flows and projected debt-repayment schedule. We will
continue to evaluate funding alternatives, including additional borrowings and
the issuance of debt or equity securities, to secure funds as needed or to
refinance outstanding debt balances with longer-term debt issuances. Our ability
to generate cash flows is subject to a number of factors, some of which are
beyond our control. Read Risk Factors under Part I, Item 1A of this Form 10-K.

Working capital. As of December 31, 2019, we had an $83.5 million working
capital deficit, which we define as the amount by which current liabilities
exceed current assets. Working capital is an indication of liquidity and
potential need for short-term funding. Working capital requirements are driven
by changes in accounts receivable and accounts payable and other factors such as
credit extended to, and the timing of collections from, our customers, and the
level and timing of our spending for acquisitions, maintenance, and expansion
activity. The working capital deficit as of December 31, 2019, was primarily due
to the costs incurred related to continued construction and expansion at the
West Texas and DJ Basin complexes, DBM oil system, and DBM water systems. As of
December 31, 2019, there was $1.6 billion available for borrowing under the RCF.
See Note 11-Components of Working Capital and Note 13-Debt and Interest Expense
in the Notes to Consolidated Financial Statements under Part II, Item 8 of this
Form 10-K.


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Capital expenditures. Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure. We categorize capital expenditures as one of the following:

• maintenance capital expenditures, which include those expenditures

required to maintain existing operating capacity and service capability of

our assets, such as to replace system components and equipment that have

been subject to significant use over time, become obsolete or reached the

end of their useful lives, to remain in compliance with regulatory or

legal requirements, or to complete additional well connections to maintain

       existing system throughput and related cash flows; or

• expansion capital expenditures, which include expenditures to construct new

midstream infrastructure and expenditures incurred to extend the useful

lives of our assets, reduce costs, increase revenues, or increase system

throughput or capacity from current levels, including well connections that

increase existing system throughput.

Capital expenditures in the consolidated statements of cash flows reflect
capital expenditures on a cash basis, when payments are made. Capital incurred
is presented on an accrual basis. Acquisitions and capital expenditures as
presented in the consolidated statements of cash flows and capital incurred were
as follows:

                                              Year Ended December 31,
thousands                                2019           2018           2017
Acquisitions                         $ 2,101,229    $   162,112    $   181,708

Expansion capital expenditures       $ 1,064,281    $ 1,827,730    $   949,375
Maintenance capital expenditures         124,548        120,865         77,557
Total capital expenditures (1) (2)   $ 1,188,829    $ 1,948,595    $ 1,026,932

Capital incurred (1) (3)             $ 1,055,151    $ 1,910,508    $ 1,252,067



(1)  For the years ended December 31, 2019, 2018, and 2017, included $23.3
     million, $31.1 million, and $9.1 million, respectively, of capitalized
     interest. For the years ended December 31, 2018 and 2017, capitalized
     interest included $9.0 million and $2.2 million, respectively, of
     pre-acquisition capitalized interest for AMA.


(2)  Capital expenditures for the years ended December 31, 2018 and 2017,

included $762.8 million and $353.3 million, respectively, of pre-acquisition

capital expenditures for AMA. Capital expenditures for the year ended

December 31, 2017, are presented net of $1.4 million of contributions in aid

of construction costs from affiliates.

(3) Capital incurred for the years ended December 31, 2018 and 2017, included

$733.1 million and $453.4 million, respectively, of pre-acquisition capital

     incurred for AMA.



Acquisitions during 2019 included AMA and the 30% interest in Red Bluff Express.
Acquisitions during 2018 included a 20% interest in Whitethorn LLC, a 15%
interest in Cactus II, and equipment purchases from affiliates. Acquisitions
during 2017 included the Additional DBJV System Interest, the additional
interest in Ranch Westex, and equipment purchases from affiliates. See
Note 3-Acquisitions and Divestitures and Note 6-Transactions with Affiliates in
the Notes to Consolidated Financial Statements under Part II, Item 8 of this
Form 10-K.
Capital expenditures, excluding acquisitions, decreased by $759.8 million for
the year ended December 31, 2019. Expansion capital expenditures decreased by
$763.4 million (including a $7.8 million decrease in capitalized interest) for
the year ended December 31, 2019, primarily due to decreases of (i) $423.8
million at the West Texas complex primarily due to the completion of Mentone
Trains I and II that commenced operations in November 2018 and March 2019,
respectively, (ii) $246.5 million at the DBM oil system primarily due to the
completion of the ROTFs that commenced operations in the second quarter of 2018,
and (iii) $196.8 million at the DBM water systems due to the completion of the
water systems that commenced operations in the third and fourth quarters of
2018. These decreases were partially offset by an increase of $88.1 million at
the DJ Basin complex primarily due to continued construction of the Latham
processing plant. Maintenance capital expenditures increased by $3.7 million for
the year ended December 31, 2019, primarily due to increases at the DBM oil
system and DJ Basin complex, partially offset by decreases at the West Texas
complex and Hilight system.

