Item 1.
Financial Statements
WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
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Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except per-unit amounts
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Revenues and other – affiliates
|
|
|
|
|
|
|
|
|
Gathering, processing and transportation
|
|
$
|
154,984
|
|
|
$
|
186,733
|
|
|
$
|
327,298
|
|
|
$
|
374,451
|
|
Natural gas and natural gas liquids sales
|
|
161,329
|
|
|
115,672
|
|
|
304,170
|
|
|
200,538
|
|
Total revenues and other – affiliates
|
|
316,313
|
|
|
302,405
|
|
|
631,468
|
|
|
574,989
|
|
Revenues and other – third parties
|
|
|
|
|
|
|
|
|
Gathering, processing and transportation
|
|
144,451
|
|
|
114,403
|
|
|
279,951
|
|
|
220,689
|
|
Natural gas and natural gas liquids sales
|
|
63,495
|
|
|
11,321
|
|
|
127,179
|
|
|
15,011
|
|
Other
|
|
1,191
|
|
|
535
|
|
|
3,045
|
|
|
1,116
|
|
Total revenues and other – third parties
|
|
209,137
|
|
|
126,259
|
|
|
410,175
|
|
|
236,816
|
|
Total revenues and other
|
|
525,450
|
|
|
428,664
|
|
|
1,041,643
|
|
|
811,805
|
|
Equity income, net – affiliates
|
|
21,728
|
|
|
19,693
|
|
|
41,189
|
|
|
36,507
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Cost of product
(1)
|
|
203,277
|
|
|
104,849
|
|
|
392,636
|
|
|
181,316
|
|
Operation and maintenance
(1)
|
|
76,148
|
|
|
75,173
|
|
|
149,908
|
|
|
151,386
|
|
General and administrative
(1)
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|
10,585
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|
|
10,883
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|
|
23,244
|
|
|
22,160
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|
Property and other taxes
|
|
11,924
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|
|
12,078
|
|
|
24,218
|
|
|
22,428
|
|
Depreciation and amortization
|
|
74,031
|
|
|
67,305
|
|
|
143,733
|
|
|
132,400
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|
Impairments
|
|
3,178
|
|
|
2,403
|
|
|
167,920
|
|
|
8,921
|
|
Total operating expenses
|
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379,143
|
|
|
272,691
|
|
|
901,659
|
|
|
518,611
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Gain (loss) on divestiture and other, net
|
|
15,458
|
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|
(1,907
|
)
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|
134,945
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|
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(2,539
|
)
|
Proceeds from business interruption insurance claims
|
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24,115
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|
2,603
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|
29,882
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|
2,603
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Operating income (loss)
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|
207,608
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|
176,362
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|
346,000
|
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|
329,765
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Interest income – affiliates
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4,225
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|
4,225
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|
8,450
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|
8,450
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|
Interest expense
(2)
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|
(35,746
|
)
|
|
(12,883
|
)
|
|
(71,250
|
)
|
|
(44,919
|
)
|
Other income (expense), net
|
|
253
|
|
|
(53
|
)
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|
683
|
|
|
71
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|
Income (loss) before income taxes
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176,340
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|
167,651
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283,883
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293,367
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Income tax (benefit) expense
|
|
843
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|
|
326
|
|
|
4,395
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|
|
6,959
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|
Net income (loss)
|
|
175,497
|
|
|
167,325
|
|
|
279,488
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|
286,408
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|
Net income attributable to noncontrolling interest
|
|
2,046
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|
2,804
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|
4,148
|
|
|
5,827
|
|
Net income (loss) attributable to Western Gas Partners, LP
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$
|
173,451
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$
|
164,521
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$
|
275,340
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$
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280,581
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Limited partners’ interest in net income (loss):
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Net income (loss) attributable to Western Gas Partners, LP
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$
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173,451
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$
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164,521
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$
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275,340
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|
$
|
280,581
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|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
—
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|
|
—
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|
|
—
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|
|
(11,326
|
)
|
Series A Preferred units interest in net (income) loss
|
|
(14,199
|
)
|
|
(23,121
|
)
|
|
(42,373
|
)
|
|
(25,450
|
)
|
General partner interest in net (income) loss
(3)
|
|
(76,365
|
)
|
|
(58,381
|
)
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|
(144,527
|
)
|
|
(113,781
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)
|
Common and Class C limited partners’ interest in net income (loss)
(3)
|
|
82,887
|
|
|
83,019
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|
88,440
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|
130,024
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Net income (loss) per common unit – basic and diluted
(4)
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$
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0.49
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$
|
0.55
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|
$
|
0.53
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|
$
|
0.86
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(1)
|
Cost of product includes product purchases from Anadarko (as defined in
Note 1
) of
$21.6 million
and
$37.6 million
for the
three and six months ended June 30, 2017
, respectively, and
$22.1 million
and
$46.7 million
for the
three and six months ended June 30, 2016
, respectively. Operation and maintenance includes charges from Anadarko of
$18.5 million
and
$35.6 million
for the
three and six months ended June 30, 2017
, respectively, and
$17.7 million
and
$35.6 million
for the
three and six months ended June 30, 2016
, respectively. General and administrative includes charges from Anadarko of
$9.4 million
and
$18.9 million
for the
three and six months ended June 30, 2017
, respectively, and
$9.2 million
and
$18.1 million
for the
three and six months ended June 30, 2016
, respectively. See
Note 5
.
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(2)
|
Includes affiliate (as defined in
Note 1
) amounts of
zero
and
$(0.1) million
for the
three and six months ended June 30, 2017
, respectively, and
$15.5 million
and
$10.9 million
for the
three and six months ended June 30, 2016
, respectively. See
Note 2
and
Note 9
.
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(3)
|
Represents net income (loss) earned on and subsequent to the date of acquisition of the Partnership assets (as defined in
Note 1
). See
Note 4
.
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|
|
(4)
|
See
Note 4
for the calculation of net income (loss) per common unit.
|
See accompanying Notes to Consolidated Financial Statements.
6
WESTERN GAS PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
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|
thousands except number of units
|
|
June 30,
2017
|
|
December 31,
2016
|
ASSETS
|
|
|
|
|
Current assets
|
|
|
|
|
Cash and cash equivalents
|
|
$
|
188,197
|
|
|
$
|
357,925
|
|
Accounts receivable, net
(1)
|
|
136,444
|
|
|
223,223
|
|
Other current assets
|
|
10,161
|
|
|
12,866
|
|
Total current assets
|
|
334,802
|
|
|
594,014
|
|
Note receivable – Anadarko
|
|
260,000
|
|
|
260,000
|
|
Property, plant and equipment
|
|
|
|
|
Cost
|
|
7,354,782
|
|
|
6,861,942
|
|
Less accumulated depreciation
|
|
2,006,988
|
|
|
1,812,010
|
|
Net property, plant and equipment
|
|
5,347,794
|
|
|
5,049,932
|
|
Goodwill
|
|
417,610
|
|
|
417,610
|
|
Other intangible assets
|
|
789,483
|
|
|
803,698
|
|
Equity investments
|
|
581,151
|
|
|
594,208
|
|
Other assets
|
|
14,875
|
|
|
13,566
|
|
Total assets
|
|
$
|
7,745,715
|
|
|
$
|
7,733,028
|
|
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
|
|
|
|
|
Current liabilities
|
|
|
|
|
Accounts and imbalance payables
(2)
|
|
$
|
198,496
|
|
|
$
|
247,076
|
|
Accrued ad valorem taxes
|
|
22,059
|
|
|
23,121
|
|
Accrued liabilities
(3)
|
|
56,840
|
|
|
45,108
|
|
Total current liabilities
|
|
277,395
|
|
|
315,305
|
|
Long-term debt
|
|
3,253,065
|
|
|
3,091,461
|
|
Deferred income taxes
|
|
10,169
|
|
|
6,402
|
|
Asset retirement obligations and other
|
|
142,526
|
|
|
142,641
|
|
Deferred purchase price obligation – Anadarko
(4)
|
|
—
|
|
|
41,440
|
|
Total long-term liabilities
|
|
3,405,760
|
|
|
3,281,944
|
|
Total liabilities
|
|
3,683,155
|
|
|
3,597,249
|
|
Equity and partners’ capital
|
|
|
|
|
Series A Preferred units (zero and 21,922,831 units issued and outstanding at June 30, 2017, and December 31, 2016, respectively)
(5)
|
|
—
|
|
|
639,545
|
|
Common units (152,602,105 and 130,671,970 units issued and outstanding at June 30, 2017, and December 31, 2016, respectively)
|
|
3,070,608
|
|
|
2,536,872
|
|
Class C units (12,743,318 and 12,358,123 units issued and outstanding at June 30, 2017, and December 31, 2016, respectively)
(6)
|
|
764,174
|
|
|
750,831
|
|
General partner units (2,583,068 units issued and outstanding at June 30, 2017, and December 31, 2016)
|
|
165,442
|
|
|
143,968
|
|
Total partners’ capital
|
|
4,000,224
|
|
|
4,071,216
|
|
Noncontrolling interest
|
|
62,336
|
|
|
64,563
|
|
Total equity and partners’ capital
|
|
4,062,560
|
|
|
4,135,779
|
|
Total liabilities, equity and partners’ capital
|
|
$
|
7,745,715
|
|
|
$
|
7,733,028
|
|
|
|
(1)
|
Accounts receivable, net includes amounts receivable from affiliates (as defined in
Note 1
) of
$63.0 million
and
$76.6 million
as of
June 30, 2017
, and December 31,
2016
, respectively. Accounts receivable, net as of December 31,
2016
, also includes an insurance claim receivable related to an incident at the DBM complex. See
Note 1
.
|
|
|
(2)
|
Accounts and imbalance payables includes affiliate amounts of
$0.2 million
and
zero
as of
June 30, 2017
, and December 31,
2016
, respectively.
|
|
|
(3)
|
Accrued liabilities includes affiliate amounts of
$0.3 million
and
zero
as of
June 30, 2017
, and December 31,
2016
, respectively.
|
|
|
(5)
|
The Series A Preferred units converted into common units on a
one
-for-one basis in 2017. See
Note 4
.
|
|
|
(6)
|
The Class C units will convert into common units on a
one
-for-one basis on March 1, 2020, unless the Partnership elects to convert such units earlier or Anadarko extends the conversion date. See
Note 4
.
|
See accompanying Notes to Consolidated Financial Statements.
7
WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS’ CAPITAL
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners’ Capital
|
|
|
|
|
thousands
|
|
Net
Investment
by Anadarko
|
|
Common
Units
|
|
Class C
Units
|
|
Series A Preferred Units
|
|
General
Partner
Units
|
|
Noncontrolling
Interest
|
|
Total
|
Balance at December 31, 2016
|
|
$
|
—
|
|
|
$
|
2,536,872
|
|
|
$
|
750,831
|
|
|
$
|
639,545
|
|
|
$
|
143,968
|
|
|
$
|
64,563
|
|
|
$
|
4,135,779
|
|
Net income (loss)
|
|
—
|
|
|
112,818
|
|
|
10,542
|
|
|
7,453
|
|
|
144,527
|
|
|
4,148
|
|
|
279,488
|
|
Above-market component of swap agreements with Anadarko
(1)
|
|
—
|
|
|
28,670
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
28,670
|
|
Conversion of Series A Preferred units into common units
(2)
|
|
—
|
|
|
686,936
|
|
|
—
|
|
|
(686,936
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of beneficial conversion feature of Class C units and Series A Preferred units
|
|
—
|
|
|
(65,100
|
)
|
|
2,801
|
|
|
62,299
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Distributions to noncontrolling interest owner
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,375
|
)
|
|
(6,375
|
)
|
Distributions to unitholders
|
|
—
|
|
|
(236,307
|
)
|
|
—
|
|
|
(22,361
|
)
|
|
(123,103
|
)
|
|
—
|
|
|
(381,771
|
)
|
Acquisitions from affiliates
|
|
(30
|
)
|
|
30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Revision to Deferred purchase price obligation – Anadarko
(3)
|
|
—
|
|
|
4,165
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,165
|
|
Contributions of equity-based compensation from Anadarko
|
|
—
|
|
|
2,192
|
|
|
—
|
|
|
—
|
|
|
44
|
|
|
—
|
|
|
2,236
|
|
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
30
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
30
|
|
Net contributions from (distributions to) Anadarko of other assets
|
|
—
|
|
|
370
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
376
|
|
Other
|
|
—
|
|
|
(38
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(38
|
)
|
Balance at June 30, 2017
|
|
$
|
—
|
|
|
$
|
3,070,608
|
|
|
$
|
764,174
|
|
|
$
|
—
|
|
|
$
|
165,442
|
|
|
$
|
62,336
|
|
|
$
|
4,062,560
|
|
See accompanying Notes to Consolidated Financial Statements.
8
WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
thousands
|
|
2017
|
|
2016
|
Cash flows from operating activities
|
|
|
|
|
Net income (loss)
|
|
$
|
279,488
|
|
|
$
|
286,408
|
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
|
|
|
|
Depreciation and amortization
|
|
143,733
|
|
|
132,400
|
|
Impairments
|
|
167,920
|
|
|
8,921
|
|
Non-cash equity-based compensation expense
|
|
2,393
|
|
|
2,391
|
|
Deferred income taxes
|
|
3,767
|
|
|
1,980
|
|
Accretion and amortization of long-term obligations, net
|
|
2,139
|
|
|
(9,055
|
)
|
Equity income, net – affiliates
|
|
(41,189
|
)
|
|
(36,507
|
)
|
Distributions from equity investment earnings – affiliates
|
|
42,202
|
|
|
38,519
|
|
(Gain) loss on divestiture and other, net
|
|
(134,945
|
)
|
|
2,539
|
|
Lower of cost or market inventory adjustments
|
|
140
|
|
|
—
|
|
Changes in assets and liabilities:
|
|
|
|
|
(Increase) decrease in accounts receivable, net
|
|
9,363
|
|
|
(33,242
|
)
|
Increase (decrease) in accounts and imbalance payables and accrued liabilities, net
|
|
(41,975
|
)
|
|
(2,227
|
)
|
Change in other items, net
|
|
116
|
|
|
1,739
|
|
Net cash provided by operating activities
|
|
433,152
|
|
|
393,866
|
|
Cash flows from investing activities
|
|
|
|
|
Capital expenditures
|
|
(260,480
|
)
|
|
(255,923
|
)
|
Contributions in aid of construction costs from affiliates
|
|
1,343
|
|
|
3,854
|
|
Acquisitions from affiliates
|
|
(3,910
|
)
|
|
(715,199
|
)
|
Acquisitions from third parties
|
|
(155,287
|
)
|
|
—
|
|
Investments in equity affiliates
|
|
(287
|
)
|
|
139
|
|
Distributions from equity investments in excess of cumulative earnings – affiliates
|
|
9,221
|
|
|
10,611
|
|
Proceeds from the sale of assets to affiliates
|
|
—
|
|
|
613
|
|
Proceeds from the sale of assets to third parties
|
|
23,292
|
|
|
137
|
|
Proceeds from property insurance claims
|
|
22,977
|
|
|
2,944
|
|
Net cash used in investing activities
|
|
(363,131
|
)
|
|
(952,824
|
)
|
Cash flows from financing activities
|
|
|
|
|
Borrowings, net of debt issuance costs
|
|
159,989
|
|
|
530,000
|
|
Repayments of debt
|
|
—
|
|
|
(290,000
|
)
|
Settlement of the Deferred purchase price obligation – Anadarko
(1)
|
|
(37,346
|
)
|
|
—
|
|
Increase (decrease) in outstanding checks
|
|
(2,763
|
)
|
|
(1,314
|
)
|
Proceeds from the issuance of common units, net of offering expenses
|
|
(183
|
)
|
|
25,000
|
|
Proceeds from the issuance of Series A Preferred units, net of offering expenses
|
|
—
|
|
|
686,940
|
|
Distributions to unitholders
(2)
|
|
(381,771
|
)
|
|
(313,380
|
)
|
Distributions to noncontrolling interest owner
|
|
(6,375
|
)
|
|
(7,460
|
)
|
Net contributions from (distributions to) Anadarko
|
|
30
|
|
|
(27,459
|
)
|
Above-market component of swap agreements with Anadarko
(2)
|
|
28,670
|
|
|
16,365
|
|
Net cash provided by (used in) financing activities
|
|
(239,749
|
)
|
|
618,692
|
|
Net increase (decrease) in cash and cash equivalents
|
|
(169,728
|
)
|
|
59,734
|
|
Cash and cash equivalents at beginning of period
|
|
357,925
|
|
|
98,033
|
|
Cash and cash equivalents at end of period
|
|
$
|
188,197
|
|
|
$
|
157,767
|
|
Supplemental disclosures
|
|
|
|
|
Accretion expense and revisions to the Deferred purchase price obligation – Anadarko
(1)
|
|
$
|
(4,094
|
)
|
|
$
|
(159,524
|
)
|
Net distributions to (contributions from) Anadarko of other assets
|
|
(376
|
)
|
|
354
|
|
Interest paid, net of capitalized interest
|
|
68,396
|
|
|
53,973
|
|
Taxes paid (reimbursements received)
|
|
189
|
|
|
67
|
|
Accrued capital expenditures
|
|
100,038
|
|
|
70,725
|
|
Fair value of properties and equipment from non-cash third party transactions
(1)
|
|
551,453
|
|
|
—
|
|
See accompanying Notes to Consolidated Financial Statements.
9
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
General.
Western Gas Partners, LP is a growth-oriented Delaware master limited partnership (“MLP”) formed by Anadarko Petroleum Corporation in 2007 to acquire, own, develop and operate midstream energy assets.
