e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended June 30, 2011
Or
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o |
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number: 001-34046
WESTERN GAS PARTNERS, LP
(Exact name of registrant as specified in its charter)
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Delaware
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26-1075808 |
(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization)
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Identification No.) |
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1201 Lake Robbins Drive
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77380 |
The Woodlands, Texas
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(Zip Code) |
(Address of principal executive offices) |
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(832) 636-6000
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files). Yes
þ No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company. See the definitions of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Exchange Act.
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Large accelerated filer þ | |
Accelerated filer o | |
Non-accelerated filer o | |
Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes o No þ
There were 57,854,693 common units outstanding as of July 29, 2011.
DEFINITIONS
As generally used within the energy industry and in this quarterly report on Form 10-Q, the
identified terms have the following meanings:
Barrel or Bbl: 42 U.S. gallons measured at 60 degrees Fahrenheit.
Bcf: One billion cubic feet.
Bcf/d: One billion cubic feet per day.
Btu: British thermal unit; the approximate amount of heat required to raise the temperature of
one pound of water by one degree Fahrenheit.
Condensate: A natural gas liquid with a low vapor pressure mainly composed of propane, butane,
pentane and heavier hydrocarbon fractions.
Cryogenic: The fractionation process in which liquefied gases, such as liquid nitrogen or
liquid helium, are used to bring volumes to very low temperatures (below approximately -238 degrees
Fahrenheit) to separate natural gas liquids from natural gas. Through cryogenic processing, more
natural gas liquids are extracted than when traditional refrigeration methods are used.
Drip condensate: Heavier hydrocarbon liquids that fall out of the natural gas stream and are
recovered in the gathering system without processing.
Fractionation: The process of applying various levels of higher pressure and lower temperature
to separate a stream of natural gas liquids into ethane, propane, normal butane, isobutane and
natural gasoline.
Imbalance: Imbalances result from (i) differences between gas volumes nominated by customers
and gas volumes received from those customers and (ii) differences between gas volumes received
from customers and gas volumes delivered to those customers.
MBbls/d: One thousand barrels per day.
MMBtu: One million British thermal units.
MMBtu/d: One million British thermal units per day.
MMcf: One million cubic feet.
MMcf/d: One million cubic feet per day.
Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane
and natural gasolines that, when removed from natural gas, become liquid under various levels of
higher pressure and lower temperature.
Pounds per square inch, absolute: The pressure resulting from a one-pound force applied to an
area of one square inch, including local atmospheric pressure. All volumes presented herein are
based on a standard pressure base of 14.73 pounds per square inch, absolute.
Residue gas: The natural gas remaining after being processed or treated.
3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
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Three Months Ended |
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Six Months Ended |
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June 30, |
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June 30, |
thousands except per-unit amounts |
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2011 |
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2010 (1) |
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2011 |
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2010 (1) |
Revenues affiliates |
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Gathering, processing and transportation of natural gas
and natural gas liquids |
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$ |
50,580 |
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$ |
45,290 |
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$ |
99,190 |
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$ |
90,758 |
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Natural gas, natural gas liquids and condensate sales |
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67,320 |
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59,576 |
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120,521 |
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119,254 |
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Equity income and other, net |
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3,579 |
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1,444 |
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6,287 |
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3,042 |
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Total revenues affiliates |
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121,479 |
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106,310 |
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225,998 |
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213,054 |
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Revenues third parties |
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Gathering, processing and transportation of natural gas
and natural gas liquids |
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16,929 |
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10,201 |
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29,449 |
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21,648 |
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Natural gas, natural gas liquids and condensate sales |
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23,237 |
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7,457 |
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41,441 |
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17,651 |
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Other, net |
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103 |
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1,015 |
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853 |
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1,566 |
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Total revenues third parties |
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40,269 |
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18,673 |
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71,743 |
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40,865 |
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Total revenues |
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161,748 |
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124,983 |
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297,741 |
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253,919 |
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Operating expenses |
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Cost of product (2) |
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62,317 |
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38,506 |
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109,137 |
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80,479 |
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Operation and maintenance (2) |
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23,639 |
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22,205 |
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44,501 |
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44,596 |
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General and administrative (2) |
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7,082 |
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5,455 |
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13,780 |
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11,523 |
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Property and other taxes |
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3,974 |
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3,649 |
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7,933 |
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7,268 |
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Depreciation, amortization and impairments |
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21,711 |
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17,613 |
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41,269 |
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35,332 |
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Total operating expenses |
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118,723 |
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87,428 |
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216,620 |
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179,198 |
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Operating income |
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43,025 |
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37,555 |
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81,121 |
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74,721 |
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Interest income affiliates |
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4,225 |
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4,232 |
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8,450 |
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8,462 |
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Interest expense (3) |
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(6,697 |
) |
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(3,598 |
) |
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(12,808 |
) |
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(7,126 |
) |
Other expense, net |
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(3,682 |
) |
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(2,393 |
) |
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(1,922 |
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(2,373 |
) |
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Income before income taxes |
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36,871 |
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35,796 |
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74,841 |
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73,684 |
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Income tax expense |
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94 |
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3,419 |
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126 |
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8,975 |
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Net income |
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36,777 |
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32,377 |
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74,715 |
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64,709 |
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Net income attributable to noncontrolling interests |
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2,838 |
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3,371 |
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5,792 |
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5,265 |
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Net income attributable to Western Gas Partners, LP |
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$ |
33,939 |
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$ |
29,006 |
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$ |
68,923 |
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$ |
59,444 |
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Limited partner interest in net income: |
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Net income attributable to Western Gas Partners, LP |
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$ |
33,939 |
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$ |
29,006 |
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$ |
68,923 |
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$ |
59,444 |
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Pre-acquisition net income allocated to Parent |
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(5,595 |
) |
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(11,901 |
) |
General partner interest in net income (4) |
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(1,842 |
) |
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(519 |
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(3,290 |
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(1,002 |
) |
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Limited partner interest in net income (4) |
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$ |
32,097 |
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$ |
22,892 |
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$ |
65,633 |
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$ |
46,541 |
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Net income per common unit basic and diluted |
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$ |
0.40 |
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$ |
0.35 |
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$ |
0.83 |
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$ |
0.72 |
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Net income per subordinated unit basic and diluted |
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$ |
0.38 |
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$ |
0.35 |
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$ |
0.79 |
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$ |
0.72 |
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Net income per limited partner unit basic and diluted |
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$ |
0.39 |
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$ |
0.35 |
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$ |
0.82 |
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$ |
0.72 |
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(1) |
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Financial information for 2010 has been revised to include results
attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1. |
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(2) |
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Cost of product includes product purchases from Anadarko (as defined in Note 1) of
$18.1 million and $33.6 million for the three and six months ended June 30, 2011,
respectively, and $16.1 million and $32.8 million for the three and six months ended June 30,
2010, respectively. Operation and maintenance includes charges from Anadarko of $10.5 million
and $20.2 million for the three and six months ended June 30, 2011, respectively, and $8.9
million and $20.5 million for the three and six months ended June 30, 2010, respectively.
General and administrative includes charges from Anadarko of $5.2 million and $10.3 million
for the three and six months ended June 30, 2011, respectively, and $4.4 million and $8.9
million for the three and six months ended June 30, 2010, respectively. See Note 4. |
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(3) |
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Includes affiliate interest expense of $1.2 million and $2.5 million for the three
and six months ended June 30, 2011, respectively, and $1.8 million and $3.6 million for the
three and six months ended June 30, 2010, respectively. See Note 7. |
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(4) |
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Represents net income for periods including and subsequent to the acquisition of the
Partnership assets (as defined in Note 1). See also Note 3. |
See accompanying Notes to Consolidated Financial Statements.