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Capital expenditures, excluding acquisitions, increased by $921.7 million for
the year ended December 31, 2018. Expansion capital expenditures increased by
$878.4 million (including a $22.0 million increase in capitalized interest) for
the year ended December 31, 2018, primarily due to increases of (i) $271.7
million at the West Texas complex, $222.4 million at the DJ Basin complex, and
$182.4 million at the DBM oil system, primarily due to pipe, compression, and
processing projects and (ii) $200.2 million at the DBM water systems due to
produced-water gathering and disposal projects. Maintenance capital expenditures
increased by $43.3 million for the year ended December 31, 2018, primarily due
to increases at the DJ Basin and West Texas complexes and the DJ Basin oil
system, which were partially offset by a decrease at the DBM oil system.
For the year ending December 31, 2020, we estimate that our total capital
expenditures will be between $875.0 million to $950.0 million (excluding
acquisitions and including our 75% share of Chipeta's capital expenditures and
equity investments) and our maintenance capital expenditures will be between
$125.0 million to $135.0 million.

Historical cash flow. The following table and discussion present a summary of our net cash flows provided by (used in) operating activities, investing activities and financing activities:

                                                                  Year Ended December 31,
thousands                                                  2019            2018            2017
Net cash provided by (used in):
Operating activities                                   $ 1,324,100     $ 1,348,175     $ 1,042,715
Investing activities                                    (3,387,853 )    (2,210,813 )    (1,133,324 )
Financing activities                                     2,071,573        

875,192 (188,875 ) Net increase (decrease) in cash and cash equivalents $ 7,820 $ 12,554 $ (279,484 )

Operating Activities. Net cash provided by operating activities decreased for
the year ended December 31, 2019, primarily due to cash payments made for the
settlement of the interest-rate swap agreements, partially offset by increases
in distributions from equity investments and the impact of other changes in
working capital items. Net cash provided by operating activities increased for
the year ended December 31, 2018, primarily due to the impact of changes in
working capital items and increases in distributions from equity investments.
Refer to Operating Results within this Item 7 for a discussion of our results of
operations as compared to the prior periods.

Investing Activities. Net cash used in investing activities for the year ended December 31, 2019, included the following:

• $2.0 billion of cash paid for the acquisition of AMA;

• $1.2 billion of capital expenditures, primarily related to construction and

expansion at the West Texas and DJ Basin complexes, DBM oil system, and DBM

      water systems;

• $128.4 million of capital contributions primarily paid to Cactus II, the

      TEFR Interests, Red Bluff Express, Whitethorn LLC, and White Cliffs for
      construction activities;

• $92.5 million of cash paid for the acquisition of our interest in Red Bluff

      Express; and

• $30.3 million of distributions received from equity investments in excess

      of cumulative earnings.

Net cash used in investing activities for the year ended December 31, 2018, included the following:

• $1.9 billion of capital expenditures, primarily related to construction and

      expansion at the DBM oil and DBM water systems and the West Texas and DJ
      Basin complexes;



•     $161.9 million of cash paid for the acquisitions of our interests in
      Whitethorn LLC and Cactus II;

• $133.6 million of capital contributions primarily paid to Cactus II, the

      TEFR Interests, Whitethorn LLC, and White Cliffs for construction
      activities; and




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• $29.6 million of distributions received from equity investments in excess

      of cumulative earnings.

Net cash used in investing activities for the year ended December 31, 2017, included the following:

• $1.0 billion of capital expenditures, net of $1.4 million of contributions

in aid of construction costs from affiliates, primarily related to

construction and expansion at the DBJV system, DBM complex, DBM oil system,

      and DJ Basin complex and the construction of the DBM water systems;

• $155.3 million of cash consideration paid as part of the Property Exchange;

• $22.5 million of cash paid for the acquisition of the additional interest

      in Ranch Westex;

• $3.9 million of cash paid for equipment purchases from affiliates;

• $31.7 million of distributions received from equity investments in excess

      of cumulative earnings;

• $23.3 million of net proceeds from the sale of the Helper and Clawson

      systems in Utah; and

• $23.0 million of proceeds from property insurance claims attributable to

the incident at the DBM complex in 2015.