For purposes of these consolidated financial statements, the “Partnership” refers to Western Gas Partners, LP and its subsidiaries. The Partnership’s general partner, Western Gas Holdings, LLC (the “general partner”), is owned by Western Gas Equity Partners, LP (“WGP”), a Delaware MLP formed by Anadarko Petroleum Corporation in September 2012 to own the Partnership’s general partner, as well as a significant limited partner interest in the Partnership. WGP has no independent operations or material assets other than owning the partnership interests in the Partnership (see
Holdings of Partnership equity
in
Note 4
). Western Gas Equity Holdings, LLC is WGP’s general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. “Anadarko” refers to Anadarko Petroleum Corporation and its subsidiaries, excluding the Partnership and the general partner, and “affiliates” refers to subsidiaries of Anadarko, excluding the Partnership, but including equity interests in Fort Union Gas Gathering, LLC (“Fort Union”), White Cliffs Pipeline, LLC (“White Cliffs”), Rendezvous Gas Services, LLC (“Rendezvous”), Enterprise EF78 LLC (the “Mont Belvieu JV”), Texas Express Pipeline LLC (“TEP”), Texas Express Gathering LLC (“TEG”) and Front Range Pipeline LLC (“FRP”). The interests in TEP, TEG and FRP are referred to collectively as the “TEFR Interests.” “MGR assets” refers to the Red Desert complex and the Granger straddle plant.
The Partnership is engaged in the business of gathering, compressing, treating, processing and transporting natural gas; gathering, stabilizing and transporting condensate, natural gas liquids (“NGLs”) and crude oil; and gathering and disposing of produced water. The Partnership provides these midstream services for Anadarko, as well as for third-party producers and customers. As of
June 30, 2017
, the Partnership’s assets and investments consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity
Interests
|
Gathering systems
|
|
12
|
|
|
3
|
|
|
3
|
|
|
2
|
|
Treating facilities
|
|
19
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Natural gas processing plants/trains
|
|
19
|
|
|
5
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipelines
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
These assets and investments are located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania and Texas. During the second quarter of 2017, the Partnership commenced operation of two produced-water disposal systems in West Texas, which are included within Gathering systems in the table above.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
Basis of presentation.
The following table outlines the Partnership’s ownership interests and the accounting method of consolidation used in the Partnership’s consolidated financial statements:
|
|
|
|
|
|
|
Percentage Interest
|
Equity investments
(1)
|
|
|
Fort Union
|
|
14.81
|
%
|
White Cliffs
|
|
10
|
%
|
Rendezvous
|
|
22
|
%
|
Mont Belvieu JV
|
|
25
|
%
|
TEP
|
|
20
|
%
|
TEG
|
|
20
|
%
|
FRP
|
|
33.33
|
%
|
Proportionate consolidation
(2)
|
|
|
Marcellus Interest systems
|
|
33.75
|
%
|
Newcastle system
|
|
50
|
%
|
Springfield system
|
|
50.1
|
%
|
Full consolidation
|
|
|
Chipeta
(3)
|
|
75
|
%
|
DBJV system
(4)
|
|
100
|
%
|
|
|
(1)
|
Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method. “Equity investment throughput” refers to the Partnership’s share of average throughput for these investments.
|
|
|
(2)
|
The Partnership proportionately consolidates its associated share of the assets, liabilities, revenues and expenses attributable to these assets.
|
|
|
(3)
|
The
25%
interest in Chipeta Processing LLC (“Chipeta”) held by a third-party member is reflected within noncontrolling interest in the consolidated financial statements.
|
|
|
(4)
|
The Partnership acquired an additional
50%
interest in the DBJV system (the “Additional DBJV System Interest”) from a third party on March 17, 2017. See
Note 2
.
|
The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“GAAP”). The consolidated financial statements include the accounts of the Partnership and entities in which it holds a controlling financial interest. All significant intercompany transactions have been eliminated.
Certain information and note disclosures commonly included in annual financial statements have been condensed or omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, the accompanying consolidated financial statements and notes should be read in conjunction with the Partnership’s 2016 Form 10-K, as filed with the SEC on February 23, 2017. Management believes that the disclosures made are adequate to make the information not misleading.
Presentation of Partnership assets.
The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method (see
Note 7
) by the Partnership as of
June 30, 2017
. Because Anadarko controls the Partnership through its ownership and control of WGP, which owns the Partnership’s entire general partner interest, each acquisition of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by the Partnership. Further, after an acquisition of Partnership assets from Anadarko, the Partnership may be required to recast its financial statements to include the activities of such Partnership assets from the date of common control.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
For those periods requiring recast, the consolidated financial statements for periods prior to the Partnership’s acquisition of the Partnership assets from Anadarko are prepared from Anadarko’s historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if the Partnership had owned the Partnership assets during the periods reported. Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the limited partners.
Use of estimates.
In preparing financial statements in accordance with GAAP, management makes informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. Management evaluates its estimates and related assumptions regularly, using historical experience and other methods considered reasonable. Changes in facts and circumstances or additional information may result in revised estimates and actual results may differ from these estimates. Effects on the business, financial condition and results of operations resulting from revisions to estimates are recognized when the facts that give rise to the revisions become known. The information furnished herein reflects all normal recurring adjustments which are, in the opinion of management, necessary for a fair presentation of the consolidated financial statements, and certain prior-period amounts have been reclassified to conform to the current-year presentation.
Insurance recoveries.
Involuntary conversions result from the loss of an asset because of some unforeseen event (e.g., destruction due to fire). Some of these events are insurable and result in property damage insurance recovery. Amounts that are received from insurance carriers are net of any deductibles related to the covered event. A receivable is recorded from insurance to the extent a loss is recognized from an involuntary conversion event and the likelihood of recovering such loss is deemed probable. To the extent that any insurance claim receivables are later judged not probable of recovery (e.g., due to new information), such amounts are expensed. A gain on involuntary conversion is recognized when the amount received from insurance exceeds the net book value of the retired asset(s). In addition, gains related to insurance recoveries are not recognized until all contingencies related to such proceeds have been resolved, that is, a cash payment is received from the insurance carrier or there is a binding settlement agreement with the carrier that clearly states that a payment will be made. To the extent that an asset is rebuilt, the associated expenditures are capitalized, as appropriate, in the consolidated balance sheets and presented as capital expenditures in the consolidated statements of cash flows. With respect to business interruption insurance claims, income is recognized only when cash proceeds are received from insurers, which are presented in the consolidated statements of operations as a component of Operating income (loss).
On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the Delaware Basin Midstream, LLC (“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. Train II (with capacity of
100
MMcf/d) sustained the most damage of the processing trains and returned to service in December 2016. Train III (with capacity of
200
MMcf/d) experienced minimal damage and returned to full service in May 2016. During the quarter ended March 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 Partnership’s estimate of the amount that will be recovered under the property insurance claim based on further discussions with insurers. During the second quarter of 2017, the Partnership reached a settlement with insurers and final proceeds were received. As of
June 30, 2017
, and December 31,
2016
, the consolidated balance sheets include receivables of
zero
and
$30.0 million
, respectively, for the property insurance claim related to the incident at the DBM complex. During the
six months ended June 30, 2017
, the Partnership received
$52.9 million
in cash proceeds from insurers in final settlement of the Partnership’s claims related to the incident at the DBM complex, including
$29.9 million
in proceeds from business interruption insurance claims and
$23.0 million
in proceeds from property insurance claims.
Recently adopted accounting standards.
Accounting Standards Update (“ASU”) 2017-01,
Business Combinations (Topic 805): Clarifying the Definition of a Business
assists in determining whether a transaction should be accounted for as an acquisition or disposal of assets or as a business. This ASU provides a screen that when substantially all of the fair value of the gross assets acquired, or disposed of, are concentrated in a single identifiable asset, or a group of similar identifiable assets, the set will not be considered a business. If the screen is not met, a set must include an input and a substantive process that together significantly contribute to the ability to create an output to be considered a business. The Partnership’s adoption of this ASU on January 1, 2017, using a prospective approach, could have a material impact on future consolidated financial statements as goodwill will not be allocated to divestitures or recorded on acquisitions that are not considered to be a business.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
ASU 2016-16,
Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory
requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs and eliminates the exception for an intra-entity transfer of an asset other than inventory. The Partnership adopted this ASU on January 1, 2017, using a modified retrospective approach, with no impact to its consolidated financial statements.
New accounting standards issued but not yet adopted.
ASU 2016-18,
Statement of Cash Flows (Topic 230): Restricted Cash
requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statement of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The Partnership will adopt this ASU on January 1, 2018, and does not expect the adoption to have a material impact on its consolidated financial statements.
ASU 2016-15,
Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments
provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable, with early adoption permitted. The Partnership will adopt this ASU on January 1, 2018, and does not expect the adoption to have a material impact on its consolidated statement of cash flows.
ASU 2016-02,
Leases (Topic 842)
requires lessees to recognize a lease liability and a right-of-use asset for all leases, including operating leases, with a term greater than 12 months on the balance sheet. The provisions of ASU 2016-02 also modify the definition of a lease and outline the requirements for recognition, measurement, presentation and disclosure of leasing arrangements by both lessees and lessors. This ASU is effective for annual and interim periods beginning after December 15, 2018, and a modified retrospective approach is required for all comparative periods presented. The Partnership plans to elect certain
practical expedients when implementing the new lease standard, which means the
Partnership
will not have to reassess the accounting for contracts that commenced prior to adoption
. The Partnership is continuing to analyze its portfolio of contracts to assess the application of this ASU to certain types of contracts, its current business processes and the impact that adoption will have on its consolidated financial statements.
ASU 2014-09,
Revenue from Contracts with Customers (Topic 606)
supersedes current revenue recognition requirements and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers. The Partnership has completed an initial review of contracts in each of its revenue streams and is developing accounting policies to address the provisions of the ASU. The Partnership is currently analyzing whether total revenues and total expenses may increase as a result of recognizing both revenue for noncash consideration for services provided and revenue and associated cost of product for the subsequent sale of commodities received as such noncash consideration. The Partnership continues to evaluate the impact of this and other provisions of the ASU on accounting policies, internal controls and consolidated financial statements and related disclosures, and has not finalized any estimates of the potential impacts. The Partnership will adopt this new standard on January 1, 2018, using the modified retrospective method with a cumulative adjustment to equity and partners’ capital.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
2. ACQUISITIONS AND DIVESTITURES
The following table presents the acquisitions completed by the Partnership during
2017
and
2016
, and identifies the funding sources for such acquisitions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands except unit and percent amounts
|
|
Acquisition
Date
|
|
Percentage
Acquired
|
|
Borrowings
|
|
Cash
On Hand
|
|
Common Units
Issued
|
|
Series A
Preferred Units Issued
|
Springfield system
(1)
|
|
03/14/2016
|
|
50.1
|
%
|
|
$
|
247,500
|
|
|
$
|
—
|
|
|
2,089,602
|
|
|
14,030,611
|
|
DBJV system
(2)
|
|
03/17/2017
|
|
50
|
%
|
|
—
|
|
|
155,000
|
|
|
—
|
|
|
—
|
|
|
|
(1)
|
The Partnership acquired Springfield Pipeline LLC (“Springfield”) from Anadarko for
$750.0 million
, consisting of
$712.5 million
in cash and the issuance of
1,253,761
of the Partnership’s common units. Springfield owns a
50.1%
interest in an oil gathering system and a gas gathering system, such interest being referred to in this report as the “Springfield interest.” The Springfield oil and gas gathering systems (collectively, the “Springfield system”) are located in Dimmit, La Salle, Maverick and Webb Counties in South Texas. The Partnership financed the cash portion of the acquisition through: (i) borrowings of
$247.5 million
on the Partnership’s senior unsecured revolving credit facility (“RCF”), (ii) the issuance of
835,841
of the Partnership’s common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See
Note 4
for further information regarding the Series A Preferred units.
|
|
|
(2)
|
The Partnership acquired the Additional DBJV System Interest from a third party. See
Property exchange
below.
|
Property exchange.
On March 17, 2017, the Partnership acquired the Additional DBJV System Interest from a third party in exchange for (a) the Partnership’s
33.75%
non-operated interest in two natural gas gathering systems located in northern Pennsylvania (the “Non-Operated Marcellus Interest”), commonly referred to as the Liberty and Rome systems, and (b)
$155.0 million
of cash consideration (collectively, the “Property Exchange”). The Partnership previously held a
50%
interest in, and operated, the DBJV system.
The Property Exchange is reflected as a nonmonetary transaction whereby the acquired Additional DBJV System Interest is recorded at the fair value of the divested Non-Operated Marcellus Interest plus the
$155.0 million
of cash consideration. The Property Exchange resulted in a net gain of
$125.7 million
recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. Results of operations attributable to the Property Exchange were included in the Partnership’s consolidated statement of operations beginning on the acquisition date in the first quarter of 2017.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
2. ACQUISITIONS AND DIVESTITURES (CONTINUED)
DBJV acquisition - Deferred purchase price obligation - Anadarko.
Prior to the Partnership’s agreement with Anadarko to settle its deferred purchase price obligation early, the consideration that would have been paid by the Partnership for the March 2015 acquisition of Delaware Basin JV Gathering LLC (“DBJV”) from Anadarko, consisted of a cash payment to Anadarko due on March 31, 2020. The cash payment would have been equal to (a) eight multiplied by the average of the Partnership’s share in the Net Earnings (see definition below) of DBJV for the calendar years 2018 and 2019, less (b) the Partnership’s share of all capital expenditures incurred for DBJV between March 1, 2015, and February 29, 2020. Net Earnings was defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to DBJV on an accrual basis. In May 2017, the Partnership reached an agreement with Anadarko to settle this obligation whereby the Partnership made a cash payment to Anadarko of
$37.3 million
, equal to the net present value of the obligation at March 31, 2017.
The following table summarizes the financial statement impact of the Deferred purchase price obligation - Anadarko:
|
|
|
|
|
|
|
|
|
|
|
|
Deferred purchase price obligation - Anadarko
|
|
Estimated future payment obligation
(1)
|
Balance at December 31, 2016
|
|
$
|
41,440
|
|
|
$
|
56,455
|
|
Accretion expense
(2)
|
|
71
|
|
|
|
Revision to Deferred purchase price obligation – Anadarko
(3)
|
|
(4,165
|
)
|
|
|
Balance at March 31, 2017
|
|
37,346
|
|
|
49,694
|
|
Settlement of the Deferred purchase price obligation – Anadarko
|
|
(37,346
|
)
|
|
|
Balance at June 30, 2017
|
|
$
|
—
|
|
|
$
|
—
|
|
|
|
(1)
|
Calculated using Level 3 inputs.
|
|
|
(2)
|
Accretion expense was recorded as a charge to Interest expense in the consolidated statements of operations.
|
|
|
(3)
|
Recorded as revisions within Common units in the consolidated balance sheet and consolidated statement of equity and partners’ capital.
|
Helper and Clawson systems divestiture.
During the second quarter of 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in a net gain on sale of
$16.3 million
recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
Hugoton system divestiture.
During the fourth quarter of 2016, the Hugoton system, located in Southwest Kansas and Oklahoma, was sold to a third party, resulting in a net loss on sale of
$12.0 million
recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. The Partnership allocated
$1.6 million
in goodwill to this divestiture.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
3. PARTNERSHIP DISTRIBUTIONS
The partnership agreement requires the Partnership to distribute all of its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within
45
days of the end of each quarter. The Board of Directors of the Partnership’s general partner (the “Board of Directors”) declared the following cash distributions to the Partnership’s common and general partner unitholders for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands except per-unit amounts
Quarters Ended
|
|
Total Quarterly
Distribution
per Unit
|
|
Total Quarterly
Cash Distribution
|
|
Date of
Distribution
|
2016
|
|
|
|
|
|
|
March 31
|
|
$
|
0.815
|
|
|
$
|
158,905
|
|
|
May 2016
|
June 30
|
|
0.830
|
|
|
162,827
|
|
|
August 2016
|
September 30
|
|
0.845
|
|
|
166,742
|
|
|
November 2016
|
December 31
|
|
0.860
|
|
|
170,657
|
|
|
February 2017
|
2017
|
|
|
|
|
|
|
March 31
|
|
$
|
0.875
|
|
|
$
|
188,753
|
|
|
May 2017
|
June 30
(1)
|
|
0.890
|
|
|
207,491
|
|
|
August 2017
|
|
|
(1)
|
The Board of Directors declared a cash distribution to the Partnership’s unitholders for the
second quarter
of
2017
of
$0.890
per unit, or
$207.5 million
in aggregate, including incentive distributions, but excluding distributions on Class C units (see
Class C unit distributions
below). The cash distribution
is payable
on
August 11, 2017
, to unitholders of record at the close of business on
July 31, 2017
.
|
Available cash.
The amount of available cash (as defined in the partnership agreement) generally is all cash on hand at the end of the quarter, plus, at the discretion of the general partner, working capital borrowings made subsequent to the end of such quarter, less the amount of cash reserves established by the Partnership’s general partner to provide for the proper conduct of the Partnership’s business, including reserves to fund future capital expenditures; to comply with applicable laws, debt instruments or other agreements; or to provide funds for distributions to its unitholders and to its general partner for any one or more of the next four quarters. Working capital borrowings generally include borrowings made under a credit facility or similar financing arrangement. Working capital borrowings may only be those that, at the time of such borrowings, were intended to be repaid within 12 months. In all cases, working capital borrowings are used solely for working capital purposes or to fund distributions to partners.
Class C unit distributions.