4
WESTERN GAS PARTNERS, LP
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
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June 30, |
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December 31, |
thousands except number of units |
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2011 |
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2010 |
ASSETS |
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Current assets |
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Cash and cash equivalents |
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$ |
62,695 |
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$ |
27,074 |
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Accounts receivable, net (1) |
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28,104 |
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10,890 |
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Other current assets |
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3,701 |
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5,220 |
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Total current assets |
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94,500 |
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43,184 |
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Note receivable Anadarko |
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260,000 |
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260,000 |
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Plant, property and equipment |
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Cost |
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2,025,652 |
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1,727,231 |
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Less accumulated depreciation |
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406,956 |
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367,881 |
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Net property, plant and equipment |
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1,618,696 |
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1,359,350 |
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Goodwill and other intangible assets |
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115,266 |
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60,236 |
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Equity investments |
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39,742 |
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40,406 |
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Other assets |
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9,017 |
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2,361 |
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Total assets |
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$ |
2,137,221 |
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$ |
1,765,537 |
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LIABILITIES, EQUITY AND PARTNERS CAPITAL |
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Current liabilities |
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Accounts and natural gas imbalance payables (2) |
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$ |
20,343 |
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$ |
15,175 |
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Accrued ad valorem taxes |
|
|
7,806 |
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|
5,986 |
|
Income taxes payable |
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|
326 |
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|
160 |
|
Accrued liabilities (3) |
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30,144 |
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|
20,873 |
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Total current liabilities |
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58,619 |
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|
42,194 |
|
Long-term debt third parties |
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|
493,946 |
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299,000 |
|
Note payable Anadarko |
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175,000 |
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|
175,000 |
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Asset retirement obligations and other |
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61,514 |
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|
44,275 |
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Total long-term liabilities |
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730,460 |
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|
518,275 |
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Total liabilities |
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789,079 |
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|
560,469 |
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Equity and partners capital |
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|
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Common units (54,904,409 and 51,036,968 units issued and outstanding at
June 30, 2011, and December 31, 2010, respectively) |
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|
943,973 |
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|
810,717 |
|
Subordinated units (26,536,306 units issued and outstanding at
June 30, 2011, and
December 31, 2010) |
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|
282,969 |
|
|
|
282,384 |
|
General partner units (1,661,757 and 1,583,128 units issued and outstanding at
June 30, 2011, and December 31, 2010, respectively) |
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|
25,052 |
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|
21,505 |
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|
|
|
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Total partners capital |
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|
1,251,994 |
|
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|
1,114,606 |
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Noncontrolling interests |
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|
96,148 |
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|
90,462 |
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Total equity and partners capital |
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1,348,142 |
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|
|
1,205,068 |
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Total liabilities, equity and partners capital |
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$ |
2,137,221 |
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$ |
1,765,537 |
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(1) |
|
Accounts receivable, net includes amounts receivable from affiliates (as
defined in Note 1) of $11.2 million and $1.8 million as of June 30, 2011, and December 31,
2010, respectively. |
(2) |
|
Accounts and natural gas imbalances payables includes amounts payable to affiliates
of $1.4 million and $1.5 million as of June 30, 2011, and December 31, 2010, respectively. |
(3) |
|
Accrued liabilities include amounts payable to affiliates of $0.3 million and $0.6
million as of June 30, 2011, and December 31, 2010, respectively. |
See accompanying Notes to Consolidated Financial Statements.
5
WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENT OF EQUITY AND PARTNERS CAPITAL
(UNAUDITED)
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Partners Capital |
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|
Limited Partners |
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General |
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Noncontrolling |
|
|
thousands |
|
Common |
|
Subordinated |
|
Partner |
|
Interests |
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Total |
Balance at December 31, 2010 |
|
$ |
810,717 |
|
|
$ |
282,384 |
|
|
$ |
21,505 |
|
|
$ |
90,462 |
|
|
$ |
1,205,068 |
|
Net income |
|
|
44,615 |
|
|
|
21,018 |
|
|
|
3,290 |
|
|
|
5,792 |
|
|
|
74,715 |
|
Issuance of common and general partner units, net of offering expenses |
|
|
129,805 |
|
|
|
|
|
|
|
2,764 |
|
|
|
|
|
|
|
132,569 |
|
Contributions from noncontrolling interest
owners |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,389 |
|
|
|
7,389 |
|
Distributions to noncontrolling interest owners |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,495 |
) |
|
|
(7,495 |
) |
Distributions to unitholders |
|
|
(40,801 |
) |
|
|
(20,433 |
) |
|
|
(2,498 |
) |
|
|
|
|
|
|
(63,732 |
) |
Non-cash equity-based compensation and other |
|
|
(363 |
) |
|
|
|
|
|
|
(9 |
) |
|
|
|
|
|
|
(372 |
) |
|
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2011 |
|
$ |
943,973 |
|
|
$ |
282,969 |
|
|
$ |
25,052 |
|
|
$ |
96,148 |
|
|
$ |
1,348,142 |
|
|
|
|
|
|
|
|
|
|
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|
See accompanying Notes to Consolidated Financial Statements.
6
WESTERN GAS PARTNERS, LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
June 30, |
thousands |
|
2011 |
|
2010 (1) |
Cash flows from operating activities |
|
|
|
|
|
|
|
|
Net income |
|
$ |
74,715 |
|
|
$ |
64,709 |
|
Adjustments to reconcile net income to net cash provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, amortization and impairments |
|
|
41,269 |
|
|
|
35,332 |
|
Deferred income taxes |
|
|
(41 |
) |
|
|
(2,633 |
) |
Changes in assets and liabilities: |
|
|
|
|
|
|
|
|
Increase in accounts receivable, net |
|
|
(17,741 |
) |
|
|
(6,352 |
) |
Increase in accounts and natural gas imbalance payables and accrued liabilities, net |
|
|
12,189 |
|
|
|
8,106 |
|
Change in other items, net |
|
|
2,962 |
|
|
|
564 |
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
113,353 |
|
|
|
99,726 |
|
Cash flows from investing activities |
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(29,956 |
) |
|
|
(50,189 |
) |
Acquisition from affiliates |
|
|
|
|
|
|
(241,680 |
) |
Acquisition from third parties |
|
|
(303,602 |
) |
|
|
|
|
Investments in equity affiliates |
|
|
(93 |
) |
|
|
(310 |
) |
Proceeds from sale of assets to affiliate |
|
|
242 |
|
|
|
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(333,409 |
) |
|
|
(292,179 |
) |
Cash flows from financing activities |
|
|
|
|
|
|
|
|
Borrowings, net of issuance costs |
|
|
1,045,939 |
|
|
|
209,987 |
|
Repayments of debt |
|
|
(859,000 |
) |
|
|
(100,000 |
) |
Proceeds from issuance of common and general partner units |
|
|
132,569 |
|
|
|
99,311 |
|
Distributions to unitholders |
|
|
(63,732 |
) |
|
|
(43,435 |
) |
Contributions from noncontrolling interest owners |
|
|
7,389 |
|
|
|
2,053 |
|
Distributions to noncontrolling interest owners |
|
|
(7,495 |
) |
|
|
(6,383 |
) |
Net contributions from Parent |
|
|
7 |
|
|
|
25,338 |
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
255,677 |
|
|
|
186,871 |
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
35,621 |
|
|
|
(5,582 |
) |
Cash and cash equivalents at beginning of period |
|
|
27,074 |
|
|
|
69,984 |
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
62,695 |
|
|
$ |
64,402 |
|
|
|
|
|
|
|
Supplemental disclosures |
|
|
|
|
|
|
|
|
Contribution of assets from Parent |
|
$ |
7 |
|
|
$ |
7,530 |
|
Increase in accrued capital expenditures |
|
$ |
4,237 |
|
|
$ |
2,376 |
|
Interest paid |
|
$ |
8,271 |
|
|
$ |
6,068 |
|
Interest received |
|
$ |
8,450 |
|
|
$ |
8,450 |
|
|
|
|
(1) |
|
Financial information for 2010 has been revised to include results
attributable to the Wattenberg assets and 0.4% interest in White Cliffs. See Note 1. |
See accompanying Notes to Consolidated Financial Statements.