Financing Activities. Net cash provided by financing activities for the year ended December 31, 2019, included the following:

• $3.0 billion of borrowings under the Term loan facility, net of issuance

       costs, which were used to fund the acquisition of AMA, repay the APCWH
       Note Payable, and repay amounts outstanding under the RCF;

• $1.2 billion of borrowings under the RCF, which were used for general

       partnership purposes, including to fund capital expenditures;



•      $458.8 million of net contributions from Anadarko representing
       intercompany transactions attributable to the acquisition of AMA;

• $11.0 million of borrowings under the APCWH Note Payable, which were used

       to fund the construction of the DBM water systems;



•      $7.4 million of capital contributions from Anadarko related to the
       above-market component of swap agreements;

• $1.0 billion of repayments of outstanding borrowings under the RCF;

• $969.1 million of distributions paid to WES unitholders;

• $439.6 million of repayments of the total outstanding balance under the

       APCWH Note Payable;

• $118.2 million of distributions paid to the noncontrolling interest owners

       of WES Operating;

• $28.0 million of repayments of the total outstanding balance under the WGP

RCF, which matured in March 2019; and

• $9.7 million of distributions paid to the noncontrolling interest owner of

       Chipeta.




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Net cash provided by financing activities for the year ended December 31, 2018, included the following:

• $1.08 billion of net proceeds from the offering of the 4.500% Senior Notes

due 2028 and 5.300% Senior Notes due 2048 in March 2018, after underwriting

and original issue discounts and offering costs, which were used to repay

amounts outstanding under the RCF and for general partnership purposes,

      including to fund capital expenditures;

• $738.1 million of net proceeds from the offering of the 4.750% Senior

Notes due 2028 and 5.500% Senior Notes due 2048 in August 2018, after

underwriting and original issue discounts and offering costs, which were

used to repay the maturing 2.600% Senior Notes due August 2018, repay

amounts outstanding under the RCF, and for general partnership purposes,

       including to fund capital expenditures;

• $534.2 million of borrowings under the RCF, net of extension and amendment

costs, which were used for general partnership purposes, including to fund

       capital expenditures;

• $321.8 million of borrowings under the APCWH Note Payable, which were used

       to fund the construction of the DBM water systems;

• $97.8 million of net contributions from Anadarko representing intercompany

       transactions attributable to the acquisition of AMA;



•     $51.6 million of capital contributions from Anadarko related to the
      above-market component of swap agreements;

• $690.0 million of repayments of outstanding borrowings under the RCF;

• $502.5 million of distributions paid to WES unitholders;

• $386.3 million of distributions paid to the noncontrolling interest owners

       of WES Operating;

• $350.0 million of principal repayment on the maturing 2.600% Senior Notes

       due August 2018;

• $13.5 million of distributions paid to the noncontrolling interest owner of

      Chipeta; and

• $3.4 million of issuance costs incurred in connection with the Term loan

      facility.

Net cash used in financing activities for the year ended December 31, 2017, included the following:

• $370.0 million of borrowings under the RCF, which were used for general

       partnership purposes, including funding of capital expenditures;



•      $126.9 million of net contributions from Anadarko representing
       intercompany transactions attributable to the acquisition of AMA;

• $98.8 million of borrowings under the APCWH Note Payable, which were used

       to fund the construction of the DBM water systems;



•      $58.6 million of capital contributions from Anadarko related to the
       above-market component of swap agreements;

• $442.0 million of distributions paid to WES unitholders;

• $355.6 million of distributions paid to the noncontrolling interest owners

       of WES Operating;

• $37.3 million of cash paid to Anadarko for the settlement of the Deferred

       purchase price obligation - Anadarko; and

• $13.6 million of distributions paid to the noncontrolling interest owner of

      Chipeta.



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Debt and credit facilities. As of December 31, 2019, the carrying value of
outstanding debt was $8.0 billion. See Note 13-Debt and Interest Expense in the
Notes to Consolidated Financial Statements under Part II, Item 8 of this Form
10-K.

WES Operating Senior Notes. At December 31, 2019, WES Operating was in compliance with all covenants under the relevant governing indentures.

WGP RCF. In February 2018, we voluntarily reduced the aggregate commitment of
lenders under the WGP RCF to $35.0 million. The WGP RCF, which previously was
available to purchase WES Operating common units and for general partnership
purposes, matured in March 2019 and the $28.0 million of outstanding borrowings
were repaid.