The Class C units receive quarterly distributions at a rate equivalent to the Partnership’s common units. The distributions are paid in the form of additional Class C units (“PIK Class C units”) until the scheduled conversion date on March 1, 2020 (unless earlier converted), and the Class C units are disregarded with respect to distributions of the Partnership’s available cash until they are converted to common units. The number of additional PIK Class C units to be issued in connection with a distribution payable on the Class C units is determined by dividing the corresponding distribution attributable to the Class C units by the volume-weighted-average price of the Partnership’s common units for the ten days immediately preceding the payment date for the common unit distribution, less a
6%
discount. The Partnership records the PIK Class C unit distributions at fair value at the time of issuance. This Level 2 fair value measurement uses the Partnership’s unit price as a significant input in the determination of the fair value. See
Note 4
for further discussion of the Class C units.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
3. PARTNERSHIP DISTRIBUTIONS (CONTINUED)
Series A Preferred unit distributions.
As further described in
Note 4
, the Partnership issued Series A Preferred units representing limited partner interests in the Partnership to private investors in 2016. The Series A Preferred unitholders received quarterly distributions in cash equal to
$0.68
per Series A Preferred unit, subject to certain adjustments. The following table summarizes the Series A Preferred unitholders’ cash distributions for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands except per-unit amounts
Quarters Ended
|
|
Total Quarterly
Distribution
per Unit
|
|
Total Quarterly
Cash Distribution
|
|
Date of
Distribution
|
2016
|
|
|
|
|
|
|
March 31
(1)
|
|
$
|
0.68
|
|
|
$
|
1,887
|
|
|
May 2016
|
June 30
(2)
|
|
0.68
|
|
|
14,082
|
|
|
August 2016
|
September 30
|
|
0.68
|
|
|
14,908
|
|
|
November 2016
|
December 31
|
|
0.68
|
|
|
14,908
|
|
|
February 2017
|
2017
|
|
|
|
|
|
|
March 31
|
|
$
|
0.68
|
|
|
$
|
7,453
|
|
|
May 2017
|
|
|
(1)
|
Quarterly per unit distribution prorated for the
18
-day period during which
14,030,611
Series A Preferred units were outstanding during the first quarter of 2016.
|
|
|
(2)
|
Full quarterly per unit distribution on 14,030,611 Series A Preferred units and quarterly per unit distribution prorated for the
77
-day period during which
7,892,220
Series A Preferred units were outstanding during the second quarter of 2016.
|
On March 1, 2017,
50%
of the outstanding Series A Preferred units converted into common units on a
one
-for-one basis, and on May 2, 2017, the remaining Series A Preferred units converted into common units on a
one
-for-one basis. Such converted common units are entitled to distributions made to common unitholders with respect to the quarter during which the applicable conversion occurred and does not include a prorated Series A Preferred unit distribution.
General partner interest and incentive distribution rights.
As of
June 30, 2017
, the general partner was entitled to
1.5%
of all quarterly distributions that the Partnership makes prior to its liquidation and, as the holder of the incentive distribution rights (“IDRs”), was entitled to incentive distributions at the maximum distribution sharing percentage of
48.0%
for all periods presented, after the minimum quarterly distribution and the target distribution levels had been achieved. The maximum distribution sharing percentage of
49.5%
does not include any distributions that the general partner may receive on common units that it may acquire.
4. EQUITY AND PARTNERS’ CAPITAL
Class C units.
In November 2014, the Partnership issued
10,913,853
Class C units to Anadarko Midstream Holdings, LLC (“AMH”), pursuant to a Unit Purchase Agreement with Anadarko and AMH. The Class C units were issued to partially fund the acquisition of DBM.
When issued, the Class C units were scheduled to convert into common units on a
one
-for-one basis on December 31, 2017. In February 2017, Anadarko elected to extend the conversion date of the Class C units to March 1, 2020. The Partnership can elect to convert the Class C units earlier or Anadarko can extend the conversion date again.
The Class C units were issued at a discount to the then-current market price of the common units into which they are convertible. This discount, totaling
$34.8 million
, represents a beneficial conversion feature, and at issuance, was reflected as an increase in common unitholders’ capital and a decrease in Class C unitholder capital to reflect the fair value of the Class C units at issuance. The beneficial conversion feature is considered a non-cash distribution that is recognized from the date of issuance through the date of conversion, resulting in an increase in Class C unitholder capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion feature is amortized assuming the extended conversion date of March 1, 2020, using the effective yield method. The impact of the beneficial conversion feature amortization is also included in the calculation of earnings per unit.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)
Series A Preferred units.
In 2016, the Partnership issued
21,922,831
Series A Preferred units to private investors. Pursuant to an agreement between the Partnership and the holders of the Series A Preferred units,
50%
of the Series A Preferred units converted into common units on a
one
-for-one basis on March 1, 2017, and the remaining Series A Preferred units converted on a
one
-for-one basis on May 2, 2017. The Partnership has an effective registration statement with the SEC relating to the public resale of the common units issued upon conversion of the Series A Preferred units.
The Series A Preferred units were issued at a discount to the then-current market price of the common units into which they were convertible. This discount, totaling
$93.4 million
, represented a beneficial conversion feature, and at issuance, was reflected as an increase in common unitholders’ capital and a decrease in Series A Preferred unitholders’ capital to reflect the fair value of the Series A Preferred units on the date of issuance. The beneficial conversion feature was considered a non-cash distribution that was recognized from the date of issuance through the date of conversion, resulting in an increase in Series A Preferred unitholders’ capital and a decrease in common unitholders’ capital as amortized. The beneficial conversion feature was amortized using the effective yield method. The impact of the beneficial conversion feature amortization is also included in the calculation of earnings per unit. For the six months ended June 30, 2017, the amortization for the beneficial conversion feature of the Series A Preferred units was
$62.3 million
.
Partnership interests.
The Partnership’s common units are listed on the New York Stock Exchange under the symbol “WES.”
The following table summarizes the common, Class C, Series A Preferred and general partner units issued during the
six months ended June 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Units
|
|
Class C
Units
|
|
Series A
Preferred
Units
|
|
General
Partner
Units
|
|
Total
|
Balance at December 31, 2016
|
|
130,671,970
|
|
|
12,358,123
|
|
|
21,922,831
|
|
|
2,583,068
|
|
|
167,535,992
|
|
PIK Class C units
|
|
—
|
|
|
385,195
|
|
|
—
|
|
|
—
|
|
|
385,195
|
|
Conversion of Series A Preferred units
|
|
21,922,831
|
|
|
—
|
|
|
(21,922,831
|
)
|
|
—
|
|
|
—
|
|
Long-Term Incentive Plan award vestings
|
|
7,304
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
7,304
|
|
Balance at June 30, 2017
|
|
152,602,105
|
|
|
12,743,318
|
|
|
—
|
|
|
2,583,068
|
|
|
167,928,491
|
|
Holdings of Partnership equity.
As of
June 30, 2017
, WGP held
50,132,046
common units, representing a
29.9%
limited partner interest in the Partnership, and, through its ownership of the general partner, WGP indirectly held
2,583,068
general partner units, representing a
1.5%
general partner interest in the Partnership, and
100%
of the incentive distribution rights. As of
June 30, 2017
, other subsidiaries of Anadarko collectively held
2,011,380
common units and
12,743,318
Class C units, representing an aggregate
8.8%
limited partner interest in the Partnership. As of
June 30, 2017
, the public held
100,458,679
common units, representing a
59.8%
limited partner interest in the Partnership.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)
Net income (loss) per unit for common units.
Net income (loss) attributable to the Partnership assets acquired from Anadarko for periods prior to the Partnership’s acquisition of the Partnership assets is not allocated to the unitholders for purposes of calculating net income (loss) per common unit. Net income (loss) attributable to Western Gas Partners, LP earned on and subsequent to the date of acquisition of the Partnership assets is allocated as follows:
General partner.
The general partner’s allocation is equal to cash distributions plus its portion of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the general partner consistent with actual cash distributions and capital account allocations, including incentive distributions. Undistributed earnings (net income in excess of distributions) or undistributed losses (available cash in excess of net income) are then allocated to the general partner in accordance with its weighted-average ownership percentage during each period.
Series A Preferred unitholders.
The Series A Preferred units were not considered a participating security as they only had distribution rights up to the specified per-unit quarterly distribution and had no rights to the Partnership’s undistributed earnings and losses. As such, the Series A Preferred unitholders’ allocation was equal to their cash distribution plus the amortization of the Series A Preferred units beneficial conversion feature (see
Series A Preferred units
above).
Common and Class C unitholders.
The Class C units are considered a participating security because they participate in distributions with common units according to a predetermined formula (see
Note 3
). The common and Class C unitholders’ allocation is equal to their cash distributions plus their respective portions of undistributed earnings or losses. Specifically, net income equal to the amount of available cash (as defined by the partnership agreement) is allocated to the common and Class C unitholders consistent with actual cash distributions and capital account allocations. Undistributed earnings or undistributed losses are then allocated to the common and Class C unitholders in accordance with their respective weighted-average ownership percentages during each period. The common unitholder allocation also includes the impact of the amortization of the Series A Preferred units and Class C units beneficial conversion features. The Class C unitholder allocation is similarly impacted by the amortization of the Class C units beneficial conversion feature (see
Class C units
above).
Calculation of net income (loss) per unit.
Basic net income (loss) per common unit is calculated by dividing the net income (loss) attributable to common unitholders by the weighted-average number of common units outstanding during the period. The common units issued in connection with acquisitions and equity offerings are included on a weighted-average basis for periods they were outstanding. Diluted net income (loss) per common unit is calculated by dividing the sum of (i) the net income (loss) attributable to common units adjusted for distributions on the Series A Preferred units and a reallocation of the common and Class C limited partners’ interest in net income (loss) assuming conversion of the Series A Preferred units into common units, and (ii) the net income (loss) attributable to the Class C units as a participating security, by the sum of the weighted-average number of common units outstanding plus the dilutive effect of (i) the weighted-average number of outstanding Class C units and (ii) the weighted-average number of common units outstanding assuming conversion of the Series A Preferred units.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
4. EQUITY AND PARTNERS’ CAPITAL (CONTINUED)
The following table illustrates the Partnership’s calculation of net income (loss) per unit for common units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except per-unit amounts
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
173,451
|
|
|
$
|
164,521
|
|
|
$
|
275,340
|
|
|
$
|
280,581
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,326
|
)
|
Series A Preferred units interest in net (income) loss
(1)
|
|
(14,199
|
)
|
|
(23,121
|
)
|
|
(42,373
|
)
|
|
(25,450
|
)
|
General partner interest in net (income) loss
|
|
(76,365
|
)
|
|
(58,381
|
)
|
|
(144,527
|
)
|
|
(113,781
|
)
|
Common and Class C limited partners’ interest in net income (loss)
|
|
$
|
82,887
|
|
|
$
|
83,019
|
|
|
$
|
88,440
|
|
|
$
|
130,024
|
|
Net income (loss) allocable to common units
(1)
|
|
$
|
73,383
|
|
|
$
|
71,622
|
|
|
$
|
75,097
|
|
|
$
|
111,184
|
|
Net income (loss) allocable to Class C units
(1)
|
|
9,504
|
|
|
11,397
|
|
|
13,343
|
|
|
18,840
|
|
Common and Class C limited partners’ interest in net income (loss)
|
|
$
|
82,887
|
|
|
$
|
83,019
|
|
|
$
|
88,440
|
|
|
$
|
130,024
|
|
Net income (loss) per unit
|
|
|
|
|
|
|
|
|
Common units – basic and diluted
(2)
|
|
$
|
0.49
|
|
|
$
|
0.55
|
|
|
$
|
0.53
|
|
|
$
|
0.86
|
|
Weighted-average units outstanding
|
|
|
|
|
|
|
|
|
Common units – basic and diluted
|
|
148,864
|
|
|
130,669
|
|
|
141,696
|
|
|
129,830
|
|
Excluded due to anti-dilutive effect:
|
|
|
|
|
|
|
|
|
Class C units
(2)
|
|
12,650
|
|
|
11,849
|
|
|
12,552
|
|
|
11,719
|
|
Series A Preferred units assuming conversion to common units
(2)
|
|
3,734
|
|
|
20,709
|
|
|
10,901
|
|
|
11,742
|
|
|
|
(1)
|
Adjusted to reflect amortization of the beneficial conversion features.
|
|
|
(2)
|
The impact of Class C units and the conversion of Series A Preferred units would be anti-dilutive for all periods presented. As of May 2, 2017, all Series A Preferred units were converted into common units on a
one
-for-one basis.
|
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
5. TRANSACTIONS WITH AFFILIATES
Affiliate transactions.
Revenues from affiliates include amounts earned by the Partnership from services provided to Anadarko as well as from the sale of residue and NGLs to Anadarko. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant to gas purchase agreements. Operation and maintenance expense includes amounts accrued for or paid to affiliates for the operation of the Partnership assets, whether in providing services to affiliates or to third parties, including field labor, measurement and analysis, and other disbursements. A portion of the Partnership’s general and administrative expenses is paid by Anadarko, which results in affiliate transactions pursuant to the reimbursement provisions of the Partnership’s omnibus agreement. Affiliate expenses do not bear a direct relationship to affiliate revenues, and third-party expenses do not bear a direct relationship to third-party revenues. See
Note 2
for further information related to contributions of assets to the Partnership by Anadarko.
Cash management.
Anadarko operates a cash management system whereby excess cash from most of its subsidiaries’ separate bank accounts is generally swept to centralized accounts. Prior to the Partnership’s acquisition of the Partnership assets, third-party sales and purchases related to such assets were received or paid in cash by Anadarko within its centralized cash management system. The outstanding affiliate balances were entirely settled through an adjustment to net investment by Anadarko in connection with the acquisition of the Partnership assets. Subsequent to the acquisition of Partnership assets from Anadarko, transactions related to such assets are cash-settled directly with third parties and with Anadarko affiliates. Chipeta cash settles its transactions directly with third parties and Anadarko, as well as with the other subsidiaries of the Partnership.
Note receivable - Anadarko.
Concurrently with the closing of the Partnership’s May 2008 initial public offering, the Partnership loaned
$260.0 million
to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of
6.50%
, payable quarterly. The fair value of the note receivable from Anadarko was
$311.3 million
and
$313.3 million
at
June 30, 2017
, and
December 31, 2016
, respectively. The fair value of the note reflects consideration of credit risk and any premium or discount for the differential between the stated interest rate and quarter-end market interest rate, based on quoted market prices of similar debt instruments. Accordingly, the fair value of the note receivable from Anadarko is measured using Level 2 inputs.
Commodity price swap agreements.
The Partnership has commodity price swap agreements with Anadarko to mitigate exposure to a majority of the commodity price risk inherent in its percent-of-proceeds and keep-whole contracts. Notional volumes for each of the commodity price swap agreements are not specifically defined. Instead, the commodity price swap agreements apply to the actual volume of natural gas, condensate and NGLs purchased and sold. The commodity price swap agreements do not satisfy the definition of a derivative financial instrument and, therefore, are not required to be measured at fair value.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
5. TRANSACTIONS WITH AFFILIATES (CONTINUED)
The following table summarizes gains and losses upon settlement of commodity price swap agreements recognized in the consolidated statements of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Gains (losses) on commodity price swap agreements related to sales:
(1)
|
|
|
|
|
|
|
|
|
Natural gas sales
|
|
$
|
4,656
|
|
|
$
|
5,202
|
|
|
$
|
5,738
|
|
|
$
|
12,243
|
|
Natural gas liquids sales
|
|
1,837
|
|
|
20,480
|
|
|
(2,470
|
)
|
|
40,550
|
|
Total
|
|
6,493
|
|
|
25,682
|
|
|
3,268
|
|
|
52,793
|
|
Gains (losses) on commodity price swap agreements related to purchases
(2)
|
|
(5,507
|
)
|
|
(16,913
|
)
|
|
(2,811
|
)
|
|
(35,784
|
)
|
Net gains (losses) on commodity price swap agreements
|
|
$
|
986
|
|
|
$
|
8,769
|
|
|
$
|
457
|
|
|
$
|
17,009
|
|
|
|
(1)
|
Reported in affiliate Natural gas and natural gas liquids sales in the consolidated statements of operations in the period in which the related sale is recorded.
|
|
|
(2)
|
Reported in Cost of product in the consolidated statements of operations in the period in which the related purchase is recorded.
|
Revenues or costs attributable to volumes settled during 2016 and 2017 for the DJ Basin complex and 2017 for the MGR assets are recognized in the consolidated statements of operations at the applicable market price in the tables below. The Partnership also records a capital contribution from Anadarko in the Partnership’s consolidated statement of equity and partners’ capital for the amount by which the swap price exceeds the applicable market price in the tables below. The commodity price swap agreement for the Hugoton system was in place until its divestiture in October 2016. For the
six months ended June 30, 2017
, the capital contribution from Anadarko was
$28.7 million
. The tables below summarize the swap prices compared to the forward market prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DJ Basin Complex
|
per barrel except natural gas
|
|
2016 - 2017
Swap Prices
|
|
2016 Market Prices
(1)
|
|
2017 Market Prices
(1)
|
Ethane
|
|
$
|
18.41
|
|
|
$
|
0.60
|
|
|
$
|
5.09
|
|
Propane
|
|
47.08
|
|
|
10.98
|
|
|
18.85
|
|
Isobutane
|
|
62.09
|
|
|
17.23
|
|
|
26.83
|
|
Normal butane
|
|
54.62
|
|
|
16.86
|
|
|
26.20
|
|
Natural gasoline
|
|
72.88
|
|
|
26.15
|
|
|
41.84
|
|
Condensate
|
|
76.47
|
|
|
34.65
|
|
|
45.40
|
|
Natural gas (per MMBtu)
|
|
5.96
|
|
|
2.11
|
|
|
3.05
|
|
|
|
(1)
|
Represents the New York Mercantile Exchange (“NYMEX”) forward strip price as of December 8, 2015 and December 1, 2016, for the 2016 Market Prices and 2017 Market Prices, respectively, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.
|
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
5. TRANSACTIONS WITH AFFILIATES (CONTINUED)
|
|
|
|
|
|
|
|
|
|
|
|
MGR Assets
|
per barrel except natural gas
|
|
2016 - 2017 Swap Prices
|
|
2017 Market Prices
(1)
|
Ethane
|
|
$
|
23.11
|
|
|
$
|
4.08
|
|
Propane
|
|
52.90
|
|
|
19.24
|
|
Isobutane
|
|
73.89
|
|
|
25.79
|
|
Normal butane
|
|
64.93
|
|
|
25.16
|
|
Natural gasoline
|
|
81.68
|
|
|
45.01
|
|
Condensate
|
|
81.68
|
|
|
53.55
|
|
Natural gas (per MMBtu)
|
|
4.87
|
|
|
3.05
|
|
|
|
(1)
|
Represents the NYMEX forward strip price as of December 1, 2016, adjusted for product specification, location, basis and, in the case of NGLs, transportation and fractionation costs.
|
Gathering and processing agreements.