7
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Description of business. Western Gas Partners, LP (the Partnership) is a Delaware limited
partnership formed in August 2007. As of June 30, 2011, the Partnerships assets included eleven
gathering systems, six natural gas treating facilities, seven natural gas processing facilities,
one NGL pipeline, one interstate pipeline and interests in Fort Union Gas Gathering, L.L.C. (Fort
Union) and White Cliffs Pipeline, L.L.C. (White Cliffs) accounted for under the equity method.
The Partnerships assets are located in East and West Texas, the Rocky Mountains (Colorado, Utah
and Wyoming), and the Mid-Continent (Kansas and Oklahoma). The Partnership is engaged in the
business of gathering, processing, compressing, treating and transporting natural gas, condensate,
NGLs and crude oil for Anadarko Petroleum Corporation and its consolidated subsidiaries, as well as
third-party producers and customers.
For purposes of these consolidated financial statements, the Partnership refers to Western
Gas Partners, LP and its consolidated subsidiaries. The Partnerships general partner is Western
Gas Holdings, LLC (the general partner or GP), a wholly owned subsidiary of Anadarko Petroleum
Corporation. Anadarko or Parent refers to Anadarko Petroleum Corporation and its consolidated
subsidiaries, excluding the Partnership and the general partner. Affiliates refers to wholly
owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and also refers to
Fort Union and White Cliffs.
Basis of presentation. The accompanying consolidated financial statements of the Partnership 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. Investments in non-controlled entities over which the
Partnership exercises significant influence are accounted for under the equity method. The
Partnership records its 50% proportionate share of the assets, liabilities, revenues and expenses
attributable to the Newcastle system. Noncontrolling interests in the Partnerships assets and
income represent the aggregate 49% interest in Chipeta Processing LLC (Chipeta) held by Anadarko
Petroleum Corporation and a third party.
The information furnished herein reflects all normal recurring adjustments which are, in the
opinion of management, necessary for a fair statement of financial position as of June 30, 2011,
and December 31, 2010, results of operations for the three and six months ended June 30, 2011 and
2010, statement of equity and partners capital for the six months ended June 30, 2011, and
statements of cash flows for the six months ended June 30, 2011 and 2010. The Partnerships
financial results for the three and six months ended June 30, 2011, are not necessarily indicative
of the expected results for the full year ending December 31, 2011.
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, utilizing historical
experience and other methods considered reasonable under the particular circumstances. Changes in
facts and circumstances or additional information may result in revised estimates and actual
results may differ from these estimates.
Certain information and note disclosures normally 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 Partnerships annual report on Form 10-K, as filed with the
SEC on February 24, 2011. Management believes that the disclosures made are adequate to make the
information not misleading.
8
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
Acquisitions. The following table presents the acquisitions completed by the Partnership during
2010 and 2011, and details the funding for those acquisitions through
borrowings, cash on hand and/or
the issuance of Partnership equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands except unit and |
|
Acquisition |
|
Percentage |
|
|
|
|
|
Cash |
|
Common |
|
GP Units |
percent amounts |
|
Date |
|
Acquired |
|
Borrowings |
|
On Hand |
|
Units Issued |
|
Issued |
Granger (1) |
|
|
01/29/10 |
|
|
|
100% |
|
|
$ |
210,000 |
|
|
$ |
31,680 |
|
|
|
620,689 |
|
|
|
12,667 |
|
Wattenberg (2) |
|
|
08/02/10 |
|
|
|
100% |
|
|
|
450,000 |
|
|
|
23,100 |
|
|
|
1,048,196 |
|
|
|
21,392 |
|
White Cliffs (3) |
|
|
09/28/10 |
|
|
|
10% |
|
|
|
|
|
|
|
38,047 |
|
|
|
|
|
|
|
|
|
Platte Valley (4) |
|
|
02/28/11 |
|
|
|
100% |
|
|
|
303,000 |
|
|
|
602 |
|
|
|
|
|
|
|
|
|
Bison (5) |
|
|
07/08/11 |
|
|
|
100% |
|
|
|
|
|
|
|
25,000 |
|
|
|
2,950,284 |
|
|
|
60,210 |
|
|
|
|
(1) |
|
The assets acquired from Anadarko include (i) the Granger gathering system
with related compressors and other facilities, and (ii) the Granger complex, consisting of
cryogenic trains, a refrigeration train, an NGLs fractionation facility and ancillary
equipment. These assets, located in southwestern Wyoming, are referred to collectively as the
Granger assets and the acquisition as the Granger acquisition. |
|
(2) |
|
The assets acquired from Anadarko include the Wattenberg gathering system and
related facilities, including the Fort Lupton processing plant. These assets, located in the
Denver-Julesburg Basin, north and east of Denver, Colorado, are referred to collectively as
the Wattenberg assets and the acquisition as the Wattenberg acquisition. |
|
(3) |
|
White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and
terminates in Cushing, Oklahoma, which became operational in June 2009. The Partnerships
acquisition of the 0.4% interest in White Cliffs and related purchase option from Anadarko
combined with the acquisition of an additional 9.6% interest in White
Cliffs from a third party, are referred to
collectively as the White Cliffs acquisition. The Partnerships interest in White Cliffs is
referred to as the White Cliffs investment. |
|
(4) |
|
The assets acquired from a third party include (i) a natural gas gathering system
and related compression and other ancillary equipment, and (ii) cryogenic gas processing
facilities. These assets, located in the Denver-Julesburg Basin, are referred to collectively
as the Platte Valley assets and the acquisition as the Platte Valley acquisition. See
further information below. |
|
(5) |
|
Subsequent to June 30, 2011, the Partnership acquired Anadarkos Bison gas treating
facility and related assets located in the Powder River Basin in northeastern Wyoming,
including (i) three amine treating units, (ii) compressor units, and (iii) generators. These
assets are referred to collectively as the Bison assets and the acquisition as the Bison
acquisition. |
Platte Valley acquisition. The Platte Valley acquisition has been accounted for under the
acquisition method of accounting. At February 28, 2011, the date of the acquisition, the assets and
liabilities of the Partnership continue to be recorded based upon their historical costs and the
Platte Valley assets and liabilities are recorded at their estimated fair values. Results of
operations attributable to the Platte Valley assets were included in the Partnerships consolidated
statements of income beginning on the acquisition date in the first quarter of 2011.
The following is the current allocation of the purchase price to the assets acquired and
liabilities assumed in the Platte Valley acquisition as of the acquisition date.
|
|
|
|
|
thousands |
|
|
|
|
Property, plant and equipment |
|
$ |
264,521 |
|
Intangible assets |
|
|
55,399 |
|
Asset retirement obligations and other liabilities |
|
|
(16,318 |
) |
|
|
|
Total purchase price |
|
$ |
303,602 |
|
|
|
|
9
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
The purchase price allocation is based on an initial assessment of the fair value of the
assets acquired and liabilities assumed in the Platte Valley acquisition. The fair values of the
plant and processing facilities, related equipment, and intangible assets acquired were based on
market, cost and income approaches. The liabilities assumed include certain amounts associated with
environmental contingencies estimated by management. All fair-value measurements of assets acquired
and liabilities assumed are based on inputs that are not observable in the market and thus
represent Level 3 inputs. The current purchase price allocation is preliminary and is subject to
change pending post-closing purchase price adjustments; finalizing fair value estimates; and
completing evaluations of property, plant and equipment, intangible assets, asset retirement
obligations, contractual arrangements and legal and environmental matters as additional information
becomes available and is assessed by the Partnership. For more information regarding the intangible
assets presented in the table above, see Note 6.