Revolving credit facility. The RCF is expandable to a maximum of $2.5 billion
and bears interest at LIBOR, plus applicable margins ranging from 1.00% to
1.50%, or an alternate base rate equal to the greatest of (a) the Prime Rate,
(b) the Federal Funds Effective Rate plus 0.50%, or (c) LIBOR plus 1.00%, in
each case plus applicable margins currently ranging from zero to 0.50%, based on
WES Operating's senior unsecured debt rating. A required quarterly facility fee
is paid ranging from 0.125% to 0.250% of the commitment amount (whether drawn or
undrawn), which also is based on the senior unsecured debt rating. In December
2019, WES Operating entered into an amendment to the RCF to, among other things,
exercise the final one-year extension option to extend the maturity date of the
RCF from February 2024 to February 2025, for each extending lender. The maturity
date with respect to each non-extending lender, whose commitments represent
$100.0 million out of $2.0 billion of total commitments from all lenders,
remains February 2024. See Executive Summary-December 2019 Agreements within
this Item 7 for more information.
As of December 31, 2019, there were $380.0 million of outstanding borrowings and
$4.6 million of outstanding letters of credit, resulting in $1.6 billion of
available borrowing capacity under the RCF. At December 31, 2019, the interest
rate on any outstanding RCF borrowings was 3.04% and the facility fee rate was
0.20%. At December 31, 2019, WES Operating was in compliance with all covenants
under the RCF.

Term loan facility. In December 2018, WES Operating entered into the Term loan
facility, the proceeds from which were used to fund substantially all of the
cash portion of the consideration under the Merger Agreement and the payment of
related transaction costs (see Executive Summary-Merger transactions within this
Item 7). The Term loan facility bears interest at LIBOR, plus applicable margins
ranging from 1.000% to 1.625%, or an alternate base rate equal to the greatest
of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.50%, or (c)
LIBOR plus 1.00%, in each case as defined in the Term loan facility and plus
applicable margins currently ranging from zero to 0.625%, based on WES
Operating's senior unsecured debt rating. Net cash proceeds received from future
asset sales and debt or equity offerings must be used to repay amounts
outstanding under the facility. The Term loan facility contains covenants and
certain events of default that are substantially similar to those contained in
the RCF.
In July 2019, WES Operating entered into an amendment to the Term loan facility
to (i) extend the maturity date from February 2020 to December 2020, (ii)
increase commitments available under the Term loan facility from $2.0 billion to
$3.0 billion, the incremental $1.0 billion of which was subsequently drawn by
WES Operating on September 13, 2019, and used to repay outstanding borrowings
under the RCF, and (iii) modify the provision requiring that all debt issuance
proceeds be used to repay the Term loan facility to allow for a $1.0 billion
exclusion for debt-offering proceeds.
As of December 31, 2019, there were $3.0 billion of outstanding borrowings under
the Term loan facility that were subject to an interest rate of 3.10%. WES
Operating was in compliance with all covenants under the Term loan facility as
of December 31, 2019. The outstanding borrowings under the Term loan facility
were classified as Long-term debt on the consolidated balance sheet at
December 31, 2019. In January 2020, WES Operating repaid the outstanding
borrowings under the Term loan facility with proceeds from the issuance of the
Senior Notes and Floating Rate Notes (see Note 16-Subsequent Events in the Notes
to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for
additional information).

The RCF and Term loan facility contain certain covenants that limit, among other
things, WES Operating's ability, and that of certain of its subsidiaries, to
incur additional indebtedness, grant certain liens, merge, consolidate, or allow
any material change in the character of its business, enter into certain
affiliate transactions and use proceeds other than for partnership purposes. The
RCF and Term loan facility also contain various customary covenants, certain
events of default, and a maximum consolidated leverage ratio as of the end of
each fiscal quarter (which is defined as the ratio of consolidated indebtedness
as of the last day of a fiscal quarter to Consolidated Earnings Before Interest,
Taxes, Depreciation, and Amortization for the most-recent four-consecutive
fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage
ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period
immediately following certain acquisitions.


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Prior to December 31, 2019, WES Operating GP was indemnified by wholly owned
subsidiaries of Occidental against any claims made against WES Operating GP for
WES Operating's long-term debt and/or borrowings under the RCF and Term loan
facility. These indemnification agreements were terminated as part of the
December 2019 Agreements. See Executive Summary-December 2019 Agreements within
this Item 7 for more information.