The Partnership has significant gathering and processing arrangements with affiliates of Anadarko on a majority of its systems. The Partnership’s natural gas gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was
38%
and
34%
for the
three and six months ended June 30, 2017
, respectively, and
39%
and
38%
for the
three and six months ended June 30, 2016
, respectively. The Partnership’s natural gas processing throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was
39%
and
44%
for the
three and six months ended June 30, 2017
, respectively, and
55%
and
58%
for the
three and six months ended June 30, 2016
, respectively. The Partnership’s crude, NGL and produced water gathering, treating and transportation throughput (excluding equity investment throughput) attributable to production owned or controlled by Anadarko was
41%
and
47%
for the
three and six months ended June 30, 2017
, respectively, and
64%
for the
three and six months ended June 30, 2016
.
Commodity purchase and sale agreements.
The Partnership sells a significant amount of its natural gas, condensate and NGLs to Anadarko Energy Services Company (“AESC”), Anadarko’s marketing affiliate. In addition, the Partnership purchases natural gas, condensate and NGLs from AESC pursuant to purchase agreements. The Partnership’s purchase and sale agreements with AESC are generally one-year contracts, subject to annual renewal.
Acquisitions from Anadarko.
On March 14, 2016, the Partnership acquired Springfield from Anadarko (see
Note 2
).
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
5. TRANSACTIONS WITH AFFILIATES (CONTINUED)
WES LTIP.
The general partner awards phantom units under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (“WES LTIP”) primarily to its independent directors, but also from time to time to its executive officers and Anadarko employees performing services for the Partnership. The phantom units awarded to the independent directors vest
one
year from the grant date, while all other awards are subject to graded vesting over a
three
-year service period. Compensation expense is recognized over the vesting period and was
$0.1 million
for each of the three months ended
June 30, 2017
and
2016
, and
$0.2 million
for each of the
six months ended June 30, 2017
and
2016
.
WGP LTIP and Anadarko Incentive Plan.
General and administrative expenses included
$0.9 million
and
$2.1 million
for the
three and six months ended June 30, 2017
, respectively, and
$1.1 million
and
$2.4 million
for the
three and six months ended June 30, 2016
, respectively, of equity-based compensation expense, allocated to the Partnership by Anadarko, for awards granted to the executive officers of the general partner and other employees under the Western Gas Equity Partners, LP 2012 Long-Term Incentive Plan (“WGP LTIP”) and the Anadarko Petroleum Corporation 2012 Omnibus Incentive Compensation Plan (“Anadarko Incentive Plan”). Of this amount,
$2.2 million
is reflected as contributions to partners’ capital in the Partnership’s consolidated statement of equity and partners’ capital for the
six months ended June 30, 2017
.
Equipment purchases and sales.
The following table summarizes the Partnership’s purchases from and sales to Anadarko of pipe and equipment:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
thousands
|
|
Purchases
|
|
Sales
|
Cash consideration
|
|
$
|
3,910
|
|
|
$
|
2,699
|
|
|
$
|
—
|
|
|
$
|
613
|
|
Net carrying value
|
|
(4,286
|
)
|
|
(2,328
|
)
|
|
—
|
|
|
(596
|
)
|
Partners’ capital adjustment
|
|
$
|
(376
|
)
|
|
$
|
371
|
|
|
$
|
—
|
|
|
$
|
17
|
|
Contributions in aid of construction costs from affiliates.
On certain of the Partnership’s capital projects, Anadarko is obligated to reimburse the Partnership for all or a portion of project capital expenditures. The majority of such arrangements are associated with projects related to pipeline construction activities and production well tie-ins. The cash receipts resulting from such reimbursements are presented as “Contributions in aid of construction costs from affiliates” within the investing section of the Partnership’s consolidated statements of cash flows.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
5. TRANSACTIONS WITH AFFILIATES (CONTINUED)
Summary of affiliate transactions.
The following table summarizes material affiliate transactions. See
Note 2
for discussion of affiliate acquisitions and related funding.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Revenues and other
(1)
|
|
$
|
316,313
|
|
|
$
|
302,405
|
|
|
$
|
631,468
|
|
|
$
|
574,989
|
|
Equity income, net
– affiliates
(1)
|
|
21,728
|
|
|
19,693
|
|
|
41,189
|
|
|
36,507
|
|
Cost of product
(1)
|
|
21,607
|
|
|
22,145
|
|
|
37,595
|
|
|
46,725
|
|
Operation and maintenance
(2)
|
|
18,462
|
|
|
17,661
|
|
|
35,551
|
|
|
35,636
|
|
General and administrative
(3)
|
|
9,365
|
|
|
9,169
|
|
|
18,900
|
|
|
18,121
|
|
Operating expenses
|
|
49,434
|
|
|
48,975
|
|
|
92,046
|
|
|
100,482
|
|
Interest income
(4)
|
|
4,225
|
|
|
4,225
|
|
|
8,450
|
|
|
8,450
|
|
Interest expense
(5)
|
|
—
|
|
|
(15,461
|
)
|
|
71
|
|
|
(10,924
|
)
|
Settlement of the Deferred purchase price obligation – Anadarko
(6)
|
|
(37,346
|
)
|
|
—
|
|
|
(37,346
|
)
|
|
—
|
|
Proceeds from the issuance of common units, net of offering expenses
(7)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25,000
|
|
Distributions to unitholders
(8)
|
|
110,449
|
|
|
94,909
|
|
|
213,572
|
|
|
184,678
|
|
Above-market component of swap agreements with Anadarko
|
|
16,373
|
|
|
9,552
|
|
|
28,670
|
|
|
16,365
|
|
|
|
(1)
|
Represents amounts earned or incurred on and subsequent to the date of the acquisition of Partnership assets, as well as amounts earned or incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets, recognized under gathering, treating or processing agreements, and purchase and sale agreements.
|
|
|
(2)
|
Represents expenses incurred on and subsequent to the date of the acquisition of Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets.
|
|
|
(3)
|
Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see
WES LTIP
and
WGP LTIP and Anadarko Incentive Plan
within this
Note 5
).
|
|
|
(4)
|
Represents interest income recognized on the note receivable from Anadarko.
|
|
|
(5)
|
Includes amounts related to the Deferred purchase price obligation - Anadarko (see
Note 2
and
Note 9
).
|
|
|
(6)
|
Represents the cash payment to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko (see
Note 2
).
|
|
|
(7)
|
Represents proceeds from the issuance of
835,841
common units to WGP as partial funding for the acquisition of Springfield (see
Note 2
).
|
|
|
(8)
|
Represents distributions paid under the partnership agreement (see
Note 3
and
Note 4
).
|
Concentration of credit risk.
Anadarko was the only customer from whom revenues exceeded 10% of the Partnership’s consolidated revenues for all periods presented in the consolidated statements of operations.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
6. PROPERTY, PLANT AND EQUIPMENT
A summary of the historical cost of the Partnership’s property, plant and equipment is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
thousands
|
|
Estimated Useful Life
|
|
June 30, 2017
|
|
December 31, 2016
|
Land
|
|
n/a
|
|
$
|
4,258
|
|
|
$
|
4,012
|
|
Gathering systems and processing complexes
|
|
3 to 47 years
|
|
6,905,758
|
|
|
6,462,053
|
|
Pipelines and equipment
|
|
15 to 45 years
|
|
139,344
|
|
|
139,646
|
|
Assets under construction
|
|
n/a
|
|
275,403
|
|
|
226,626
|
|
Other
|
|
3 to 40 years
|
|
30,019
|
|
|
29,605
|
|
Total property, plant and equipment
|
|
|
|
7,354,782
|
|
|
6,861,942
|
|
Accumulated depreciation
|
|
|
|
2,006,988
|
|
|
1,812,010
|
|
Net property, plant and equipment
|
|
|
|
$
|
5,347,794
|
|
|
$
|
5,049,932
|
|
The cost of property classified as “Assets
under construction” is excluded from capitalized costs being depreciated. These amounts represent property that is not yet suitable to be placed into productive service as of the respective balance sheet date.
Impairments.
During the
six months ended June 30, 2017
, the Partnership recognized impairments of
$167.9 million
, including an impairment of
$158.8 million
at the Granger complex, which was impaired to its estimated fair value of
$48.5 million
using the income approach and Level 3 fair value inputs, due to a reduced throughput fee as a result of a producer’s bankruptcy. Also during the period, the Partnership recognized additional impairments of
$9.1 million
, primarily related to (i) a
$3.7 million
impairment at the Granger straddle plant, which was impaired to its estimated salvage value of
$0.6 million
using the income approach and Level 3 fair value inputs, (ii) a
$3.1 million
impairment of the Fort Union equity investment (see
Note 7
) and (iii) the cancellation of a pipeline project in West Texas.
During 2016, the Partnership recognized impairments of
$15.5 million
, including an impairment of
$6.1 million
at the Newcastle system, which was impaired to its estimated fair value of
$3.1 million
using the income approach and Level 3 fair value inputs, due to a reduction in estimated future cash flows caused by the low commodity price environment. Also during 2016, the Partnership recognized impairments of
$9.4 million
, primarily related to the cancellation of projects at the DJ Basin complex and Springfield and DBJV systems, and the abandonment of compressors at the MIGC system.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
7. EQUITY INVESTMENTS
The following table presents the activity in the Partnership’s equity investments for the
six months ended June 30, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity Investments
|
thousands
|
Fort
Union
|
|
White
Cliffs
|
|
Rendezvous
|
|
Mont
Belvieu JV
|
|
TEG
|
|
TEP
|
|
FRP
|
|
Total
|
Balance at December 31, 2016
|
$
|
12,833
|
|
|
$
|
47,319
|
|
|
$
|
46,739
|
|
|
$
|
112,805
|
|
|
$
|
15,846
|
|
|
$
|
189,194
|
|
|
$
|
169,472
|
|
|
$
|
594,208
|
|
Investment earnings (loss), net of amortization
|
1,844
|
|
|
6,701
|
|
|
540
|
|
|
13,388
|
|
|
1,319
|
|
|
8,956
|
|
|
8,441
|
|
|
41,189
|
|
Impairment expense
(1)
|
(3,110
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3,110
|
)
|
Contributions
|
—
|
|
|
277
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
287
|
|
Distributions
|
(2,239
|
)
|
|
(6,410
|
)
|
|
(1,510
|
)
|
|
(13,407
|
)
|
|
(1,026
|
)
|
|
(9,082
|
)
|
|
(8,528
|
)
|
|
(42,202
|
)
|
Distributions in excess of cumulative earnings
(2)
|
(800
|
)
|
|
(1,571
|
)
|
|
(1,418
|
)
|
|
(1,717
|
)
|
|
—
|
|
|
(2,102
|
)
|
|
(1,613
|
)
|
|
(9,221
|
)
|
Balance at June 30, 2017
|
$
|
8,528
|
|
|
$
|
46,316
|
|
|
$
|
44,351
|
|
|
$
|
111,069
|
|
|
$
|
16,139
|
|
|
$
|
186,976
|
|
|
$
|
167,772
|
|
|
$
|
581,151
|
|
|
|
(1)
|
Recorded in Impairments in the consolidated statements of operations.
|
|
|
(2)
|
Distributions in excess of cumulative earnings, classified as investing cash flows in the consolidated statements of cash flows, is calculated on an individual investment basis.
|
The investment balance in Fort Union at June 30, 2017, is
$3.1 million
less than the Partnership’s underlying equity in Fort Union’s net assets due to an impairment loss recognized by the Partnership in the second quarter of 2017 for its investment in Fort Union. This investment was impaired to its estimated fair value of
$8.5 million
, using the income approach and Level 3 fair value inputs.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
8. COMPONENTS OF WORKING CAPITAL
A summary of accounts receivable, net is as follows:
|
|
|
|
|
|
|
|
|
|
thousands
|
|
June 30, 2017
|
|
December 31, 2016
|
Trade receivables, net
|
|
$
|
136,398
|
|
|
$
|
192,808
|
|
Other receivables, net
|
|
46
|
|
|
30,415
|
|
Total accounts receivable, net
|
|
$
|
136,444
|
|
|
$
|
223,223
|
|
A summary of other current assets is as follows:
|
|
|
|
|
|
|
|
|
|
thousands
|
|
June 30, 2017
|
|
December 31, 2016
|
Natural gas liquids inventory
|
|
$
|
8,869
|
|
|
$
|
7,126
|
|
Imbalance receivables
|
|
1,020
|
|
|
3,483
|
|
Prepaid insurance
|
|
272
|
|
|
2,257
|
|
Total other current assets
|
|
$
|
10,161
|
|
|
$
|
12,866
|
|
A summary of accrued liabilities is as follows:
|
|
|
|
|
|
|
|
|
|
thousands
|
|
June 30, 2017
|
|
December 31, 2016
|
Accrued interest expense
|
|
$
|
40,541
|
|
|
$
|
39,826
|
|
Short-term asset retirement obligations
|
|
6,191
|
|
|
3,114
|
|
Short-term remediation and reclamation obligations
|
|
630
|
|
|
630
|
|
Income taxes payable
|
|
1,634
|
|
|
1,006
|
|
Other
|
|
7,844
|
|
|
532
|
|
Total accrued liabilities
|
|
$
|
56,840
|
|
|
$
|
45,108
|
|
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9. DEBT AND INTEREST EXPENSE
At
June 30, 2017
, the Partnership’s debt consisted of
5.375%
Senior Notes due 2021 (the “2021 Notes”),
4.000%
Senior Notes due 2022 (the “2022 Notes”),
2.600%
Senior Notes due 2018 (the “2018 Notes”),
5.450%
Senior Notes due 2044 (the “2044 Notes”),
3.950%
Senior Notes due 2025 (the “2025 Notes”),
4.650%
Senior Notes due 2026 (the “2026 Notes”) and borrowings on the RCF.
The following table presents the Partnership’s outstanding debt as of
June 30, 2017
, and
December 31, 2016
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2017
|
|
December 31, 2016
|
thousands
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
2021 Notes
|
|
$
|
500,000
|
|
|
$
|
495,268
|
|
|
$
|
537,476
|
|
|
$
|
500,000
|
|
|
$
|
494,734
|
|
|
$
|
536,252
|
|
2022 Notes
|
|
670,000
|
|
|
668,740
|
|
|
686,001
|
|
|
670,000
|
|
|
668,634
|
|
|
681,723
|
|
2018 Notes
|
|
350,000
|
|
|
349,434
|
|
|
351,057
|
|
|
350,000
|
|
|
349,188
|
|
|
351,531
|
|
2044 Notes
|
|
600,000
|
|
|
593,179
|
|
|
618,294
|
|
|
600,000
|
|
|
593,132
|
|
|
615,753
|
|
2025 Notes
|
|
500,000
|
|
|
491,423
|
|
|
497,615
|
|
|
500,000
|
|
|
490,971
|
|
|
492,499
|
|
2026 Notes
|
|
500,000
|
|
|
495,021
|
|
|
517,289
|
|
|
500,000
|
|
|
494,802
|
|
|
518,441
|
|
RCF
|
|
160,000
|
|
|
160,000
|
|
|
160,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total long-term debt
|
|
$
|
3,280,000
|
|
|
$
|
3,253,065
|
|
|
$
|
3,367,732
|
|
|
$
|
3,120,000
|
|
|
$
|
3,091,461
|
|
|
$
|
3,196,199
|
|
|
|
(1)
|
Fair value is measured using the market approach and Level 2 inputs.
|
Debt activity.
The following table presents the debt activity of the Partnership for the
six months ended June 30, 2017
:
|
|
|
|
|
|
thousands
|
|
Carrying Value
|
Balance at December 31, 2016
|
|
$
|
3,091,461
|
|
RCF borrowings
|
|
160,000
|
|
Other
|
|
1,604
|
|
Balance at June 30, 2017
|
|
$
|
3,253,065
|
|
Senior Notes.
At
June 30, 2017
, the Partnership was in compliance with all covenants under the indentures governing its outstanding notes.
Revolving credit facility.
As of
June 30, 2017
, the Partnership had
$160.0 million
of outstanding RCF borrowings and
$4.9 million
in outstanding letters of credit, resulting in
$1.035 billion
available for borrowing under the RCF, which matures in February 2020. As of
June 30, 2017
and
2016
, the interest rate on the outstanding RCF borrowings was
2.53%
and
1.77%
, respectively. The facility fee rate was
0.20%
at
June 30, 2017
and
2016
. At
June 30, 2017
, the Partnership was in compliance with all covenants under the RCF.
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9. DEBT AND INTEREST EXPENSE (CONTINUED)
Interest expense.