The following table presents the pro forma condensed financial information as if the Platte
Valley acquisition occurred on January 1, 2011.
|
|
|
|
|
|
|
Six Months |
|
|
|
Ended |
|
thousands except per-unit amount |
|
June 30, 2011 |
|
Revenues |
|
$ |
313,780 |
|
Net income |
|
|
77,441 |
|
Net income attributable to Western Gas Partners, LP |
|
|
71,649 |
|
Earnings per limited partner unit basic and diluted |
|
$ |
0.85 |
|
The pro forma information is presented for illustration purposes only and is not necessarily
indicative of the operating results that would have occurred had the acquisition been completed at
the assumed date, nor is it necessarily indicative of future operating results of the combined
entity. The Partnerships pro forma information in the table above includes $31.5 million of
revenues and $21.3 million of expenses attributable to the Platte Valley assets and is included in
the Partnerships consolidated statement of income for the six months ended June 30, 2011. The pro
forma adjustments reflect pre-acquisition results of the Platte Valley assets for January and
February 2011, including (a) estimated revenues and expenses; (b) estimated depreciation and
amortization based on the preliminary purchase price allocated to property, plant and equipment and
other intangible assets and estimated useful lives; (c) elimination of $0.7 million of
acquisition-related costs; and (d) interest on the Partnerships $303.0 million of borrowings under
its revolving credit facility to finance the Platte Valley acquisition. The pro forma adjustments
include estimates and assumptions based on currently available information. Management believes the
estimates and assumptions are reasonable, and the relative effects of the transactions are properly
reflected. The pro forma information does not reflect any cost savings or other synergies
anticipated as a result of the acquisition, nor any future acquisition related expenses. Pro forma
information is not presented for periods ended on or before December 31, 2010, as it is not
practical to determine revenues and cost of product for periods prior to January 1, 2011, the
effective date of the gathering and processing agreement with the seller.
Presentation of Partnership acquisitions. References to the Partnership assets refer collectively
to the assets owned by the Partnership as of June 30, 2011. Because of Anadarkos control of the
Partnership through its ownership of the general partner, each acquisition as of June 30, 2011, of
Partnership assets, except for the acquisitions of the Platte Valley assets and the 9.6% interest
in White Cliffs from third parties, was considered a transfer of net assets between entities under
common control. As a result, after each acquisition of assets from Anadarko, the Partnership is
required to revise its financial statements to include the activities of the Partnership assets as
of the date of common control. Anadarko acquired the Wattenberg assets in connection with its
August 10, 2006, acquisition of Kerr-McGee Corporation, and made its initial investment in White
Cliffs on January 29, 2007.
10
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
The Partnerships historical financial statements for the three and six months ended June 30,
2010, as presented in the Partnerships second quarter 2010 Form 10-Q as filed with the SEC on
August 5, 2010, have been recast in this quarterly report on Form 10-Q to include the results
attributable to the Wattenberg assets and the 0.4% interest in White Cliffs as if the Partnership
owned such assets for all periods presented. Unless otherwise noted, references to periods prior
to the acquisition of the Partnership assets and similar phrases refer to periods prior to July
2010 with respect to the Wattenberg assets and periods prior to September 2010 with respect to the
White Cliffs investment. References to periods including and subsequent to the acquisition of the
Partnership assets and similar phrases refer to periods including and subsequent to July 2010 with
respect to the Wattenberg assets and periods including and subsequent to September 2010 with
respect to the White Cliffs investment. The consolidated financial statements for periods prior to
the Partnerships acquisition of the Partnership assets have been prepared from Anadarkos
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 assets during the periods
reported.
Net income attributable to the Partnership assets for periods prior to the Partnerships
acquisition of such assets is not allocated to the limited partners for purposes of calculating net
income per limited partner unit. In addition, certain amounts in prior periods have been
reclassified to conform to the current presentation. Specifically, during the quarter ended
September 30, 2010, the Partnership revised its presentation to report the effects of commodity
price swap agreements attributable to purchases in cost of product in its consolidated statements
of income. Net gains and losses on commodity price swap agreements related to purchases have been
reclassified from revenue to cost of product for all periods to conform to the current
presentation. The following table presents the impact to the historical consolidated statements of
income attributable to the Wattenberg assets and 0.4% interest in White Cliffs, as well as the
reclassification of the impact of commodity price swap agreements related to purchases:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2010 |
|
|
|
Partnership |
|
|
Wattenberg |
|
|
White |
|
|
|
|
|
|
|
thousands |
|
Historical |
|
|
Assets |
|
|
Cliffs |
|
|
Reclassification |
|
|
Combined |
|
Revenues |
|
$ |
87,968 |
|
|
$ |
30,094 |
|
|
$ |
50 |
|
|
$ |
6,871 |
|
|
$ |
124,983 |
|
Net income |
|
|
26,782 |
|
|
|
5,543 |
|
|
|
52 |
|
|
|
|
|
|
|
32,377 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2010 |
|
|
|
Partnership |
|
|
Wattenberg |
|
|
White |
|
|
|
|
|
|
|
thousands |
|
Historical |
|
|
Assets |
|
|
Cliffs |
|
|
Reclassification |
|
|
Combined |
|
Revenues |
|
$ |
182,287 |
|
|
$ |
65,131 |
|
|
$ |
90 |
|
|
$ |
6,411 |
|
|
$ |
253,919 |
|
Net income |
|
|
51,590 |
|
|
|
13,026 |
|
|
|
93 |
|
|
|
|
|
|
|
64,709 |
|
11
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION (CONTINUED)
Equity offerings. The Partnership completed the following public equity offerings during 2010 and
2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Underwriting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount and |
|
|
|
|
thousands except unit |
|
Common |
|
|
GP Units |
|
|
Price Per |
|
|
Other Offering |
|
|
Net |
|
and per-unit amounts |
|
Units Issued (2) |
|
|
Issued (3) |
|
|
Unit |
|
|
Expenses |
|
|
Proceeds (4) |
|
May 2010 equity offering (1) |
|
|
4,558,700 |
|
|
|
93,035 |
|
|
$ |
22.25 |
|
|
$ |
4,427 |
|
|
$ |
99,074 |
|
November 2010 equity offering |
|
|
8,415,000 |
|
|
|
171,734 |
|
|
|
29.92 |
|
|
|
10,279 |
|
|
|
246,729 |
|
March 2011 equity offering |
|
|
3,852,813 |
|
|
|
78,629 |
|
|
|
35.15 |
|
|
|
5,621 |
|
|
|
132,569 |
|
|
|
|
(1) |
|
The May 2010 equity
offering refers collectively to the May 2010
equity offering issuance, and the June 2010 exercise of the
underwriters over-allotment option. |
|
(2) |
|
Common units issued includes the issuance of 558,700 common units, 915,000 common
units and 302,813 common units pursuant to the exercise, in full or in part, of the
underwriters over-allotment options granted in connection with the May 2010, November 2010
and March 2011 equity offerings, respectively. |
|
(3) |
|
GP units issued represents general partner units issued to the general partner in
exchange for the general partners proportionate capital contribution to maintain its 2.0%
interest. |
|
(4) |
|
Net proceeds were primarily used to repay amounts outstanding under the
Partnerships revolving credit facility. |
Limited partner and general partner units. The Partnerships common units are listed on the
New York Stock Exchange under the symbol WES. The following table summarizes common, subordinated
and general partner units issued during the six months ended June 30, 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Limited Partner Units |
|
General |
|
|
thousands |
|
Common |
|
Subordinated |
|
Partner Units |
|
Total |
Balance at December 31, 2010 |
|
|
51,037 |
|
|
|
26,536 |
|
|
|
1,583 |
|
|
|
79,156 |
|
March 2011 equity offering |
|
|
3,853 |
|
|
|
|
|
|
|
79 |
|
|
|
3,932 |
|
Long-Term Incentive Plan Awards |
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
Balance at June 30, 2011 |
|
|
54,904 |
|
|
|
26,536 |
|
|
|
1,662 |
|
|
|
83,102 |
|
|
|
|
|
|
|
|
|
|
Anadarko holdings of Partnership equity. As of June 30, 2011, Anadarko held 1,661,757 general
partner units representing a 2% general partner interest in the Partnership, 10,302,631 common
units, 26,536,306 subordinated units, and 100% of the Partnerships incentive distribution rights,
or IDRs. Anadarko owned an aggregate 44.3% interest in the Partnership based on its holdings of
common and subordinated limited partner units. The public held 44,601,778 common units,
representing a 53.7% interest in the Partnership based on its holdings of common limited partner
units. Anadarkos ownership interest as of June 30, 2011, does not include the common or general
units it acquired in connection with the Bison acquisition, which was completed in July 2011.