APCWH Note Payable. In June 2017, in connection with funding the construction of
the APC water systems that were acquired as part of the AMA acquisition, APCWH
entered into an eight-year note payable agreement with Anadarko. This note
payable had a maximum borrowing limit of $500.0 million, including accrued
interest, which was payable at maturity at the applicable mid-term federal rate
based on a quarterly compounding basis as determined by the U.S. Secretary of
the Treasury. The APCWH Note Payable was repaid at Merger completion (see
Executive Summary-Merger transactions within this Item 7).

Interest-rate swaps. In December 2018 and March 2019, WES Operating entered into
interest-rate swap agreements with an aggregate notional principal amount of
$750.0 million and $375.0 million, respectively, to manage interest-rate risk
associated with anticipated debt issuances. Pursuant to these swap agreements,
WES Operating received a floating interest rate indexed to the three-month LIBOR
and paid a fixed interest rate. In November and December 2019, WES Operating
entered into additional interest-rate swap agreements with an aggregate notional
principal amount of $1,125.0 million. Pursuant to these swap agreements, WES
Operating received a fixed interest rate and paid a floating interest rate
indexed to the three-month LIBOR, effectively offsetting the swap agreements
entered into in December 2018 and March 2019.
In December 2019, all outstanding interest-rate swap agreements were
cash-settled. As part of the settlement, WES Operating made cash payments of
$107.7 million and recorded an accrued liability of $25.6 million to be paid
quarterly in 2020. These cash payments were classified as cash flows from
operating activities in the consolidated statement of cash flows.
We did not apply hedge accounting and, therefore, gains and losses associated
with the interest-rate swap agreements were recognized in earnings. For the year
ended December 31, 2019, a net loss of $125.3 million was recognized, which is
included in Other income (expense), net in the consolidated statements of
operations. See Note 13-Debt and Interest Expense in the Notes to Consolidated
Financial Statements under Part II, Item 8 of this Form 10-K for additional
information.

DBJV acquisition - Deferred purchase price obligation - Anadarko. Prior to WES
Operating's agreement with Anadarko to settle the deferred purchase price
obligation early, the consideration that would have been paid for the March 2015
acquisition of DBJV from Anadarko consisted of a cash payment to Anadarko due on
March 31, 2020. In May 2017, WES Operating reached an agreement with Anadarko to
settle this obligation with a cash payment to Anadarko of $37.3 million, which
was equal to the estimated net present value of the obligation at March 31,
2017.

Credit risk. We bear credit risk through exposure to non-payment or
non-performance by our counterparties, including Occidental, financial
institutions, customers, and other parties. Generally, non-payment or
non-performance results from a customer's inability to satisfy payables to us
for services rendered or volumes owed pursuant to gas imbalance agreements. We
examine and monitor the creditworthiness of third-party customers and may
establish credit limits for third-party customers. A substantial portion of our
throughput, however, comes from producers, including Occidental, that have
investment-grade ratings. We are subject to the risk of non-payment or late
payment by Occidental for gathering, processing, transportation, and disposal
fees and for proceeds from the sale of residue, NGLs, and condensate to
Occidental.
We expect our exposure to concentrated risk of non-payment or non-performance to
continue for as long as we remain dependent on Occidental for over 50% of our
revenues. Additionally, we are exposed to credit risk on the note receivable
from Anadarko. We also are party to agreements with Occidental under which
Occidental is required to indemnify us for certain environmental claims, losses
arising from rights-of-way claims, failures to obtain required consents or
governmental permits, and income taxes with respect to the assets previously
acquired from Anadarko. See Note 6-Transactions with Affiliates in the Notes to
Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
Our ability to make distributions to our unitholders may be adversely impacted
if Occidental becomes unable to perform under the terms of gathering,
processing, transportation, and disposal agreements; natural-gas and NGLs
purchase agreements; Anadarko's note payable to WES Operating; the contribution
agreements; or the December 2019 Agreements (see Note 1-Summary of Significant
Accounting Policies in the Notes to Consolidated Financial Statements under
Part II, Item 8 of this Form 10-K).


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ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING

Our consolidated financial statements include the consolidated financial results
of WES Operating. Our results of operations do not differ materially from the
results of operations and cash flows of WES Operating, which are reconciled
below.