The following table summarizes the amounts included in interest expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Third parties
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
(35,161
|
)
|
|
$
|
(28,281
|
)
|
|
$
|
(69,780
|
)
|
|
$
|
(56,099
|
)
|
Amortization of debt issuance costs and commitment fees
|
|
(1,645
|
)
|
|
(1,545
|
)
|
|
(3,275
|
)
|
|
(3,075
|
)
|
Capitalized interest
|
|
1,060
|
|
|
1,482
|
|
|
1,876
|
|
|
3,331
|
|
Total interest expense – third parties
|
|
(35,746
|
)
|
|
(28,344
|
)
|
|
(71,179
|
)
|
|
(55,843
|
)
|
Affiliates
|
|
|
|
|
|
|
|
|
Deferred purchase price obligation – Anadarko
(1)
|
|
—
|
|
|
15,461
|
|
|
(71
|
)
|
|
10,924
|
|
Total interest expense – affiliates
|
|
—
|
|
|
15,461
|
|
|
(71
|
)
|
|
10,924
|
|
Interest expense
|
|
$
|
(35,746
|
)
|
|
$
|
(12,883
|
)
|
|
$
|
(71,250
|
)
|
|
$
|
(44,919
|
)
|
|
|
(1)
|
See
Note 2
for a discussion of the Deferred purchase price obligation - Anadarko.
|
10. COMMITMENTS AND CONTINGENCIES
Litigation and legal proceedings.
From time to time, the Partnership is involved in legal, tax, regulatory and other proceedings in various forums regarding performance, contracts and other matters that arise in the ordinary course of business. Management is not aware of any such proceeding the final disposition of which could have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows.
Other commitments.
The Partnership has short-term payment obligations, or commitments, related to its capital spending programs, as well as those of its unconsolidated affiliates. As of
June 30, 2017
, the Partnership had unconditional payment obligations for services to be rendered or products to be delivered in connection with its capital projects of
$53.6 million
, the majority of which is expected to be paid in the next twelve months. These commitments relate primarily to (i) the construction of Train VI at the DBM complex and (ii) expansion projects at the DBJV system and the DBM and DJ Basin complexes.
Lease commitments.
Anadarko, on behalf of the Partnership, has entered into lease arrangements for corporate offices, shared field offices and a warehouse supporting the Partnership’s operations, and equipment leases for which Anadarko charges the Partnership rent. The leases for the corporate offices and shared field offices extend through 2028 and 2019, respectively, and the lease for the warehouse expired in February 2017.
Rent expense associated with office, warehouse and equipment leases was
$11.5 million
and
$19.4 million
for the
three and six months ended June 30, 2017
, respectively, and
$8.4 million
and
$17.3 million
for the
three and six months ended June 30, 2016
, respectively.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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, which are included under
Part I
,
Item 1
of this quarterly report, as well as our historical consolidated financial statements, and the notes thereto, which are included under Part II, Item 8 of our 2016 Form 10-K as filed with the SEC on February 23, 2017.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
We have made in this Form
10-Q
, and may from time to time make in other public filings, press releases and statements by management, forward-looking statements concerning our operations, economic performance and financial condition. These forward-looking statements include statements preceded by, followed by or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should” or similar expressions or variations on such expressions. These statements discuss future expectations, contain projections of results of operations or financial condition or include other “forward-looking” information.
Although we and our general partner believe that the expectations reflected in such forward-looking statements are reasonable, neither we nor our general partner can give any assurance that such expectations will prove to have been correct. These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following:
|
|
•
|
our ability to pay distributions to our unitholders;
|
|
|
•
|
our and Anadarko’s assumptions about the energy market;
|
|
|
•
|
future throughput (including Anadarko production) which is gathered or processed by or transported through our assets;
|
|
|
•
|
competitive conditions;
|
|
|
•
|
the availability of capital resources to fund acquisitions, capital expenditures and other contractual obligations, and our ability to access those resources from Anadarko or through the debt or equity capital markets;
|
|
|
•
|
the supply of, demand for, and price of, oil, natural gas, NGLs and related products or services;
|
|
|
•
|
our ability to mitigate exposure to the commodity price risks inherent in our percent-of-proceeds and keep-whole contracts through the extension of our commodity price swap agreements with Anadarko, or otherwise;
|
|
|
•
|
weather and natural disasters;
|
|
|
•
|
the availability of goods and services;
|
|
|
•
|
general economic conditions, internationally, domestically or in the jurisdictions in which we are doing business;
|
|
|
•
|
federal, state and local laws, including those that limit Anadarko and other producers’ hydraulic fracturing or other oil and natural gas operations;
|
|
|
•
|
environmental liabilities;
|
|
|
•
|
legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes;
|
|
|
•
|
changes in the financial or operational condition of Anadarko;
|
|
|
•
|
the creditworthiness of Anadarko or our other counterparties, including financial institutions, operating partners, and other parties;
|
|
|
•
|
changes in Anadarko’s capital program, strategy or desired areas of focus;
|
|
|
•
|
our commitments to capital projects;
|
|
|
•
|
our ability to use our RCF;
|
|
|
•
|
our ability to repay debt;
|
|
|
•
|
conflicts of interest among us, our general partner, WGP and its general partner, and affiliates, including Anadarko;
|
|
|
•
|
our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;
|
|
|
•
|
our ability to acquire assets on acceptable terms from Anadarko or third parties, and Anadarko’s ability to generate an inventory of assets suitable for acquisition;
|
|
|
•
|
non-payment or non-performance of Anadarko or other significant customers, including under our gathering, processing and transportation agreements and our $260.0 million note receivable from Anadarko;
|
|
|
•
|
the timing, amount and terms of future issuances of equity and debt securities;
|
|
|
•
|
the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigation by the National Transportation Safety Board (“NTSB”), related to Anadarko’s operations in Colorado, and continued or additional disruptions in operations that may occur as Anadarko and we comply with regulatory orders or other state or local changes in laws or regulations in Colorado; and
|
|
|
•
|
other factors discussed below, in “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates” included in our
2016
Form 10-K, and in our quarterly reports on Form 10-Q, and in our other public filings and press releases.
|
The risk factors and other factors noted throughout or incorporated by reference in this Form
10-Q
could cause actual results to differ materially from those contained in any forward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
EXECUTIVE SUMMARY
We are a growth-oriented Delaware MLP formed by Anadarko to acquire, own, develop and operate midstream energy assets. We currently own or have investments in assets located in the Rocky Mountains (Colorado, Utah and Wyoming), North-central Pennsylvania and Texas. 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. We provide these midstream services for Anadarko, as well as for third-party producers and customers. As of
June 30, 2017
, our assets and investments consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|
Equity
Interests
|
Gathering systems
|
|
12
|
|
|
3
|
|
|
3
|
|
|
2
|
|
Treating facilities
|
|
19
|
|
|
3
|
|
|
—
|
|
|
3
|
|
Natural gas processing plants/trains
|
|
19
|
|
|
5
|
|
|
—
|
|
|
2
|
|
NGL pipelines
|
|
2
|
|
|
—
|
|
|
—
|
|
|
3
|
|
Natural gas pipelines
|
|
5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Oil pipelines
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Significant financial and operational events during the
six months ended June 30, 2017
, included the following:
|
|
•
|
In March 2017, we acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration, resulting in a net gain of
$125.7 million
. See
Acquisitions and Divestitures
within this
Item 2
for additional information.
|
|
|
•
|
In May 2017, we reached an agreement with Anadarko to settle the outstanding Deferred purchase price obligation - Anadarko, whereby we made a cash payment to Anadarko of $37.3 million during the second quarter of 2017.
|
|
|
•
|
On March 1, 2017, 50% of the outstanding Series A Preferred units converted into common units on a one-for-one basis and on May 2, 2017, the remaining Series A Preferred units converted into common units on a one-for-one basis. See
Equity Offerings
within this
Item 2
for additional information.
|
|
|
•
|
During the second quarter of 2017, we commenced operation of two produced-water disposal systems in West Texas (included within Gathering systems in the table above).
|
|
|
•
|
In June 2017, we closed on the sale of our Helper and Clawson systems, which resulted in a net gain on divestiture of
$16.3 million
. See
Acquisitions and Divestitures
within this
Item 2
for additional information.
|
|
|
•
|
In February 2017, Anadarko elected to extend the conversion date of the Class C units from December 31, 2017, to March 1, 2020.
|
|
|
•
|
We received
$52.9 million
in cash proceeds from insurers in final settlement of our claims related to the incident at the DBM complex, including
$29.9 million
for business interruption insurance claims and
$23.0 million
for property insurance claims. See
Liquidity and Capital Resources
within this
Item 2
for additional information.
|
|
|
•
|
We raised our distribution to
$0.890
per unit for the
second
quarter of
2017
, representing a
2%
increase
over the distribution for the
first
quarter of
2017
and a
7%
increase
over the distribution for the
second
quarter of
2016
.
|
|
|
•
|
Throughput attributable to Western Gas Partners, LP for natural gas assets totaled
3,472
MMcf/d and
3,705
MMcf/d for the three and
six months ended June 30, 2017
, respectively, representing a
10%
and
3%
decrease
, respectively, compared to the same periods in
2016
.
|
|
|
•
|
Throughput for crude, NGL and produced water assets totaled
182
MBbls/d and
176
MBbls/d for the three and
six months ended June 30, 2017
, respectively, representing a
3%
and
5%
decrease
, respectively, compared to the same periods in
2016
.
|
|
|
•
|
Operating income (loss) was
$207.6 million
and
$346.0 million
for the three and
six months ended June 30, 2017
, respectively, representing an
18%
and
5%
increase
, respectively, compared to the same periods in
2016
.
|
|
|
•
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets (as defined under the caption
Key Performance Metrics
within this
Item 2
) averaged
$0.94
per Mcf and
$0.89
per Mcf for the three and
six months ended June 30, 2017
, respectively, representing a
12%
and
9%
increase
, respectively, compared to the same periods in
2016
.
|
|
|
•
|
Adjusted gross margin for crude, NGL and produced water assets (as defined under the caption
Key Performance Metrics
within this
Item 2
) averaged
$2.15
per Bbl and
$2.07
per Bbl for the three and
six months ended June 30, 2017
, respectively, representing a
6%
and
1%
increase
, respectively, compared to the same periods in
2016
.
|
Anadarko’s Colorado Response.
Following a home explosion in Colorado in April 2017, Anadarko has taken actions in an effort to alleviate public concern and reinforce confidence in the safety of its operations. Anadarko took precautionary measures to shut in all operated vertical wells in the DJ Basin to conduct additional inspections and testing and also remove all one-inch return lines associated with these wells. Subsequently, in May 2017, the Colorado Oil & Gas Conservation Commission issued a two-phase Notice to Operators (“NTO”) requiring all upstream operators to inventory and integrity test existing flowlines within 1,000 feet of a building unit and abandon all inactive flowlines in such areas. Anadarko expects to meet the NTO compliance deadline, is cooperating fully with the NTSB in its investigation, and continues to work cooperatively with state regulators and others.
Significant Item Affecting Comparability.
On December 3, 2015, there was an initial fire and secondary explosion at the processing facility within the DBM complex. The majority of the damage was to the liquid handling facilities and the amine treating units at the inlet of the complex. Train II (with capacity of 100 MMcf/d) sustained the most damage of the processing trains and returned to service in December 2016. Train III (with capacity of 200 MMcf/d) experienced minimal damage and returned to full service in May 2016. For ease of reference throughout the remainder of this Management’s Discussion and Analysis, the damage to the processing facility and resulting lack of processing capacity and associated financial statement impact is referred to as the “DBM outage.” See
Note 1—Description of Business and Basis of Presentation
in the
Notes to Consolidated Financial Statements
under Part I, Item 1 of this Form 10-Q.
ACQUISITIONS AND DIVESTITURES
Acquisitions.
The following table presents the acquisitions completed during
2017
and
2016
, and identifies the funding sources for such acquisitions. See
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under Part I, Item 1 of this Form 10-Q.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands except unit and percent amounts
|
|
Acquisition
Date
|
|
Percentage
Acquired
|
|
Borrowings
|
|
Cash
On Hand
|
|
Common Units
Issued
|
|
Series A
Preferred Units Issued
|
Springfield system
(1)
|
|
03/14/2016
|
|
50.1
|
%
|
|
$
|
247,500
|
|
|
$
|
—
|
|
|
2,089,602
|
|
|
14,030,611
|
|
DBJV system
(2)
|
|
03/17/2017
|
|
50
|
%
|
|
—
|
|
|
155,000
|
|
|
—
|
|
|
—
|
|
|
|
(1)
|
We acquired Springfield from Anadarko for
$750.0 million
, consisting of
$712.5 million
in cash and the issuance of
1,253,761
of our common units. Springfield owns a
50.1%
interest in the Springfield system. We financed the cash portion of the acquisition through: (i) borrowings of
$247.5 million
on our RCF, (ii) the issuance of
835,841
of our common units to WGP and (iii) the issuance of Series A Preferred units to private investors. See
Note 4—Equity and Partners’ Capital
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
for further information regarding the Series A Preferred units.
|
|
|
(2)
|
We acquired the Additional DBJV System Interest from a third party. See
Property exchange
below.
|
Property exchange.
On March 17, 2017, we acquired the Additional DBJV System Interest from a third party in exchange for the Non-Operated Marcellus Interest and $155.0 million of cash consideration. We previously held a 50% interest in, and operated, the DBJV system. The Property Exchange resulted in a net gain of
$125.7 million
recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations. See
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under Part I, Item 1 of this Form 10-Q.
Divestitures.
During the second quarter of 2017, the Helper and Clawson systems, located in Utah, were sold to a third party, resulting in a net gain on sale of
$16.3 million
recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
In October 2016, the Hugoton system, located in Southwest Kansas and Oklahoma, was sold to a third party, resulting in a net loss on sale of
$12.0 million
recorded as Gain (loss) on divestiture and other, net in the consolidated statements of operations.
Presentation of Partnership assets.
The term “Partnership assets” includes both the assets owned and the interests accounted for under the equity method (see
Note 7—Equity Investments
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
) by us as of
June 30, 2017
. Because Anadarko controls us through its ownership and control of WGP, which owns the entire interest in our general partner, each of our acquisitions of Partnership assets from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko’s historic carrying value, which did not correlate to the total acquisition price paid by us (see
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
). Further, after an acquisition of Partnership assets from Anadarko, we may be required to recast our financial statements to include the activities of such Partnership assets from the date of common control.
EQUITY OFFERINGS
Series A Preferred units.
In 2016, we issued 21,922,831 Series A Preferred units to private investors. Pursuant to an agreement between us and the holders of the Series A Preferred units, 50% of the Series A Preferred units converted into common units on a one-for-one basis on March 1, 2017, and the remaining Series A Preferred units converted on a one-for-one basis on May 2, 2017. See
Note 4—Equity and Partners’ Capital
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
RESULTS OF OPERATIONS
OPERATING RESULTS
The following tables and discussion present a summary of our results of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Total revenues and other
(1)
|
|
$
|
525,450
|
|
|
$
|
428,664
|
|
|
$
|
1,041,643
|
|
|
$
|
811,805
|
|
Equity income, net – affiliates
|
|
21,728
|
|
|
19,693
|
|
|
41,189
|
|
|
36,507
|
|
Total operating expenses
(1)
|
|
379,143
|
|
|
272,691
|
|
|
901,659
|
|
|
518,611
|
|
Gain (loss) on divestiture and other, net
|
|
15,458
|
|
|
(1,907
|
)
|
|
134,945
|
|
|
(2,539
|
)
|
Proceeds from business interruption insurance claims
(2)
|
|
24,115
|
|
|
2,603
|
|
|
29,882
|
|
|
2,603
|
|
Operating income (loss)
|
|
207,608
|
|
|
176,362
|
|
|
346,000
|
|
|
329,765
|
|
Interest income – affiliates
|
|
4,225
|
|
|
4,225
|
|
|
8,450
|
|
|
8,450
|
|
Interest expense
|
|
(35,746
|
)
|
|
(12,883
|
)
|
|
(71,250
|
)
|
|
(44,919
|
)
|
Other income (expense), net
|
|
253
|
|
|
(53
|
)
|
|
683
|
|
|
71
|
|
Income (loss) before income taxes
|
|
176,340
|
|
|
167,651
|
|
|
283,883
|
|
|
293,367
|
|
Income tax (benefit) expense
|
|
843
|
|
|
326
|
|
|
4,395
|
|
|
6,959
|
|
Net income (loss)
|
|
175,497
|
|
|
167,325
|
|
|
279,488
|
|
|
286,408
|
|
Net income attributable to noncontrolling interest
|
|
2,046
|
|
|
2,804
|
|
|
4,148
|
|
|
5,827
|
|
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
173,451
|
|
|
$
|
164,521
|
|
|
$
|
275,340
|
|
|
$
|
280,581
|
|
Key performance metrics
(3)
|
|
|
|
|
|
|
|
|
Adjusted gross margin attributable to Western Gas Partners, LP
|
|
$
|
333,548
|
|
|
$
|
329,254
|
|
|
$
|
665,104
|
|
|
$
|
640,478
|
|
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
274,835
|
|
|
250,565
|
|
|
529,829
|
|
|
481,664
|
|
Distributable cash flow
|
|
247,225
|
|
|
199,349
|
|
|
463,728
|
|
|
391,287
|
|
|
|
(1)
|
Revenues and other include amounts earned from services provided to our affiliates, as well as from the sale of residue and NGLs to our affiliates. Operating expenses include amounts charged by our affiliates for services as well as reimbursement of amounts paid by affiliates to third parties on our behalf. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
|
|
|
(2)
|
See
Note 1—Description of Business and Basis of Presentation
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
|
|
|
(3)
|
Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow are defined under the caption
Key Performance Metrics
within this
Item 2
.
For reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, see
Key Performance Metrics–Reconciliation of non-GAAP Measures
within this
Item 2
.
|
For purposes of the following discussion, any increases or decreases “for the three months ended
June 30, 2017
” refer to the comparison of the three months ended
June 30, 2017
, to the three months ended
June 30, 2016
; any increases or decreases “for the
six months ended June 30, 2017
” refer to the comparison of the
six months ended June 30, 2017
, to the
six months ended June 30, 2016
; and any increases or decreases “for the three and
six months ended June 30, 2017
” refer to the comparison of these
2017
periods to the corresponding three and
six
month periods ended
June 30, 2016
.
Throughput
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
Throughput for natural gas assets (MMcf/d)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering, treating and transportation
|
|
866
|
|
|
1,508
|
|
|
(43
|
)%
|
|
1,155
|
|
|
1,553
|
|
|
(26
|
)%
|
Processing
|
|
2,555
|
|
|
2,320
|
|
|
10
|
%
|
|
2,498
|
|
|
2,226
|
|
|
12
|
%
|
Equity investment
(1)
|
|
158
|
|
|
170
|
|
|
(7
|
)%
|
|
160
|
|
|
178
|
|
|
(10
|
)%
|
Total throughput for natural gas assets
|
|
3,579
|
|
|
3,998
|
|
|
(10
|
)%
|
|
3,813
|
|
|
3,957
|
|
|
(4
|
)%
|
Throughput attributable to noncontrolling interest for natural gas assets
|
|
107
|
|
|
128
|
|
|
(16
|
)%
|
|
108
|
|
|
132
|
|
|
(18
|
)%
|
Total throughput attributable to Western Gas Partners, LP for natural gas assets
|
|
3,472
|
|
|
3,870
|
|
|
(10
|
)%
|
|
3,705
|
|
|
3,825
|
|
|
(3
|
)%
|
Throughput for crude, NGL and produced water assets (MBbls/d)
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering, treating and transportation
|
|
50
|
|
|
59
|
|
|
(15
|
)%
|
|
47
|
|
|
59
|
|
|
(20
|
)%
|
Equity investment
(2)
|
|
132
|
|
|
128
|
|
|
3
|
%
|
|
129
|
|
|
127
|
|
|
2
|
%
|
Total throughput for crude, NGL and produced water assets
|
|
182
|
|
|
187
|
|
|
(3
|
)%
|
|
176
|
|
|
186
|
|
|
(5
|
)%
|
|
|
(1)
|
Represents our 14.81% share of average Fort Union throughput and our 22% share of average Rendezvous throughput.
|
|
|
(2)
|
Represents our 10% share of average White Cliffs throughput, our 25% share of average Mont Belvieu JV throughput, our 20% share of average TEG and TEP throughput, and our 33.33% share of average FRP throughput.
|
Natural gas assets
Gathering, treating and transportation throughput
decrease
d by
642
MMcf/d and
398
MMcf/d for the three and
six months ended June 30, 2017
, respectively, primarily due to the Property Exchange in March 2017, production declines in the areas around the Marcellus Interest and Springfield gas gathering systems, and the sale of the Hugoton system in October 2016.
Processing throughput
increase
d by
235
MMcf/d and
272
MMcf/d for the three and
six months ended June 30, 2017
, respectively, primarily due to the DBM outage in 2016 and the start-up of Train IV and Train V at the DBM complex in May 2016 and October 2016, respectively. These increases were partially offset by production declines in the areas around the Chipeta complex and MGR assets.
Equity investment throughput
decrease
d by
12
MMcf/d and
18
MMcf/d for the three and
six months ended June 30, 2017
, respectively, primarily due to
decrease
d throughput at the Rendezvous and Fort Union systems due to production declines in the area.
Crude, NGL and produced water assets
Gathering, treating and transportation throughput
decrease
d by
9
MBbls/d and
12
MBbls/d for the three and
six months ended June 30, 2017
, respectively, primarily due to
decrease
d throughput at the Springfield oil gathering system due to production declines in the area, partially offset by throughput from the two produced-water disposal systems in West Texas that commenced operation during the second quarter of 2017.
Equity investment throughput
increase
d by
4
MBbls/d and
2
MBbls/d for the three and
six months ended June 30, 2017
, respectively, primarily due to
increase
d volumes on FRP and TEP as a result of increased production in the DJ Basin area, partially offset by decreased throughput at White Cliffs as a result of a competitive pipeline commencing service in September 2016.
Gathering, Processing and Transportation Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
Gathering, processing and transportation revenues
|
|
$
|
299,435
|
|
|
$
|
301,136
|
|
|
(1
|
)%
|
|
$
|
607,249
|
|
|
$
|
595,140
|
|
|
2
|
%
|
Revenues from gathering, processing and transportation
decrease
d by
$1.7 million
for the
three months ended June 30, 2017
, primarily due to
decrease
s of (i) $11.8 million due to the Property Exchange in March 2017, (ii) $9.5 million at the Springfield system, $3.6 million at the Chipeta complex and $2.2 million at the Marcellus Interest systems due to throughput decreases, (iii) $4.8 million due to the sale of the Hugoton system in October 2016 and (iv) $2.8 million at the Granger complex due to a lower processing fee. These decreases were partially offset by increases of (i) $25.1 million at the DBM complex due to increased throughput (see
Operating Results–Throughput
within this Item 2) and (ii) $6.1 million at the DJ Basin complex due to a higher throughput fee.
Revenues from gathering, processing and transportation
increase
d by
$12.1 million
for the
six months ended June 30, 2017
, primarily due to
increase
s of (i) $56.4 million at the DBM complex due to increased throughput (see
Operating Results–Throughput
within this Item 2) and (ii) $14.6 million at the DJ Basin complex due to increased throughput and a higher throughput fee. These increases were partially offset by decreases of (i) $18.2 million at the Springfield system, $8.1 million at the Chipeta complex and $6.0 million at the Marcellus Interest systems due to throughput decreases, (ii) $13.1 million due to the Property Exchange in March 2017, (iii) $9.7 million due to the sale of the Hugoton system in October 2016 and (iv) $4.2 million at the Granger complex due to a lower processing fee.
Natural Gas and Natural Gas Liquids Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except percentages and per-unit amounts
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
Natural gas sales
(1)
|
|
$
|
92,946
|
|
|
$
|
44,366
|
|
|
109
|
%
|
|
$
|
172,861
|
|
|
$
|
82,593
|
|
|
109
|
%
|
Natural gas liquids sales
(1)
|
|
131,878
|
|
|
82,627
|
|
|
60
|
%
|
|
258,488
|
|
|
132,956
|
|
|
94
|
%
|
Total
|
|
$
|
224,824
|
|
|
$
|
126,993
|
|
|
77
|
%
|
|
$
|
431,349
|
|
|
$
|
215,549
|
|
|
100
|
%
|
Average price per unit
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
2.95
|
|
|
$
|
2.09
|
|
|
41
|
%
|
|
$
|
3.00
|
|
|
$
|
2.20
|
|
|
36
|
%
|
Natural gas liquids (per Bbl)
|
|
19.98
|
|
|
20.33
|
|
|
(2
|
)%
|
|
20.87
|
|
|
19.69
|
|
|
6
|
%
|
|
|
(1)
|
Excludes amounts considered above market with respect to our swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
|
For the three and
six months ended June 30, 2017
, average natural gas and NGL prices included the effects of commodity price swap agreements attributable to sales for the MGR assets and DJ Basin complex. For the three and six months ended June 30, 2016, average natural gas and NGL prices included the effects of commodity price swap agreements attributable to sales for the Hugoton system, MGR assets and DJ Basin complex. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
The
increase
in natural gas sales of
$48.6 million
for the
three months ended June 30, 2017
, was primarily due to increases of (i) $30.5 million at the DBM complex due to an increase in volumes sold (see
Operating Results–Throughput
within this Item 2) and (ii) $16.1 million at the DJ Basin complex due to an increase in average price and volumes sold.
The
increase
in natural gas sales of
$90.3 million
for the
six months ended June 30, 2017
, was primarily due to
increase
s of (i) $60.3 million at the DBM complex due to an increase in volumes sold (see
Operating Results–Throughput
within this Item 2), (ii) $28.7 million at the DJ Basin complex due to an increase in average price and volumes sold and (iii) $6.4 million at the Hilight system due to an increase in average price. These increases were partially offset by a decrease of $6.2 million at the MGR assets due to the partial equity treatment of our above-market swap agreements beginning January 1, 2017.
The
increase
in NGLs sales of
$49.3 million
and
$125.5 million
for the three and
six months ended June 30, 2017
, respectively, was primarily due to
increase
s of (i) $57.2 million and $121.8 million, respectively, at the DBM complex due to an increase in volumes sold (see
Operating Results–Throughput
within this Item 2), (ii) $5.4 million and $22.2 million, respectively, at the DJ Basin complex due to an increase in volumes sold and (iii) $2.6 million and $8.0 million, respectively, at the Hilight system due to an increase in average price. These increases were partially offset by decreases during the three and
six months ended June 30, 2017
, of $17.1 million and $32.2 million, respectively, at the MGR assets due to the partial equity treatment of our above-market swap agreements beginning January 1, 2017.
Equity Income, Net – Affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
Equity income, net – affiliates
|
|
$
|
21,728
|
|
|
$
|
19,693
|
|
|
10
|
%
|
|
$
|
41,189
|
|
|
$
|
36,507
|
|
|
13
|
%
|
For the three and
six months ended June 30, 2017
, equity income, net – affiliates
increase
d by
$2.0 million
and
$4.7 million
, respectively, primarily due to an increase in equity income from the TEFR Interests due to increased volumes. In addition, for the
six months ended June 30, 2017
, equity income, net – affiliates increased due to our 14.81% share of an impairment loss determined by the managing partner of Fort Union in the first quarter of 2016.
Cost of Product and Operation and Maintenance Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
NGL purchases
(1)
|
|
$
|
114,607
|
|
|
$
|
50,056
|
|
|
129
|
%
|
|
$
|
222,980
|
|
|
$
|
82,725
|
|
|
170
|
%
|
Residue purchases
(1)
|
|
87,807
|
|
|
47,413
|
|
|
85
|
%
|
|
166,123
|
|
|
86,398
|
|
|
92
|
%
|
Other
(1)
|
|
863
|
|
|
7,380
|
|
|
(88
|
)%
|
|
3,533
|
|
|
12,193
|
|
|
(71
|
)%
|
Cost of product
|
|
203,277
|
|
|
104,849
|
|
|
94
|
%
|
|
392,636
|
|
|
181,316
|
|
|
117
|
%
|
Operation and maintenance
|
|
76,148
|
|
|
75,173
|
|
|
1
|
%
|
|
149,908
|
|
|
151,386
|
|
|
(1
|
)%
|
Total cost of product and operation and maintenance expenses
|
|
$
|
279,425
|
|
|
$
|
180,022
|
|
|
55
|
%
|
|
$
|
542,544
|
|
|
$
|
332,702
|
|
|
63
|
%
|
|
|
(1)
|
Excludes amounts considered above market with respect to our swap agreements for the MGR assets, DJ Basin complex and Hugoton system (until its divestiture in October 2016) that were recorded as capital contributions in the consolidated statement of equity and partners’ capital. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
|
Cost of product expense for the three and
six months ended June 30, 2017
, included the effects of commodity price swap agreements attributable to purchases for the MGR assets and DJ Basin complex. Cost of product expense for the three and
six months ended June 30, 2016
, included the effects of commodity price swap agreements attributable to purchases for the Hugoton system, MGR assets and DJ Basin complex. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
NGL purchases
increase
d by
$64.6 million
and
$140.3 million
for the three and
six months ended June 30, 2017
, respectively, primarily due to increases of (i) $54.4 million and $115.7 million, respectively, at the DBM complex due to an increase in volumes purchased (see
Operating Results
–
Throughput
within this Item 2), (ii) $14.7 million and $29.9 million, respectively, at the DJ Basin complex due to an increase in volumes purchased and (iii) $2.6 million and $6.5 million, respectively, at the Hilight system due to an increase in average price, partially offset by a decrease in volumes purchased. These increases were partially offset by decreases during the three and
six months ended June 30, 2017
, of $9.0 million and $17.1 million, respectively, at the MGR assets due to the partial equity treatment of our above-market swap agreements beginning January 1, 2017.
Residue purchases
increase
d by
$40.4 million
and
$79.7 million
for the three and
six months ended June 30, 2017
, respectively, primarily due to increases of (i) $28.4 million and $56.0 million, respectively, at the DBM complex due to an increase in volumes purchased (see
Operating Results
–
Throughput
within this Item 2), (ii) $11.1 million and $24.2 million, respectively, at the DJ Basin complex due to an increase in volumes purchased and (iii) $4.1 million and $5.8 million, respectively, at the Hilight system due to an increase in average price, partially offset by a decrease in volumes purchased. These increases were partially offset by decreases during the three and
six months ended June 30, 2017
, of $4.1 million and $8.0 million, respectively, at the MGR assets due to the partial equity treatment of our above-market swap agreements beginning January 1, 2017.
Other items
decrease
d by
$6.5 million
and
$8.7 million
for the three and
six months ended June 30, 2017
, respectively, primarily due to fees paid in 2016 for rerouting volumes due to the DBM outage.
Operation and maintenance expense
increase
d by
$1.0 million
for the
three months ended June 30, 2017
, primarily due to an increase of $2.6 million in other operating costs primarily at the DJ Basin and DBM complexes, partially offset by a decrease of $1.3 million in utilities expense primarily at the DJ Basin complex.
Operation and maintenance expense
decrease
d by
$1.5 million
for the
six months ended June 30, 2017
, primarily due to decreases of (i) $2.4 million in utilities expense primarily at the DJ Basin and Chipeta complexes and (ii) $1.5 million of salaries and wages due to the sale of the Hugoton system in October 2016. These decreases were partially offset by an increase of $2.7 million in other operating costs primarily at the DJ Basin and DBM complexes.
Other Operating Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
General and administrative
|
|
$
|
10,585
|
|
|
$
|
10,883
|
|
|
(3
|
)%
|
|
$
|
23,244
|
|
|
$
|
22,160
|
|
|
5
|
%
|
Property and other taxes
|
|
11,924
|
|
|
12,078
|
|
|
(1
|
)%
|
|
24,218
|
|
|
22,428
|
|
|
8
|
%
|
Depreciation and amortization
|
|
74,031
|
|
|
67,305
|
|
|
10
|
%
|
|
143,733
|
|
|
132,400
|
|
|
9
|
%
|
Impairments
|
|
3,178
|
|
|
2,403
|
|
|
32
|
%
|
|
167,920
|
|
|
8,921
|
|
|
NM
|
|
Total other operating expenses
|
|
$
|
99,718
|
|
|
$
|
92,669
|
|
|
8
|
%
|
|
$
|
359,115
|
|
|
$
|
185,909
|
|
|
93
|
%
|
NM-Not Meaningful
General and administrative expenses
increase
d by
$1.1 million
for the
six months ended June 30, 2017
, primarily due to increases in personnel costs for which we reimbursed Anadarko pursuant to our omnibus agreement and bad debt expense, partially offset by decreases in legal and consulting fees.
Property and other taxes
increase
d by
$1.8 million
for the
six months ended June 30, 2017
, primarily due to ad valorem tax increases at the DBM complex and DBJV system.
Depreciation and amortization expense
increase
d by
$6.7 million
and
$11.3 million
for the three and
six months ended June 30, 2017
, respectively, primarily due to depreciation expense increases of (i) $5.5 million and $5.1 million, respectively, due to the Property Exchange in March 2017, (ii) $2.8 million and $6.7 million, respectively, related to capital projects at the DBM complex and (iii) $2.8 million and $5.6 million, respectively, at the Bison facility due to a change in the estimated property life. These increases were partially offset by decreases during the three and
six months ended June 30, 2017
, of (i) $2.4 million and $2.5 million, respectively, at the Granger complex due to an impairment recorded in the first quarter of 2017 (see impairment expense below) and (ii) $2.0 million and $4.1 million, respectively, due to the sale of the Hugoton system in October 2016.
Impairment expense
increase
d by
$0.8 million
for the
three months ended June 30, 2017
, primarily due to an impairment of $3.1 million at the Fort Union system in 2017, as compared to the impairment in 2016 primarily related to the abandonment of compressors at the MIGC system.
Impairment expense
increase
d by
$159.0 million
for the
six months ended June 30, 2017
, primarily due to an impairment of
$158.8 million
at the Granger complex in 2017. This asset was impaired to its estimated fair value of
$48.5 million
, using the income approach and Level 3 fair value inputs, due to a reduced throughput fee as a result of a producer’s bankruptcy. Also during 2017, we recognized additional impairments of
$9.1 million
, primarily due to (i) a $3.7 million impairment at the Granger straddle plant, which was impaired to its estimated salvage value of $0.6 million using the income approach and Level 3 fair value inputs, (ii) a $3.1 million impairment at the Fort Union system, which was impaired to its estimated fair value of $8.5 million using the income approach and Level 3 fair value inputs and (iii) the cancellation of a pipeline project in West Texas. Impairment expense for the six months ended June 30, 2016, was primarily related to the Newcastle system. This asset was impaired to its estimated fair value of $3.1 million, using the income approach and Level 3 fair value inputs, due to a reduction in estimated future cash flows caused by the low commodity price environment.