Management anticipates the subordinated units held by Anadarko will convert to common units on
August 15, 2011.
Recently issued accounting standards not yet adopted. In May 2011, the Financial Accounting
Standards Board (the FASB) issued an Accounting Standards Update (ASU) amending guidance for
fair value measurements and related disclosures. The ASU clarifies the FASBs intent regarding the
application of existing fair value measurement requirements, changes the fair value measurement
requirements for certain financial instruments and requires additional disclosures about fair value
measurements. This ASU will apply to the Partnership prospectively beginning January 1, 2012. The
impact of the adoption of the ASU on the Partnerships consolidated financial statements, if any,
is currently under evaluation.
12
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
2. 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 Partnership declared the following cash distributions to
its unitholders for the periods presented:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Quarterly |
|
|
|
|
|
|
thousands except per-unit amounts |
|
Distribution |
|
Total Cash |
|
Date of |
Quarters Ended |
|
per Unit |
|
Distribution |
|
Distribution |
March 31, 2010 |
|
$ |
0.340 |
|
|
$ |
22,042 |
|
|
May 2010 |
June 30, 2010 |
|
$ |
0.350 |
|
|
$ |
24,378 |
|
|
August 2010 |
March 31, 2011 |
|
$ |
0.390 |
|
|
$ |
33,168 |
|
|
May 2011 |
June 30, 2011 (1) |
|
$ |
0.405 |
|
|
$ |
36,063 |
|
|
August 2011 |
|
|
|
(1) |
|
On June 30, 2011, the board of directors of the Partnerships general partner
declared a cash distribution to the Partnerships unitholders of $0.405 per unit, or $36.1
million in aggregate, including incentive distributions. The cash distribution is payable on
August 12, 2011, to unitholders of record at the close of business on July 29, 2011. |
3. NET INCOME PER LIMITED PARTNER UNIT
The Partnerships net income for periods including and subsequent to the Partnerships
acquisitions of the Partnership assets is allocated to the general partner and the limited
partners, including any subordinated unitholders, in accordance with their respective ownership
percentages, and when applicable, giving effect to incentive distributions allocable to the general
partner. The Partnerships net income allocable to the limited partners is allocated between the
common and subordinated unitholders by applying the provisions of the partnership agreement that
govern actual cash distributions as if all earnings for the period had been distributed.
Specifically, net income equal to the amount of available cash (as defined by the partnership
agreement) is allocated to the general partner, common unitholders and subordinated unitholders
consistent with actual cash distributions, including incentive distributions allocable to the
general partner. 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, common
unitholders and subordinated unitholders in accordance with their respective ownership percentages
during each period.
Basic and diluted net income per limited partner unit is calculated by dividing the limited
partners interest in net income by the weighted average number of limited partner units
outstanding during the period. The common units issued in connection with acquisitions and equity
offerings during 2010 and 2011 are included on a weighted-average basis for periods they were
outstanding. Management anticipates the subordinated units will convert to common units on August
15, 2011.
13
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
3. NET INCOME PER LIMITED PARTNER UNIT (CONTINUED)
The following table illustrates the Partnerships calculation of net income per unit for
common and subordinated limited partner units:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
June 30, |
thousands except per-unit amounts |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
Net income attributable to Western Gas Partners, LP |
|
$ |
33,939 |
|
|
$ |
29,006 |
|
|
$ |
68,923 |
|
|
$ |
59,444 |
|
Pre-acquisition net income allocated to Parent |
|
|
|
|
|
|
(5,595 |
) |
|
|
|
|
|
|
(11,901 |
) |
General partner interest in net income |
|
|
(1,842 |
) |
|
|
(519 |
) |
|
|
(3,290 |
) |
|
|
(1,002 |
) |
|
|
|
|
|
|
|
|
|
Limited partner interest in net income |
|
$ |
32,097 |
|
|
$ |
22,892 |
|
|
$ |
65,633 |
|
|
$ |
46,541 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income allocable to common units |
|
$ |
22,028 |
|
|
$ |
13,639 |
|
|
$ |
44,615 |
|
|
$ |
27,380 |
|
Net income allocable to subordinated units |
|
|
10,069 |
|
|
|
9,253 |
|
|
|
21,018 |
|
|
|
19,161 |
|
|
|
|
|
|
|
|
|
|
Limited partner interest in net income |
|
$ |
32,097 |
|
|
$ |
22,892 |
|
|
$ |
65,633 |
|
|
$ |
46,541 |
|
|
|
|
|
|
|
|
|
|
Net
income per limited partner unit basic and diluted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units |
|
$ |
0.40 |
|
|
$ |
0.35 |
|
|
$ |
0.83 |
|
|
$ |
0.72 |
|
Subordinated units |
|
$ |
0.38 |
|
|
$ |
0.35 |
|
|
$ |
0.79 |
|
|
$ |
0.72 |
|
Total limited partner units |
|
$ |
0.39 |
|
|
$ |
0.35 |
|
|
$ |
0.82 |
|
|
$ |
0.72 |
|
Weighted average limited partner units outstanding
basic and diluted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common units |
|
|
54,896 |
|
|
|
39,117 |
|
|
|
53,528 |
|
|
|
37,966 |
|
Subordinated units |
|
|
26,536 |
|
|
|
26,536 |
|
|
|
26,536 |
|
|
|
26,536 |
|
|
|
|
|
|
|
|
|
|
Total limited partner units |
|
|
81,432 |
|
|
|
65,653 |
|
|
|
80,064 |
|
|
|
64,502 |
|
|
|
|
|
|
|
|
|
|
4. 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 gas, condensate and NGLs to
Anadarko. In addition, the Partnership purchases natural gas from an affiliate of Anadarko pursuant
to gas purchase agreements. Operating 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 Partnerships general and administrative expenses are paid by
Anadarko, which results in affiliate transactions pursuant to the reimbursement provisions of the
omnibus agreement. Affiliate expenses do not inherently bear a direct relationship to affiliate
revenues and third-party expenses do not necessarily bear a direct relationship to third-party
revenues. See Note 1 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, held in separate bank accounts, is generally swept to centralized accounts. Prior to
the 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. Anadarko
charged or credited the Partnership interest at a variable rate on outstanding affiliate balances
for the periods these balances remained outstanding. The outstanding affiliate balances were
entirely settled through an adjustment to parent net investment in connection with the acquisition
of the Partnership assets. Subsequent to the acquisition of the Partnership assets, the Partnership
cash-settles transactions related to such assets directly with third parties and with Anadarko
affiliates and affiliate-based interest expense on current intercompany balances is not charged.