Reconciliation of net income (loss) attributable to WES to net income (loss) attributable to WES Operating. The differences between net income (loss) attributable to WES and net income (loss) attributable to WES Operating are reconciled as follows:

                                                             Year Ended December 31,
thousands                                               2019          2018  

2017

Net income (loss) attributable to WES                $ 697,241     $ 551,571     $ 540,790
Limited partner interests in WES Operating not
held by WES (1)                                        103,364        70,474       185,860
General and administrative expenses (2)                  6,819         4,029         2,872
Other income (expense), net                                (79 )        (192 )         (85 )
Interest expense                                           245        

2,035 2,229 Net income (loss) attributable to WES Operating $ 807,590 $ 627,917 $ 731,666

(1) Represents the portion of net income (loss) allocated to the limited partner

interests in WES Operating not held by WES. As of December 31, 2019, 2018,

and 2017, the public held a 0%, 59.2%, and 59.6% limited partner interest in

WES Operating, respectively. Certain subsidiaries of Occidental separately

held a 2.0%, 9.7%, and 9.1% limited partner interest in WES Operating as of

December 31, 2019, 2018, and 2017, respectively. Immediately prior to the

Merger closing, the WES Operating IDRs and the general partner units were

converted into a non-economic general partner interest in WES Operating and

WES Operating common units, and at Merger completion, all WES Operating

common units held by the public and subsidiaries of Anadarko (other than

common units held by WES, WES Operating GP, and 6.4 million common units

held by a subsidiary of Anadarko) were converted into WES common units. See

Note 1-Summary of Significant Accounting Policies in the Notes to

Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

(2) Represents general and administrative expenses incurred by WES separate

     from, and in addition to, those incurred by WES Operating.




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Reconciliation of net cash provided by (used in) operating and financing activities. The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows:

                                                                Year Ended December 31,
thousands                                                2019            2018            2017

WES net cash provided by operating activities $ 1,324,100 $ 1,348,175 $ 1,042,715 General and administrative expenses (1)

                    6,819           4,029           2,872
Non-cash equity-based compensation expense                (1,259 )          (278 )          (247 )
Changes in working capital                                 2,383            (854 )            (8 )
Other income (expense), net                                  (79 )          (192 )           (85 )
Interest expense                                             245           2,035           2,229
Debt related amortization and other items, net               (20 )          (801 )          (678 )
WES Operating net cash provided by operating
activities                                           $ 1,332,189     $ 

1,352,114 $ 1,046,798

WES net cash provided by (used in) financing
activities                                           $ 2,071,573     $   875,192     $  (188,875 )
Distributions to WES unitholders (2)                     969,073         502,457         441,967
Distributions to WES from WES Operating (3)           (1,006,163 )      (507,323 )      (445,677 )
Registration expenses related to the issuance of
WES common units                                             855               -               -
WGP RCF costs                                                  -               7               -
WGP RCF repayments                                        28,000               -               -
WES Operating net cash provided by (used in)
financing activities                                 $ 2,063,338     $   870,333     $  (192,585 )

(1) Represents general and administrative expenses incurred by WES separate

     from, and in addition to, those incurred by WES Operating.


(2)  Represents distributions to WES common unitholders paid under WES's
     partnership agreement. See Note 4-Partnership Distributions and

Note 5-Equity and Partners' Capital in the Notes to Consolidated Financial

Statements under Part II, Item 8 of this Form 10-K.

(3) Difference attributable to elimination upon consolidation of WES Operating's

distributions on partnership interests owned by WES. See Note 4-Partnership

Distributions and Note 5-Equity and Partners' Capital in the Notes to

Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Noncontrolling interest. WES Operating's noncontrolling interest consists of the 25% third-party interest in Chipeta (see Note 1-Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for further information).

WES Operating distributions. WES Operating distributes all of its available cash
(as defined in its partnership agreement) to WES Operating unitholders of record
on the applicable record date within 45 days following each quarter's end.
Immediately prior to the Merger closing, the WES Operating IDRs and general
partner units were converted into WES Operating common units and a non-economic
general partner interest in WES Operating, and at Merger completion, all WES
Operating common units held by the public and subsidiaries of Anadarko (other
than common units held by WES, WES Operating GP, and 6.4 million common units
held by a subsidiary of Anadarko) were converted into WES common units.
Beginning first quarter of 2019, WES Operating makes cash distributions to WES
and WGRAH, a subsidiary of Occidental, in respect of their proportionate share
of limited partner interests in WES Operating. For the quarters ended March 31,
2019, June 30, 2019, and September 30, 2019, WES Operating distributed $283.3
million, $288.1 million, and $289.7 million, respectively, to its limited
partners. For the quarter ended December 31, 2019, WES Operating distributed
$290.3 million to its limited partners. See Note 5.