Interest Income – Affiliates and Interest Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
Note receivable – Anadarko
|
|
$
|
4,225
|
|
|
$
|
4,225
|
|
|
—
|
%
|
|
$
|
8,450
|
|
|
$
|
8,450
|
|
|
—
|
%
|
Interest income – affiliates
|
|
$
|
4,225
|
|
|
$
|
4,225
|
|
|
—
|
%
|
|
$
|
8,450
|
|
|
$
|
8,450
|
|
|
—
|
%
|
Third parties
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt
|
|
$
|
(35,161
|
)
|
|
$
|
(28,281
|
)
|
|
24
|
%
|
|
$
|
(69,780
|
)
|
|
$
|
(56,099
|
)
|
|
24
|
%
|
Amortization of debt issuance costs and commitment fees
|
|
(1,645
|
)
|
|
(1,545
|
)
|
|
6
|
%
|
|
(3,275
|
)
|
|
(3,075
|
)
|
|
7
|
%
|
Capitalized interest
|
|
1,060
|
|
|
1,482
|
|
|
(28
|
)%
|
|
1,876
|
|
|
3,331
|
|
|
(44
|
)%
|
Affiliates
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred purchase price obligation – Anadarko
(1)
|
|
—
|
|
|
15,461
|
|
|
(100
|
)%
|
|
(71
|
)
|
|
10,924
|
|
|
(101
|
)%
|
Interest expense
|
|
$
|
(35,746
|
)
|
|
$
|
(12,883
|
)
|
|
177
|
%
|
|
$
|
(71,250
|
)
|
|
$
|
(44,919
|
)
|
|
59
|
%
|
|
|
(1)
|
See
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
for a discussion of the Deferred purchase price obligation - Anadarko.
|
Interest expense
increase
d by
$22.9 million
and
$26.3 million
for the three and
six months ended June 30, 2017
, respectively, primarily due to (i) accretion revisions in 2016 recorded as reductions to interest expense for the Deferred purchase price obligation - Anadarko (see
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
), (ii) interest incurred on the 2026 Notes issued in July 2016 and (iii) interest incurred on the additional 2044 Notes issued in October 2016. These increases were partially offset by additional interest incurred on the RCF in 2016, as a result of higher outstanding borrowings. Capitalized interest
decrease
d by
$0.4 million
and
$1.5 million
for the three and
six months ended June 30, 2017
, respectively, primarily due to the completion of Trains IV and V in May 2016 and October 2016, respectively, partially offset by an increase due to the construction of Train VI beginning in the fourth quarter of 2016, all located at the DBM complex. See
Note 9—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
Income Tax (Benefit) Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except percentages
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
Income (loss) before income taxes
|
|
$
|
176,340
|
|
|
$
|
167,651
|
|
|
5
|
%
|
|
$
|
283,883
|
|
|
$
|
293,367
|
|
|
(3
|
)%
|
Income tax (benefit) expense
|
|
843
|
|
|
326
|
|
|
159
|
%
|
|
4,395
|
|
|
6,959
|
|
|
(37
|
)%
|
Effective tax rate
|
|
—
|
%
|
|
—
|
%
|
|
|
|
2
|
%
|
|
2
|
%
|
|
|
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
six months ended June 30, 2016
, the variance from the federal statutory rate was primarily due to federal and state taxes on pre-acquisition income attributable to Partnership assets acquired from Anadarko, and our share of Texas margin tax. For all other periods presented, the variance from the federal statutory rate, which is zero percent as a non-taxable entity, was primarily due to our share of Texas margin tax.
Income attributable to the Springfield system prior to and including February 2016 was subject to federal and state income tax. Income earned on the Springfield system for periods subsequent to February 2016 was only subject to Texas margin tax on income apportionable to Texas.
KEY PERFORMANCE METRICS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except percentages and per-unit amounts
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
|
2017
|
|
2016
|
|
Inc/
(Dec)
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets
(1)
|
|
$
|
297,778
|
|
|
$
|
294,661
|
|
|
1
|
%
|
|
$
|
599,283
|
|
|
$
|
571,190
|
|
|
5
|
%
|
Adjusted gross margin for crude, NGL and produced water assets
(2)
|
|
35,770
|
|
|
34,593
|
|
|
3
|
%
|
|
65,821
|
|
|
69,288
|
|
|
(5
|
)%
|
Adjusted gross margin attributable to Western Gas Partners, LP
(3)
|
|
333,548
|
|
|
329,254
|
|
|
1
|
%
|
|
665,104
|
|
|
640,478
|
|
|
4
|
%
|
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets
(4)
|
|
0.94
|
|
|
0.84
|
|
|
12
|
%
|
|
0.89
|
|
|
0.82
|
|
|
9
|
%
|
Adjusted gross margin per Bbl for crude, NGL and produced water assets
(5)
|
|
2.15
|
|
|
2.03
|
|
|
6
|
%
|
|
2.07
|
|
|
2.05
|
|
|
1
|
%
|
Adjusted EBITDA attributable to Western Gas Partners, LP
(3)
|
|
274,835
|
|
|
250,565
|
|
|
10
|
%
|
|
529,829
|
|
|
481,664
|
|
|
10
|
%
|
Distributable cash flow
(3)
|
|
247,225
|
|
|
199,349
|
|
|
24
|
%
|
|
463,728
|
|
|
391,287
|
|
|
19
|
%
|
|
|
(1)
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets is calculated as total revenues and other for natural gas assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for natural gas assets, plus distributions from our equity investments in Fort Union and Rendezvous, and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. See the reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets to its most comparable GAAP measure below.
|
|
|
(2)
|
Adjusted gross margin for crude, NGL and produced water assets is calculated as total revenues and other for crude, NGL and produced water assets, less reimbursements for electricity-related expenses recorded as revenue and cost of product for crude, NGL and produced water assets, plus distributions from our equity investments in White Cliffs, the Mont Belvieu JV, and the TEFR Interests. See the reconciliation of Adjusted gross margin for crude, NGL and produced water assets to its most comparable GAAP measure below.
|
|
|
(3)
|
For a reconciliation of Adjusted gross margin attributable to Western Gas Partners, LP, Adjusted EBITDA attributable to Western Gas Partners, LP and Distributable cash flow to the most directly comparable financial measure calculated and presented in accordance with GAAP, see the descriptions below.
|
|
|
(4)
|
Average for period. Calculated as Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets, divided by total throughput (MMcf/d) attributable to Western Gas Partners, LP for natural gas assets.
|
|
|
(5)
|
Average for period. Calculated as Adjusted gross margin for crude, NGL and produced water assets, divided by total throughput (MBbls/d) for crude, NGL and produced water assets.
|
Adjusted gross margin attributable to Western Gas Partners, LP.
We define Adjusted gross margin attributable to Western Gas Partners, LP (“Adjusted gross margin”) as total revenues and other, less cost of product and reimbursements for electricity-related expenses recorded as revenue, plus distributions from equity investments and excluding the noncontrolling interest owner’s proportionate share of revenue and cost of product. We believe Adjusted gross margin is an important performance measure of the core profitability of our operations, as well as our operating performance as compared to that of other companies in our industry.
Adjusted gross margin
increase
d by
$4.3 million
and
$24.6 million
for the three and
six months ended June 30, 2017
, respectively, primarily due to (i) an increase in throughput at the DBM complex and (ii) an increase in processed volumes at the DJ Basin complex. These increases were partially offset by decreases from (i) the Property Exchange in March 2017, (ii) lower throughput at the Springfield and Marcellus Interest systems, (iii) the partial equity treatment of our above-market swap agreements at the MGR assets beginning January 1, 2017, and (iv) the sale of the Hugoton system in October 2016.
To facilitate investor and industry analyst comparisons between us and our peers, we also disclose
Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets
and
Adjusted gross margin per Bbl for crude, NGL and produced water assets
. Adjusted gross margin per Mcf attributable to Western Gas Partners, LP for natural gas assets
increase
d by
$0.10
and
$0.07
for the three and
six months ended June 30, 2017
, respectively, primarily due to the Property Exchange in March 2017 and
increase
d throughput at the DBM complex. Adjusted gross margin per Bbl for crude, NGL and produced water assets
increase
d by
$0.12
and
$0.02
for the three and
six months ended June 30, 2017
, respectively, primarily due to higher distributions received from the Mont Belvieu JV.
Adjusted EBITDA attributable to Western Gas Partners, LP.
We define Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) as net income (loss) attributable to Western Gas Partners, LP, 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, and other income. We believe that 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 to assess the following, among other measures:
|
|
•
|
our operating performance as compared to other publicly traded partnerships in the midstream energy 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 expenditure projects and the returns on investment of various investment opportunities.
|
Adjusted EBITDA
increase
d by
$24.3 million
for the
three months ended June 30, 2017
, primarily due to a
$96.8 million
increase
in total revenues and other, a
$21.5 million
increase
in business interruption proceeds, and a
$4.4 million
increase
in distributions from equity investments. These amounts were partially offset by a
$98.3 million
increase
in cost of product (net of lower of cost or market inventory adjustments).
Adjusted EBITDA
increase
d by
$48.2 million
for the
six months ended June 30, 2017
, primarily due to a
$229.8 million
increase
in total revenues and other, a
$27.3 million
increase
in business interruption proceeds, a
$2.3 million
increase
in distributions from equity investments, a
$1.7 million
decrease
in net income attributable to noncontrolling interest, and a
$1.5 million
decrease
in operation and maintenance expenses. These amounts were partially offset by a
$211.2 million
increase
in cost of product (net of lower of cost or market inventory adjustments), a
$1.8 million
increase
in property and other tax expense, and a
$1.4 million
increase
in general and administrative expenses excluding non-cash equity-based compensation expense.
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 our commodity price swap agreements to the extent such amounts are not recognized as Adjusted EBITDA, less net cash paid (or to be paid) for interest expense (including amortization of deferred debt issuance costs originally paid in cash, offset by non-cash capitalized interest), maintenance capital expenditures, Series A Preferred unit distributions and income taxes. We compare Distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute 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 and compare it with the performance of other publicly traded partnerships.
While Distributable cash flow is a measure we use to assess our ability to make distributions to our unitholders, it should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute 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.
Distributable cash flow
increase
d by
$47.9 million
for the
three months ended June 30, 2017
, primarily due to a
$24.3 million
increase
in Adjusted EBITDA, a
$14.1 million
decrease
in Series A Preferred unit distributions, a
$9.7 million
decrease
in cash paid for maintenance capital expenditures, and a
$6.8 million
increase
in the above-market component of the swap agreements with Anadarko. These amounts were partially offset by a
$7.0 million
increase
in net cash paid for interest expense.
Distributable cash flow
increase
d by
$72.4 million
for the
six months ended June 30, 2017
, primarily due to a
$48.2 million
increase
in Adjusted EBITDA, a
$17.5 million
decrease
in cash paid for maintenance capital expenditures, a
$12.3 million
increase
in the above-market component of the swap agreements with Anadarko, and an
$8.5 million
decrease
in Series A Preferred unit distributions. These amounts were partially offset by a
$13.9 million
increase
in net cash paid for interest expense.
Reconciliation of non-GAAP 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), while net income (loss) attributable to Western Gas Partners, LP 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) attributable to Western Gas Partners, LP. 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) attributable to Western Gas Partners, LP, 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) attributable to Western Gas Partners, LP 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.
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) attributable to Western Gas Partners, LP 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 uses in evaluating our operating results.
The following tables present (a) a reconciliation of the GAAP financial measure of operating income (loss) to the non-GAAP financial measure of Adjusted gross margin, (b) a reconciliation of the GAAP financial measures of net income (loss) attributable to Western Gas Partners, LP and 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 net income (loss) attributable to Western Gas Partners, LP to the non-GAAP financial measure of Distributable cash flow:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Reconciliation of Operating income (loss) to Adjusted gross margin attributable to Western Gas Partners, LP
|
|
|
|
|
|
|
|
|
Operating income (loss)
|
|
$
|
207,608
|
|
|
$
|
176,362
|
|
|
$
|
346,000
|
|
|
$
|
329,765
|
|
Add:
|
|
|
|
|
|
|
|
|
Distributions from equity investments
|
|
28,856
|
|
|
24,491
|
|
|
51,423
|
|
|
49,130
|
|
Operation and maintenance
|
|
76,148
|
|
|
75,173
|
|
|
149,908
|
|
|
151,386
|
|
General and administrative
|
|
10,585
|
|
|
10,883
|
|
|
23,244
|
|
|
22,160
|
|
Property and other taxes
|
|
11,924
|
|
|
12,078
|
|
|
24,218
|
|
|
22,428
|
|
Depreciation and amortization
|
|
74,031
|
|
|
67,305
|
|
|
143,733
|
|
|
132,400
|
|
Impairments
|
|
3,178
|
|
|
2,403
|
|
|
167,920
|
|
|
8,921
|
|
Less:
|
|
|
|
|
|
|
|
|
Gain (loss) on divestiture and other, net
|
|
15,458
|
|
|
(1,907
|
)
|
|
134,945
|
|
|
(2,539
|
)
|
Proceeds from business interruption insurance claims
|
|
24,115
|
|
|
2,603
|
|
|
29,882
|
|
|
2,603
|
|
Equity income, net – affiliates
|
|
21,728
|
|
|
19,693
|
|
|
41,189
|
|
|
36,507
|
|
Reimbursed electricity-related charges recorded as revenues
|
|
14,046
|
|
|
14,869
|
|
|
28,015
|
|
|
30,537
|
|
Adjusted gross margin attributable to noncontrolling interest
|
|
3,435
|
|
|
4,183
|
|
|
7,311
|
|
|
8,604
|
|
Adjusted gross margin attributable to Western Gas Partners, LP
|
|
$
|
333,548
|
|
|
$
|
329,254
|
|
|
$
|
665,104
|
|
|
$
|
640,478
|
|
Adjusted gross margin attributable to Western Gas Partners, LP for natural gas assets
|
|
$
|
297,778
|
|
|
$
|
294,661
|
|
|
$
|
599,283
|
|
|
$
|
571,190
|
|
Adjusted gross margin for crude, NGL and produced water assets
|
|
35,770
|
|
|
34,593
|
|
|
65,821
|
|
|
69,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
173,451
|
|
|
$
|
164,521
|
|
|
$
|
275,340
|
|
|
$
|
280,581
|
|
Add:
|
|
|
|
|
|
|
|
|
Distributions from equity investments
|
|
28,856
|
|
|
24,491
|
|
|
51,423
|
|
|
49,130
|
|
Non-cash equity-based compensation expense
|
|
975
|
|
|
1,246
|
|
|
2,221
|
|
|
2,549
|
|
Interest expense
|
|
35,746
|
|
|
12,883
|
|
|
71,250
|
|
|
44,919
|
|
Income tax expense
|
|
843
|
|
|
326
|
|
|
4,395
|
|
|
6,959
|
|
Depreciation and amortization
(1)
|
|
73,352
|
|
|
66,650
|
|
|
142,401
|
|
|
131,089
|
|
Impairments
|
|
3,178
|
|
|
2,403
|
|
|
167,920
|
|
|
8,921
|
|
Other expense
(1)
|
|
95
|
|
|
56
|
|
|
140
|
|
|
56
|
|
Less:
|
|
|
|
|
|
|
|
|
Gain (loss) on divestiture and other, net
|
|
15,458
|
|
|
(1,907
|
)
|
|
134,945
|
|
|
(2,539
|
)
|
Equity income, net – affiliates
|
|
21,728
|
|
|
19,693
|
|
|
41,189
|
|
|
36,507
|
|
Interest income – affiliates
|
|
4,225
|
|
|
4,225
|
|
|
8,450
|
|
|
8,450
|
|
Other income
(1)
|
|
250
|
|
|
—
|
|
|
677
|
|
|
122
|
|
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
274,835
|
|
|
$
|
250,565
|
|
|
$
|
529,829
|
|
|
$
|
481,664
|
|
Reconciliation of Net cash provided by operating activities to Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
240,536
|
|
|
$
|
157,363
|
|
|
$
|
433,152
|
|
|
$
|
393,866
|
|
Interest (income) expense, net
|
|
31,521
|
|
|
8,658
|
|
|
62,800
|
|
|
36,469
|
|
Uncontributed cash-based compensation awards
|
|
(209
|
)
|
|
86
|
|
|
(172
|
)
|
|
158
|
|
Accretion and amortization of long-term obligations, net
|
|
(1,038
|
)
|
|
14,522
|
|
|
(2,139
|
)
|
|
9,055
|
|
Current income tax (benefit) expense
|
|
204
|
|
|
198
|
|
|
628
|
|
|
4,979
|
|
Other (income) expense, net
|
|
(253
|
)
|
|
53
|
|
|
(683
|
)
|
|
(71
|
)
|
Distributions from equity investments in excess of cumulative earnings – affiliates
|
|
5,768
|
|
|
5,827
|
|
|
9,221
|
|
|
10,611
|
|
Changes in operating working capital:
|
|
|
|
|
|
|
|
|
Accounts receivable, net
|
|
(10,876
|
)
|
|
45,800
|
|
|
(9,363
|
)
|
|
33,242
|
|
Accounts and imbalance payables and accrued liabilities, net
|
|
12,035
|
|
|
20,205
|
|
|
41,975
|
|
|
2,227
|
|
Other
|
|
(131
|
)
|
|
1,309
|
|
|
(116
|
)
|
|
(1,739
|
)
|
Adjusted EBITDA attributable to noncontrolling interest
|
|
(2,722
|
)
|
|
(3,456
|
)
|
|
(5,474
|
)
|
|
(7,133
|
)
|
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
274,835
|
|
|
$
|
250,565
|
|
|
$
|
529,829
|
|
|
$
|
481,664
|
|
Cash flow information of Western Gas Partners, LP
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
|
|
|
|
$
|
433,152
|
|
|
$
|
393,866
|
|
Net cash used in investing activities
|
|
|
|
|
|
(363,131
|
)
|
|
(952,824
|
)
|
Net cash provided by (used in) financing activities
|
|
|
|
|
|
(239,749
|
)
|
|
618,692
|
|
|
|
(1)
|
Includes our 75% share of depreciation and amortization; other expense; and other income attributable to the Chipeta complex.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
June 30,
|
|
Six Months Ended
June 30,
|
thousands except Coverage ratio
|
|
2017
|
|
2016
|
|
2017
|
|
2016
|
Reconciliation of Net income (loss) attributable to Western Gas Partners, LP to Distributable cash flow and calculation of the Coverage ratio
|
|
|
|
|
|
|
|
|
Net income (loss) attributable to Western Gas Partners, LP
|
|
$
|
173,451
|
|
|
$
|
164,521
|
|
|
$
|
275,340
|
|
|
$
|
280,581
|
|
Add:
|
|
|
|
|
|
|
|
|
Distributions from equity investments
|
|
28,856
|
|
|
24,491
|
|
|
51,423
|
|
|
49,130
|
|
Non-cash equity-based compensation expense
|
|
975
|
|
|
1,246
|
|
|
2,221
|
|
|
2,549
|
|
Non-cash settled - interest expense, net
(1)
|
|
—
|
|
|
(15,461
|
)
|
|
71
|
|
|
(10,924
|
)
|
Income tax (benefit) expense
|
|
843
|
|
|
326
|
|
|
4,395
|
|
|
6,959
|
|
Depreciation and amortization
(2)
|
|
73,352
|
|
|
66,650
|
|
|
142,401
|
|
|
131,089
|
|
Impairments
|
|
3,178
|
|
|
2,403
|
|
|
167,920
|
|
|
8,921
|
|
Above-market component of swap agreements with Anadarko
(3)
|
|
16,373
|
|
|
9,552
|
|
|
28,670
|
|
|
16,365
|
|
Other expense
(2)
|
|
95
|
|
|
56
|
|
|
140
|
|
|
56
|
|
Less:
|
|
|
|
|
|
|
|
|
Gain (loss) on divestiture and other, net
|
|
15,458
|
|
|
(1,907
|
)
|
|
134,945
|
|
|
(2,539
|
)
|
Equity income, net – affiliates
|
|
21,728
|
|
|
19,693
|
|
|
41,189
|
|
|
36,507
|
|
Cash paid for maintenance capital expenditures
(2)
|
|
11,402
|
|
|
21,085
|
|
|
22,524
|
|
|
39,982
|
|
Capitalized interest
|
|
1,060
|
|
|
1,482
|
|
|
1,876
|
|
|
3,331
|
|
Cash paid for (reimbursement of) income taxes
|
|
—
|
|
|
—
|
|
|
189
|
|
|
67
|
|
Series A Preferred unit distributions
|
|
—
|
|
|
14,082
|
|
|
7,453
|
|
|
15,969
|
|
Other income
(2)
|
|
250
|
|
|
—
|
|
|
677
|
|
|
122
|
|
Distributable cash flow
|
|
$
|
247,225
|
|
|
$
|
199,349
|
|
|
$
|
463,728
|
|
|
$
|
391,287
|
|
Distributions declared
(4)
|
|
|
|
|
|
|
|
|
Limited partners – common units
|
|
$
|
135,816
|
|
|
|
|
$
|
259,745
|
|
|
|
General partner
|
|
71,675
|
|
|
|
|
136,499
|
|
|
|
Total
|
|
$
|
207,491
|
|
|
|
|
$
|
396,244
|
|
|
|
Coverage ratio
|
|
1.19
|
|
x
|
|
|
1.17
|
|
x
|
|
|
|
(1)
|
Includes amounts related to the Deferred purchase price obligation - Anadarko. See
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
|
|
|
(2)
|
Includes our 75% share of depreciation and amortization; other expense; cash paid for maintenance capital expenditures; and other income attributable to the Chipeta complex.