14
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
4. TRANSACTIONS WITH AFFILIATES (CONTINUED)
Note receivable from Anadarko. Concurrent with the closing of the Partnerships 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%. Interest on the note is payable quarterly. The
fair value of the note receivable from Anadarko was approximately $272.8 million and $258.9 million
at June 30, 2011, and December 31, 2010, 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.
Commodity price swap agreements. The Partnership holds commodity price swap agreements with
Anadarko to mitigate exposure to commodity price volatility that would otherwise be present as a
result of the purchase and sale of natural gas, condensate or NGLs. Notional volumes for each of
the 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 at the Hilight,
Hugoton, Newcastle, Granger and Wattenberg assets. 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. The Partnership reports its realized gains and losses on the commodity
price swap agreements related to sales in natural gas, natural gas liquids and condensate sales in
its consolidated statements of income in the period in which the associated revenues are
recognized. The Partnership reports its realized gains and losses on the commodity price swap
agreements related to purchases in cost of product in its consolidated statements of income in the
period in which the associated purchases are recorded. The Partnership has not
entered into any new commodity price swap agreements since the fourth quarter of 2010.
The following table summarizes realized gains and losses on commodity price swap agreements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
June 30, |
thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
Gains (losses) on commodity price swap agreements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas sales |
|
$ |
8,992 |
|
|
$ |
5,190 |
|
|
$ |
15,800 |
|
|
$ |
5,465 |
|
Natural gas liquids sales |
|
|
(10,677 |
) |
|
|
2,896 |
|
|
|
(16,518 |
) |
|
|
695 |
|
|
|
|
|
|
|
|
|
|
Total |
|
|
(1,685 |
) |
|
|
8,086 |
|
|
|
(718 |
) |
|
|
6,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Losses on commodity price swap agreements
related to purchases |
|
|
(6,670 |
) |
|
|
(6,871 |
) |
|
|
(12,876 |
) |
|
|
(6,411 |
) |
|
|
|
|
|
|
|
|
|
Net gains (losses) on commodity price swap agreements |
|
$ |
(8,355 |
) |
|
$ |
1,215 |
|
|
$ |
(13,594 |
) |
|
$ |
(251 |
) |
|
|
|
|
|
|
|
|
|
Gas gathering and processing agreements. The Partnership has significant gas gathering and
processing arrangements with affiliates of Anadarko on a majority of its systems. Approximately 80%
and 81% of the Partnerships gathering and transportation throughput for the three and six months
ended June 30, 2011 and 2010, respectively, was attributable to natural gas production owned or
controlled by Anadarko. Approximately 71% and 78% of the Partnerships processing throughput for
the three months ended June 30, 2011 and 2010, respectively, and 72% and 78% for the six months
ended June 30, 2011 and 2010, respectively, was attributable to natural gas production owned or
controlled by Anadarko.
15
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
4. TRANSACTIONS WITH AFFILIATES (CONTINUED)
Summary of affiliate transactions. Affiliate transactions include revenue from affiliates,
reimbursement of operating expenses and purchases of natural gas. The following table summarizes
affiliate transactions, including transactions with the general partner:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues (1) |
|
$ |
121,479 |
|
|
$ |
106,310 |
|
|
$ |
225,998 |
|
|
$ |
213,054 |
|
Cost of product (1) |
|
|
18,102 |
|
|
|
16,136 |
|
|
|
33,592 |
|
|
|
32,825 |
|
Operation and maintenance (2) |
|
|
10,526 |
|
|
|
8,904 |
|
|
|
20,178 |
|
|
|
20,467 |
|
General and administrative (3) |
|
|
5,225 |
|
|
|
4,434 |
|
|
|
10,262 |
|
|
|
8,897 |
|
|
|
|
|
|
|
|
|
|
Operating expenses |
|
|
33,853 |
|
|
|
29,474 |
|
|
|
64,032 |
|
|
|
62,189 |
|
Interest income (4) |
|
|
4,225 |
|
|
|
4,232 |
|
|
|
8,450 |
|
|
|
8,462 |
|
Interest expense (5) |
|
|
1,233 |
|
|
|
1,785 |
|
|
|
2,467 |
|
|
|
3,570 |
|
Distributions to unitholders (6) |
|
|
15,779 |
|
|
|
12,609 |
|
|
|
30,864 |
|
|
|
24,848 |
|
Contributions from noncontrolling interest owners |
|
|
2,659 |
|
|
|
34 |
|
|
|
3,619 |
|
|
|
2,019 |
|
Distributions to noncontrolling interest owners |
|
|
1,533 |
|
|
|
1,751 |
|
|
|
4,547 |
|
|
|
3,126 |
|
|
|
|
(1) |
|
Represents amounts recognized under gathering and processing, and purchase and
sale agreements with affiliates of Anadarko. |
|
(2) |
|
Represents expenses incurred under the Services and Secondment Agreement with
Anadarko, as applicable. See Note 1. |
|
(3) |
|
Represents general and administrative expense incurred under the Omnibus Agreement
with Anadarko, as applicable. See Note 1. |
|
(4) |
|
Represents interest income recognized under the Note Receivable from Anadarko. |
|
(5) |
|
Represents interest expense recognized under the Note Payable to
Anadarko. |
|
(6) |
|
Represents distributions paid to an affiliate of Anadarko under the Partnership
Agreement. |
Concentration of credit risk. Anadarko was the only customer from whom revenues exceeded 10%
of the Partnerships consolidated revenues for all periods presented on the Partnerships
consolidated statements of income. The percentages of revenues from Anadarko and the Partnerships
other customers are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2011 |
|
|
2010 |
|
|
2011 |
|
|
2010 |
|
Anadarko |
|
|
73% |
|
|
|
85% |
|
|
|
74% |
|
|
|
84% |
|
Other customers |
|
|
27% |
|
|
|
15% |
|
|
|
26% |
|
|
|
16% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
100% |
|
|
|
100% |
|
|
|
100% |
|
|
|
100% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
5. PROPERTY, PLANT AND EQUIPMENT
A summary of the historical cost of the Partnerships property, plant and equipment is as
follows:
|
|
|
|
|
|
|
|
|
thousands |
|
June 30, 2011 |
|
December 31, 2010 |
Land |
|
$ |
354 |
|
|
$ |
354 |
|
Gathering systems |
|
|
1,902,733 |
|
|
|
1,621,633 |
|
Pipelines and equipment |
|
|
83,718 |
|
|
|
83,613 |
|
Assets under construction |
|
|
35,713 |
|
|
|
18,928 |
|
Other |
|
|
3,134 |
|
|
|
2,703 |
|
|
|
|
|
|
Total property, plant and equipment |
|
|
2,025,652 |
|
|
|
1,727,231 |
|
Accumulated depreciation |
|
|
406,956 |
|
|
|
367,881 |
|
|
|
|
|
|
Net property, plant and equipment |
|
$ |
1,618,696 |
|
|
$ |
1,359,350 |
|
|
|
|
|
|
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. In addition, property, plant and
equipment cost as well as third-party accrued liability balances in the Partnerships consolidated
balance sheets include $9.7 million and $5.5 million of accrued capital as of June 30, 2011, and
December 31, 2010, respectively, representing estimated capital expenditures for which invoices had
not yet been processed.