WES Operating LTIP. Concurrent with the Merger closing, we assumed the Western
Gas Partners, LP 2017 Long-Term Incentive Plan. See Note 6-Transactions with
Affiliates in the Notes to Consolidated Financial Statements under Part II,
Item 8 of this Form 10-K for further information.


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                            CONTRACTUAL OBLIGATIONS

The following is a summary of our contractual cash obligations as of
December 31, 2019. The table below excludes amounts classified as current
liabilities on the consolidated balance sheets, other than the current portions
of the categories listed within the table. It is expected that the majority of
the excluded current liabilities will be paid in cash in 2020.
                                                             Obligations by Period
thousands                2020           2021          2022          2023          2024        Thereafter         Total
Total debt
Principal            $ 3,007,873     $ 500,000     $ 670,000     $       -     $       -     $ 3,830,000     $  8,007,873
Interest                 331,192       217,990       207,589       180,963       180,963       2,136,237        3,254,934

Asset retirement
obligations               22,472        38,537             -             -         4,443         293,416          358,868
Capital
expenditures             140,954             -             -             -             -               -          140,954
Credit facility
fees                       4,133         4,133         4,133         4,133         4,133             530           21,195
Environmental
obligations                3,528           907           468           320           203              12            5,438
Operating leases           1,969           612           618           625           449           1,209            5,482
Total                $ 3,512,121     $ 762,179     $ 882,808     $ 186,041     $ 190,191     $ 6,261,404     $ 11,794,744



Asset retirement obligations. When assets are acquired or constructed, the
initial estimated asset retirement obligation is recognized in an amount equal
to the net present value of the settlement obligation, with an associated
increase in properties and equipment. Revisions in estimated asset retirement
obligations may result from changes in estimated inflation rates, discount
rates, asset retirement costs, and the estimated timing of settlement. For
additional information, see Note 12-Asset Retirement Obligations in the Notes to
Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Capital expenditures. Included in this amount are capital obligations related to
our expansion projects. We have other planned capital and investment projects
that are discretionary in nature, with no substantial contractual obligations
made in advance of the actual expenditures. See Note 15-Commitments and
Contingencies in the Notes to Consolidated Financial Statements under Part II,
Item 8 of this Form 10-K.

Credit facility fees. For additional information on credit facility fees required under the RCF, see Note 13-Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Environmental obligations. We are subject to various environmental-remediation
obligations arising from federal, state, and local regulations regarding air and
water quality, hazardous and solid waste disposal, and other environmental
matters. We regularly monitor the remediation and reclamation process and the
liabilities recorded and believe that the amounts reflected in our recorded
environmental obligations are adequate to fund remedial actions required to
comply with present laws and regulations. For additional information on
environmental obligations, see Note 15-Commitments and Contingencies in the
Notes to Consolidated Financial Statements under Part II, Item 8 of this Form
10-K.

Leases. We have entered into operating leases that extend through 2028 for
corporate offices, shared field offices, and equipment supporting our
operations, with both Occidental and third parties as lessors. Lease obligations
to Occidental represent existing contractual operating lease obligations that
may be assigned or otherwise charged to us pursuant to the reimbursement
provisions of our Services Agreement. We also have subleased equipment from
Occidental via finance leases extending through April 2020. The liabilities
associated with these finance leases are included within Short-term debt in the
consolidated balance sheets. See Note 14-Leases in the Notes to Consolidated
Financial Statements under Part II, Item 8 of this Form 10-K.

For additional information on contracts, obligations, and arrangements we and WES Operating enter into from time to time, see Note 6-Transactions with Affiliates and Note 15-Commitments and Contingencies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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                         CRITICAL ACCOUNTING ESTIMATES