|
|
|
(3)
|
See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
|
|
|
(4)
|
Reflects cash distributions of
$0.890
and
$1.765
per unit declared for the three and
six months ended June 30, 2017
, respectively.
|
LIQUIDITY AND CAPITAL RESOURCES
Our primary cash requirements are for acquisitions and capital expenditures, debt service, customary operating expenses, quarterly distributions to our limited partners and general partner, and distributions to our noncontrolling interest owner. Our sources of liquidity as of
June 30, 2017
, 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 our 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, including the extension of our commodity price swap agreements, 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, to limit interest expense, we may use operating cash flows to fund expansion capital expenditures or acquisitions, which could result in subsequent borrowings under our RCF to pay distributions or fund other short-term working capital requirements.
During the second quarter of 2017, we reached a settlement with insurers related to the insurance claim filed for the incident at the DBM complex and final proceeds were received. Recoveries from the business interruption claim related to the DBM outage are recognized as income when cash proceeds are received from insurers. During the
six months ended June 30, 2017
, we received
$52.9 million
in cash proceeds from insurers in final settlement of our claims related to the incident at the DBM complex, including
$29.9 million
for business interruption insurance claims and
$23.0 million
for property insurance claims (see
Note 1—Description of Business and Basis of Presentation
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
).
Our partnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date within 45 days of the end of each quarter. We have made cash distributions to our unitholders each quarter since our IPO and have increased our quarterly distribution each quarter since the second quarter of 2009. The Board of Directors declared a cash distribution to our unitholders for the
second quarter
of
2017
of
$0.890
per unit, or
$207.5 million
in aggregate, including incentive distributions, but excluding distributions on Class C units. The cash distribution
is payable
on
August 11, 2017
, to unitholders of record at the close of business on
July 31, 2017
. In connection with the closing of the DBM acquisition in November 2014, we issued Class C units that will receive distributions in the form of additional Class C units until March 1, 2020, unless earlier converted (see
Note 3—Partnership Distributions
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
). The Class C unit distribution, if paid in cash, would have been
$11.3 million
for the
second quarter
of
2017
. In 2016, we issued Series A Preferred units to private investors that received quarterly distributions in cash equal to $0.68 per Series A Preferred unit, subject to certain adjustments (see
Note 3—Partnership Distributions
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
). Effective as of May 2, 2017, the remaining Series A Preferred units converted into common units on a one-for-one basis. Such converted common units are entitled to distributions made to common unitholders, as described above, with respect to the second quarter of 2017.
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 notes. To facilitate a potential debt or equity securities issuance, we have the ability to sell securities under our shelf registration statements. 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 II, Item 1A of this Form
10-Q
.
Working capital
.
As of
June 30, 2017
, we had
$57.4 million
of working capital, which we define as the amount by which current assets exceed current liabilities. Working capital is an indication of our liquidity and potential need for short-term funding. Our working capital requirements are driven by changes in accounts receivable and accounts payable and factors such as credit extended to, and the timing of collections from, our customers, and the level and timing of our spending for maintenance and expansion activity. As of
June 30, 2017
, we had
$1.035 billion
available for borrowing under our RCF. See
Note 9—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
Capital expenditures
.
Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or develop new midstream infrastructure. We categorize capital expenditures as either of the following:
|
|
•
|
maintenance capital expenditures, which include those expenditures required to maintain the 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 (for fiscal year 2017, the general partner’s Board of Directors has approved Estimated Maintenance Capital Expenditures (as defined in our partnership agreement) of $18.0 million per quarter); or
|
|
|
•
|
expansion capital expenditures, which include expenditures to construct new midstream infrastructure and those 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. Capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
thousands
|
|
2017
|
|
2016
|
Acquisitions
|
|
$
|
159,197
|
|
|
$
|
715,199
|
|
|
|
|
|
|
Expansion capital expenditures
|
|
$
|
236,538
|
|
|
$
|
212,081
|
|
Maintenance capital expenditures
|
|
22,599
|
|
|
39,988
|
|
Total capital expenditures
(1) (2)
|
|
$
|
259,137
|
|
|
$
|
252,069
|
|
|
|
|
|
|
Capital incurred
(2)
|
|
$
|
279,921
|
|
|
$
|
261,342
|
|
|
|
(1)
|
Capital expenditures for the
six months ended June 30, 2017
and
2016
, are presented net of
$1.3 million
and
$3.9 million
, respectively, of contributions in aid of construction costs from affiliates.
|
|
|
(2)
|
For the
six months ended June 30, 2017
and
2016
, included
$1.9 million
and
$3.3 million
, respectively, of capitalized interest.
|
Acquisitions during 2017 included the Additional DBJV System Interest and equipment purchases from Anadarko. Acquisitions during 2016 included Springfield and equipment purchases from Anadarko. See
Note 2—Acquisitions and Divestitures
and
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
Capital expenditures, excluding acquisitions,
increase
d by
$7.1 million
for the
six months ended June 30, 2017
. Expansion capital expenditures
increase
d by
$24.5 million
(including a
$1.5 million
decrease
in capitalized interest) for the
six months ended June 30, 2017
, primarily due to an increase of $43.9 million due to the construction of two produced-water disposal systems, $36.9 million for purchases of long lead items related to the future construction of the Mentone plant, $20.4 million at the DBJV system and $5.5 million at the DJ Basin complex. These increases were partially offset by decreases of $71.0 million at the DBM complex and $7.5 million at the Haley system. Maintenance capital expenditures
decrease
d by
$17.4 million
for the
six months ended June 30, 2017
, primarily due to repairs made in 2016 at the DBM complex as a result of the DBM outage. In addition, maintenance capital expenditures decreased at the MGR assets due to timing of expenditures and at the Non-Operated Marcellus Interest systems due to the Property Exchange in March 2017.
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:
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
thousands
|
|
2017
|
|
2016
|
Net cash provided by (used in):
|
|
|
|
|
Operating activities
|
|
$
|
433,152
|
|
|
$
|
393,866
|
|
Investing activities
|
|
(363,131
|
)
|
|
(952,824
|
)
|
Financing activities
|
|
(239,749
|
)
|
|
618,692
|
|
Net increase (decrease) in cash and cash equivalents
|
|
$
|
(169,728
|
)
|
|
$
|
59,734
|
|
Operating Activities
. Net cash provided by operating activities during the
six months ended June 30, 2017
and
2016
,
increase
d primarily due to the impact of changes in working capital items. Refer to
Operating Results
within this
Item 2
for a discussion of our results of operations as compared to the prior periods.
Investing Activities
. Net cash used in investing activities for the
six months ended June 30, 2017
, included the following:
|
|
•
|
$259.1 million
of capital expenditures, net of
$1.3 million
of contributions in aid of construction costs from affiliates, primarily related to construction and expansion at the DBM complex and DBJV system, and purchases of long lead items related to the future construction of the Mentone plant, all located in West Texas;
|
|
|
•
|
$155.3 million of cash consideration paid as part of the Property Exchange;
|
|
|
•
|
$3.9 million
of cash paid for equipment purchases from Anadarko;
|
|
|
•
|
$23.3 million of net proceeds from the sale of the Helper and Clawson systems in Utah;
|
|
|
•
|
$23.0 million
of proceeds from property insurance claims attributable to the DBM outage; and
|
|
|
•
|
$9.2 million
of distributions from equity investments in excess of cumulative earnings.
|
Net cash used in investing activities for the
six months ended June 30, 2016
, included the following:
|
|
•
|
$712.5 million of cash paid for the acquisition of Springfield;
|
|
|
•
|
$252.1 million
of capital expenditures, net of
$3.9 million
of contributions in aid of construction costs from affiliates, primarily related to plant construction and expansion at the DBM and DJ Basin complexes and the DBJV system;
|
|
|
•
|
$2.7 million
of cash paid for equipment purchases from Anadarko;
|
|
|
•
|
$10.6 million
of distributions from equity investments in excess of cumulative earnings; and
|
|
|
•
|
$2.9 million
of proceeds from property insurance claims attributable to the DBM outage.
|
Financing Activities
. Net cash used in financing activities for the
six months ended June 30, 2017
, included the following:
|
|
•
|
$381.8 million
of distributions paid to our unitholders;
|
|
|
•
|
$37.3 million
of cash paid to Anadarko for the settlement of the Deferred purchase price obligation - Anadarko;
|
|
|
•
|
$6.4 million
of distributions paid to the noncontrolling interest owner of Chipeta;
|
|
|
•
|
$160.0 million of borrowings under our RCF, which were used for general partnership purposes; and
|
|
|
•
|
$28.7 million
of capital contribution from Anadarko related to the above-market component of swap agreements.
|
Net cash provided by financing activities for the
six months ended June 30, 2016
, included the following:
|
|
•
|
$440.0 million of net proceeds from the issuance of 14,030,611 Series A Preferred units in March 2016, all of which was used to fund a portion of the acquisition of Springfield;
|
|
|
•
|
$530.0 million of borrowings under our RCF, which were used to fund a portion of the Springfield acquisition and for general partnership purposes, including funding capital expenditures;
|
|
|
•
|
$246.9 million of net proceeds from the issuance of 7,892,220 Series A Preferred units in April 2016, all of which was used to pay down amounts borrowed under our RCF in connection with the acquisition of Springfield;
|
|
|
•
|
$25.0 million of net proceeds from the sale of common units to WGP, all of which was used to fund a portion of the acquisition of Springfield;
|
|
|
•
|
$16.4 million
of capital contribution from Anadarko related to the above-market component of swap agreements;
|
|
|
•
|
$313.4 million
of distributions paid to our unitholders;
|
|
|
•
|
$290.0 million
of repayments of outstanding borrowings under our RCF;
|
|
|
•
|
$27.5 million
of net distributions paid to Anadarko representing pre-acquisition intercompany transactions attributable to Springfield; and
|
|
|
•
|
$7.5 million
of distributions paid to the noncontrolling interest owner of Chipeta.
|
Debt and credit facility.
At
June 30, 2017
, our debt consisted of $500.0 million aggregate principal amount of the 2021 Notes, $670.0 million aggregate principal amount of the 2022 Notes, $350.0 million aggregate principal amount of the 2018 Notes, $600.0 million aggregate principal amount of the 2044 Notes, $500.0 million aggregate principal amount of the 2025 Notes, $500.0 million aggregate principal amount of the 2026 Notes and
$160.0 million
of borrowings outstanding under our RCF. As of
June 30, 2017
, the carrying value of our outstanding debt was
$3.3 billion
. See
Note 9—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
Senior Notes
. At
June 30, 2017
, we were in compliance with all covenants under the indentures governing our outstanding notes.
Revolving credit facility.
As of
June 30, 2017
, we had
$160.0 million
of outstanding RCF borrowings and
$4.9 million
in outstanding letters of credit, resulting in
$1.035 billion
available for borrowing under the RCF, which matures in February 2020. At
June 30, 2017
, the interest rate on the RCF was
2.53%
, the facility fee rate was
0.20%
and we were in compliance with all covenants under the RCF.
Deferred purchase price obligation - Anadarko.
Prior to our agreement with Anadarko to settle our 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. The cash payment would have been equal to (a) eight multiplied by the average of our share in the Net Earnings (see definition below) of DBJV for the calendar years 2018 and 2019, less (b) our share of all capital expenditures incurred for DBJV between March 1, 2015, and February 29, 2020. Net Earnings was defined as all revenues less cost of product, operating expenses and property taxes, in each case attributable to DBJV on an accrual basis. In May 2017, we reached an agreement with Anadarko to settle this obligation whereby we made a cash payment to Anadarko of $37.3 million, equal to the net present value of the obligation at March 31, 2017. See
Note 2—Acquisitions and Divestitures
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
Securities
.
We may issue an indeterminate amount of common units and various debt securities under our effective shelf registration statement on file with the SEC. We may also issue common units under the $500.0 million COP, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings.
We have an effective registration statement with the SEC relating to the public resale of the common units issued upon conversion of the Series A Preferred units. See
Note 4—Equity and Partners’ Capital
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
for a discussion of the Series A Preferred units.
Credit risk
.
We bear credit risk represented by our exposure to non-payment or non-performance by our counterparties, including Anadarko, 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.
We are dependent upon a single producer, Anadarko, for a substantial portion of our volumes (excluding our equity investment throughput), and we do not maintain a credit limit with respect to Anadarko. Consequently, we are subject to the risk of non-payment or late payment by Anadarko for gathering, processing and transportation fees and for proceeds from the sale of residue, NGLs and condensate to Anadarko.
We expect our exposure to concentrated risk of non-payment or non-performance to continue for as long as we remain substantially dependent on Anadarko for our revenues. Additionally, we are exposed to credit risk on the note receivable from Anadarko. We are also party to agreements with Anadarko under which Anadarko 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 acquired from Anadarko. Finally, we have entered into various commodity price swap agreements with Anadarko in order to reduce our exposure to a majority of the commodity price risk inherent in our percent-of-proceeds and keep-whole contracts, and are subject to performance risk thereunder. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
Our ability to make distributions to our unitholders may be adversely impacted if Anadarko becomes unable to perform under the terms of our gathering, processing and transportation agreements, natural gas and NGL purchase agreements, Anadarko’s note payable to us, our omnibus agreement, the services and secondment agreement, contribution agreements or the commodity price swap agreements.
CONTRACTUAL OBLIGATIONS
Our contractual obligations include, among other things, a revolving credit facility, other third-party long-term debt, capital obligations related to our expansion projects and various operating leases. Refer to
Note 9—Debt and Interest Expense
and
Note 10—Commitments and Contingencies
in the
Notes to Consolidated Financial Statements
under Part I, Item 1 of this Form 10-Q for an update to our contractual obligations as of
June 30, 2017
, including, but not limited to, increases in committed capital.
OFF-BALANCE SHEET ARRANGEMENTS
We do not have any off-balance sheet arrangements other than operating leases and standby letters of credit. The information pertaining to operating leases and our standby letters of credit required for this item is provided under
Note 10—Commitments and Contingencies
and
Note 9—Debt and Interest Expense
, respectively, included in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.
RECENT ACCOUNTING DEVELOPMENTS
See
Note 1—Description of Business and Basis of Presentation
in the
Notes to Consolidated Financial Statements
under
Part I
,
Item 1
of this Form
10-Q
.