6. OTHER INTANGIBLE ASSETS
The intangible asset balance in the Partnerships consolidated balance sheets represent the
estimated economic value related to the contracts assumed by the Partnership in connection with the
Platte Valley acquisition in February 2011, that dedicate certain customers field production to
the acquired gathering and processing system. These contracts ensure an extended commercial
relationship with the existing customers and provide the Partnership with a high probability of
additional production from the customers acreage. These contracts are generally limited, however,
by the quantity and production life of the underlying natural gas resource base.
At June 30, 2011, the carrying value of the Partnerships customer relationship intangible
assets was $55.0 million, net of $0.4 million of accumulated amortization, and is included in
goodwill and other intangible assets in the Partnerships consolidated balance sheets. Customer
relationships are amortized on a straight-line basis over 50 years, which is the estimated
productive life of the reserves covered by the underlying acreage ultimately expected to be
produced and gathered or processed through the Partnerships assets subject to current contractual
arrangements. Estimated future amortization for these intangible assets is as follows:
|
|
|
|
|
|
|
Future |
|
thousands |
|
amortization |
|
July December 2011 |
|
$ |
554 |
|
2012 |
|
|
1,108 |
|
2013 |
|
|
1,108 |
|
2014 |
|
|
1,108 |
|
2015 |
|
|
1,108 |
|
17
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
6. OTHER INTANGIBLE ASSETS (CONTINUED)
The Partnership assesses intangible assets for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be recoverable. Impairments
exist when the carrying amount of an asset exceeds estimates of the undiscounted cash flows
expected to result from the use and eventual disposition of the asset. When alternative courses of
action to recover the carrying amount of a long-lived asset are under consideration, estimates of
future undiscounted cash flows take into account possible outcomes and probabilities of their
occurrence. If the carrying amount of the long-lived asset is not recoverable based on the
estimated future undiscounted cash flows, the impairment loss is measured as the excess of the
assets carrying amount over its estimated fair value such that the assets carrying amount is
adjusted to its estimated fair value with an offsetting charge to operating expense. No intangible
asset impairment has been recognized in connection with these assets.
7. DEBT AND INTEREST EXPENSE
The following table presents the Partnerships outstanding debt as of June 30, 2011, and
December 31, 2010:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2011 |
|
December 31, 2010 |
|
|
|
|
|
|
Carrying |
|
Fair |
|
|
|
|
|
Carrying |
|
Fair |
thousands |
|
Principal |
|
Value |
|
Value |
|
Principal |
|
Value |
|
Value |
Revolving credit facility |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
49,000 |
|
|
$ |
49,000 |
|
|
$ |
49,000 |
|
5.375% Senior Notes due 2021 |
|
|
500,000 |
|
|
|
493,946 |
|
|
|
514,834 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Wattenberg term loan |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
250,000 |
|
|
|
250,000 |
|
|
|
250,000 |
|
Note payable to Anadarko |
|
|
175,000 |
|
|
|
175,000 |
|
|
|
170,327 |
|
|
|
175,000 |
|
|
|
175,000 |
|
|
|
168,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt outstanding (1) |
|
$ |
675,000 |
|
|
$ |
668,946 |
|
|
$ |
685,161 |
|
|
$ |
474,000 |
|
|
$ |
474,000 |
|
|
$ |
467,116 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The Partnerships consolidated balance sheets include accrued interest expense
of $3.3 million and $0.8 million as of June 30, 2011, and December 31, 2010, respectively,
which is included in accrued liabilities. |
Fair value of debt. The fair value of debt reflects any premium or discount for the
difference between the stated interest rate and quarter-end market interest rate and is based on
quoted market prices for identical instruments, if available, or based on valuations of similar
debt instruments.
The following table presents the debt activity of the Partnership for the six months ended
June 30, 2011:
|
|
|
|
|
thousands |
|
Carrying Value |
Balance as of December 31, 2010 |
|
$ |
474,000 |
|
First Quarter 2011 |
|
|
|
|
Revolving credit facility borrowings |
|
|
560,000 |
|
Repayment of revolving credit facility |
|
|
(139,000 |
) |
Repayment of Wattenberg term loan |
|
|
(250,000 |
) |
Revolving credit facility borrowings Swingline |
|
|
10,000 |
|
Repayment of revolving credit facility Swingline |
|
|
(10,000 |
) |
Second Quarter 2011 |
|
|
|
|
Revolving credit facility borrowings Swingline |
|
|
10,000 |
|
Issuance of 5.375% Senior Notes due 2021 |
|
|
500,000 |
|
Repayment of revolving credit facility |
|
|
(470,000 |
) |
Repayment of revolving credit facility Swingline |
|
|
(10,000 |
) |
Other and changes in debt discount |
|
|
(6,054 |
) |
|
|
|
Balance as of June 30, 2011 |
|
$ |
668,946 |
|
|
|
|
18
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
7. DEBT AND INTEREST EXPENSE (CONTINUED)
5.375% Senior Notes due 2021. In May 2011, the Partnership completed the offering of $500.0 million
aggregate principal amount of 5.375% Senior Notes due 2021 (the Notes) at a price to the public
of 98.778% of the face amount of the Notes. Interest on the Notes will be paid semi-annually on
June 1 and December 1 of each year, commencing on December 1, 2011. The Notes mature on June 1,
2021, unless redeemed, in whole or in part, at any time prior to maturity, at a redemption price
that includes a make-whole premium. Proceeds from the offering of the Notes (net of the
underwriting discount of $3.3 million and debt issuance costs)
were used to repay the then-outstanding balance on the Partnerships revolving credit facility, with the remainder used for
general partnership purposes.
The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of the
Partnerships wholly owned subsidiaries (the Subsidiary Guarantors). The Subsidiary Guarantors
guarantees will be released if, among other things, the Subsidiary Guarantors are released from
their obligations under the Partnerships revolving credit facility. See Note 9 for the financial
statements of the Subsidiary Guarantors.
The Notes indenture contains customary events of default including, among others, (i) default
in any payment of interest on any debt securities when due that continues for 30 days; (ii) default
in payment, when due, of principal of or premium, if any, on the Notes at maturity; and (iii)
certain events of bankruptcy or insolvency with respect to the Partnership. The indenture governing
the Notes also contains covenants that limit, among other things, the ability of the Partnership
and the Subsidiary Guarantors to (i) create liens on their principal properties; (ii) engage in
sale and leaseback transactions; and (iii) merge or consolidate with another entity or sell, lease
or transfer substantially all of their properties or assets to another entity. At June 30, 2011,
the Partnership was in compliance with all covenants under the Notes.
Note payable to Anadarko. In December 2008, the Partnership entered into a five-year $175.0 million
term loan agreement with Anadarko. The interest rate was fixed at 4.00% until November 2010. The
term loan agreement was amended in December 2010 to fix the interest rate at 2.82% through maturity
in 2013. The Partnership has the option, at any time, to repay the outstanding principal amount in
whole or in part.
The provisions of the five-year term loan agreement contain customary events of default,
including (i) non-payment of principal when due or non-payment of interest or other amounts within
three business days of when due, (ii) certain events of bankruptcy or insolvency with respect to
the Partnership and (iii) a change of control. At June 30, 2011, the Partnership was in compliance
with all covenants under this agreement.
Revolving credit facility. In March 2011, the Partnership entered into an amended and restated
$800.0 million senior unsecured revolving credit facility (the RCF) and borrowed $250.0 million
under the RCF to repay the Wattenberg term loan (described below). The RCF amended and restated the
Partnerships $450.0 million credit facility, which was originally entered into in October 2009.