The preparation of consolidated financial statements in accordance with GAAP
requires management to make informed judgments and estimates that affect the
amounts of assets and liabilities as of the date of the financial statements and
affect the amounts of revenues and expenses recognized during the periods
reported. On an ongoing basis, management reviews its estimates, including those
related to the determination of property, plant, and equipment, asset retirement
obligations, litigation, environmental liabilities, income taxes, revenues, and
fair values. On an annual basis, as determined by the specific agreement,
management reviews and updates certain gathering rates that are based on
cost-of-service agreements. These cost-of-service gathering rates are calculated
using a contractually specified rate of return and estimates including long-term
assumptions for capital invested, receipt volumes, and operating and maintenance
expenses. See Contract balances in Note 2-Revenue from Contracts with Customers
in the Notes to Consolidated Financial Statements under Part II, Item 8 of this
Form 10-K. Although these estimates are based on management's best available
knowledge of current and expected future events, changes in facts and
circumstances or discovery of new information may result in revised estimates,
and actual results may differ from these estimates. Management considers the
following to be its most critical accounting estimates that involve judgment and
discusses the selection and development of these estimates with our general
partner's Audit Committee. For additional information concerning accounting
policies, see Note 1-Summary of Significant Accounting Policies in the Notes to
Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Impairments of tangible assets. Property, plant, and equipment generally is
stated at the lower of historical cost less accumulated depreciation or fair
value if impaired. Because prior acquisitions of assets from Anadarko were
transfers of net assets between entities under common control, the assets
acquired initially were recorded at Anadarko's historic carrying value. Assets
acquired in a business combination or non-monetary exchange with a third party
are initially recorded at fair value. Property, plant, and equipment balances
are evaluated for potential impairment when events or changes in circumstances
indicate that their carrying amounts may not be recoverable from expected
undiscounted cash flows from the use and eventual disposition of an asset. If
the sum of the undiscounted future net cash flows is less than the carrying
amount of the asset's estimated fair value, an impairment loss is recognized for
the excess, if any, of the carrying amount of the asset over its estimated fair
value.
In assessing long-lived assets for impairments, our management evaluates changes
in our business and economic conditions and their implications for
recoverability of the assets' carrying amounts. Management applies judgment in
determining whether there is an indication of impairment, the grouping of assets
for impairment assessment, and determinations about the future use of such
assets. Significant downward revisions in production forecasts or changes in
future development plans by producers, to the extent they affect our operations,
may necessitate assessment of the carrying amount of the affected assets for
recoverability. The primary assumptions used to estimate undiscounted future net
cash flows include long-range customer production forecasts and revenue,
capital, and operating expense estimates. The measure of impairments to be
recognized, if any, depends upon management's estimate of the asset's fair
value, which may be determined based on the estimates of future net cash flows
or values at which similar assets were transferred in the market in recent
transactions, if such data is available. See Note 8-Property, Plant, and
Equipment in the Notes to Consolidated Financial Statements under Part II, Item
8 of this Form 10-K for a description of impairments recorded during the years
ended December 31, 2019, 2018, and 2017.




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Fair value. Among other things, management estimates fair value (i) of
long-lived assets for impairment testing, (ii) of reporting units for goodwill
impairment testing when necessary, (iii) of assets and liabilities acquired in a
business combination or exchanged in non-monetary transactions, (iv) for the
initial measurement of asset retirement obligations, (v) for the initial
measurement of environmental obligations assumed in a third-party acquisition,
and (vi) of interest-rate swaps. When management is required to measure fair
value and there is not a market-observable price for the asset or liability or a
market-observable price for a similar asset or liability, management utilizes
the cost, income, or multiples approach, depending on the quality of information
available to support management's assumptions. The cost approach is based on
management's best estimate of the current asset replacement cost. The income
approach uses management's best assumptions regarding expectations of projected
cash flows and discounts the expected cash flows using a commensurate
risk-adjusted discount rate. Such evaluations involve significant judgment
because results are based on expected future events or conditions, such as sales
prices, estimates of future throughput, capital and operating costs and the
timing thereof, economic and regulatory climates, and other factors. A multiples
approach uses management's best assumptions regarding expectations of projected
EBITDA and an assumed multiple of that EBITDA that a willing buyer would pay to
acquire an asset. Management's estimates of future net cash flows and EBITDA are
inherently imprecise because they reflect management's expectation of future
conditions that are often outside of management's control. However, the
assumptions used reflect a market participant's view of long-term prices, costs,
and other factors, and are consistent with assumptions used in our business
plans and investment decisions. See Note 1-Summary of Significant Accounting
Policies in the Notes to Consolidated Financial Statements under Part II, Item 8
of this Form 10-K.

                         OFF-BALANCE SHEET ARRANGEMENTS

We do not have any off-balance sheet arrangements other than short-term
operating leases and standby letters of credit. The information pertaining to
operating leases and standby letters of credit required for this item is
provided under Note 1-Summary of Significant Accounting Policies,
Note 14-Leases, and Note 13-Debt and Interest Expense, respectively, included in
the Notes to Consolidated Financial Statements under Part II, Item 8 of this
Form 10-K.

                         RECENT ACCOUNTING DEVELOPMENTS

See Note 1-Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

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