The RCF matures in March 2016 and bears interest at London Interbank Offered Rate, or LIBOR, plus
applicable margins currently ranging from 1.30% to 1.90%, or an alternate base rate equal to the
greatest of (a) the Prime Rate, (b) the Federal Funds Effective Rate plus 0.5%, and (c) LIBOR plus
1%, plus applicable margins currently ranging from 0.30% to 0.90%. The interest rate was 1.89% and
3.26% at June 30, 2011, and at December 31, 2010, respectively. The Partnership is required to pay
a quarterly facility fee currently ranging from 0.20% to 0.35% of the commitment amount (whether
used or unused), based upon the Partnerships consolidated leverage ratio, as defined in the RCF.
The facility fee rate was 0.30% and 0.50% at June 30, 2011, and December 31, 2010, respectively.
19
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
7. DEBT AND INTEREST EXPENSE (CONTINUED)
The RCF contains covenants that limit, among other things, the ability of the Partnership and
certain of its subsidiaries to incur additional indebtedness, grant certain liens, merge,
consolidate or allow any material change in the character of its business, sell all or
substantially all of the Partnerships assets, make certain transfers, enter into certain affiliate
transactions, make distributions or other payments other than distributions of available cash under
certain conditions and use proceeds other than for partnership purposes. The RCF also contains
various customary covenants, customary events of default and certain financial tests as of the end
of each quarter, including a maximum consolidated leverage ratio (which is defined as the ratio of
consolidated indebtedness as of the last day of a fiscal quarter to consolidated EBITDA for the
most recent four consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated
leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately
following certain acquisitions, and a minimum consolidated interest coverage ratio (which is
defined as the ratio of consolidated EBITDA for the most recent four consecutive fiscal quarters to
consolidated interest expense for such period) of 2.0 to 1.0.
All amounts due under the RCF are unconditionally guaranteed by the Partnerships wholly owned
subsidiaries. The Partnership will no longer be required to comply with the minimum consolidated
interest coverage ratio as well as the subsidiary guarantees and certain of the aforementioned
covenants, if the Partnership obtains two of the following three ratings: BBB- or better by S&P,
Baa3 or better by Moodys, or BBB- or better by Fitch. As of June 30, 2011, no amounts were
outstanding under the RCF, with $800.0 million available for borrowing. At June 30, 2011, the
Partnership was in compliance with all covenants under the RCF.
Wattenberg term loan. In connection with the Wattenberg acquisition, in August 2010 the Partnership
borrowed $250.0 million under a three-year term loan from a group of banks (Wattenberg term
loan). The Wattenberg term loan incurred interest at LIBOR plus a margin ranging from 2.50% to
3.50% depending on the Partnerships consolidated leverage ratio as defined in the Wattenberg term
loan agreement. The Partnership repaid the Wattenberg term loan in March 2011 using borrowings from
its RCF and recognized $1.3 million of accelerated amortization expense related to its early
repayment.
Interest-rate swap agreement. The Partnership entered into a forward-starting interest-rate swap
agreement in March 2011 to mitigate the risk of rising interest rates prior to the issuance of the
Notes. In May 2011, the Partnership issued the Notes and terminated the swap agreement, realizing a
loss of $1.9 million, which is included in other expense, net in the Partnerships consolidated statements of
income.
Interest expense. The following table summarizes the amounts included in interest expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
Third Parties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense on long-term debt |
|
$ |
4,474 |
|
|
$ |
1,130 |
|
|
$ |
7,150 |
|
|
$ |
2,107 |
|
Amortization of debt issuance costs and commitment fees |
|
|
1,003 |
|
|
|
683 |
|
|
|
3,204 |
|
|
|
1,449 |
|
Capitalized interest |
|
|
(13 |
) |
|
|
|
|
|
|
(13 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense third parties |
|
|
5,464 |
|
|
|
1,813 |
|
|
|
10,341 |
|
|
|
3,556 |
|
|
|
|
|
|
|
|
|
|
Affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense on notes payable to Anadarko |
|
|
1,233 |
|
|
|
1,750 |
|
|
|
2,467 |
|
|
|
3,500 |
|
Credit facility commitment fees |
|
|
|
|
|
|
35 |
|
|
|
|
|
|
|
70 |
|
|
|
|
|
|
|
|
|
|
Total interest expense affiliates |
|
|
1,233 |
|
|
|
1,785 |
|
|
|
2,467 |
|
|
|
3,570 |
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
6,697 |
|
|
$ |
3,598 |
|
|
$ |
12,808 |
|
|
$ |
7,126 |
|
|
|
|
|
|
|
|
|
|
20
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
8. COMMITMENTS AND CONTINGENCIES
Litigation and legal proceedings. In March 2011, DCP Midstream LP (DCP) filed a lawsuit against
Anadarko and others, including a Partnership subsidiary, Kerr-McGee Gathering LLC, in Weld County
District Court (the Court) in Colorado, alleging that Anadarko and its affiliates diverted gas
from DCPs gathering and processing facilities in breach of certain dedication agreements. In
addition to various claims against Anadarko, DCP is claiming unjust enrichment and other damages
against Kerr-McGee Gathering LLC, the entity which holds the Wattenberg assets. In April 2011, the
defendants, including the Partnership, moved to dismiss this lawsuit. The motion has been fully
briefed by the parties, but not yet ruled upon by the Court. Management does not believe the
outcome of this proceeding will have a material effect on the Partnerships financial condition,
results of operations or cash flows. The Partnership intends to vigorously defend this litigation.
Furthermore, without regard to the merit of DCPs claims, management believes that the Partnership
has adequate contractual indemnities covering the claims against it in this lawsuit.
In addition, 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 for which a
final disposition could have a material adverse effect on the Partnerships financial condition,
results of operations or cash flows.
Lease commitments. Anadarko, on behalf of the Partnership, has entered into lease agreements for
corporate offices, shared field offices and a warehouse supporting the Partnerships operations.
The lease for the corporate offices expires in January 2012, with no purchase option at
termination, and the leases for the shared offices extend through 2014. The lease for the warehouse
extends through September 2011 and includes an early termination clause. In addition, during 2010,
Anadarko and Kerr-McGee Gathering LLC purchased previously leased compression equipment used at the
Granger and Wattenberg assets, which terminated the leases and associated lease expense. The
purchased compression equipment was contributed to the Partnership pursuant to provisions of the
contribution agreements for the Granger and the Wattenberg acquisitions.
As of June 30, 2011, there was no material change in the existing contractual lease
obligations for the office and warehouse leases from December 31, 2010. Rent expense associated
with these leases and the previously leased compression equipment was approximately $0.5 million
and $0.9 million for the three and six months ended June 30, 2011, respectively, and $2.5 million
and $4.6 million for the three and six months ended June 30, 2010, respectively.
9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS
The Partnership may issue an indeterminate amount of common units and various debt securities
under its effective shelf registration statement on file with the SEC. The Notes are, and any
future debt securities issued under such registration statement may be, guaranteed by the
Subsidiary Guarantors. The guarantees are full, unconditional, joint and several. The following
condensed consolidating financial information reflects the Partnerships stand-alone accounts, the
combined accounts of the Subsidiary Guarantors, the accounts of the Non-Guarantor Subsidiary,
consolidating adjustments, and eliminations and the Partnerships consolidated financial
information. The condensed consolidating financial information should be read in conjunction with
the Partnerships accompanying consolidated financial statements and related notes.
Western Gas Partners, LPs and the Subsidiary Guarantors investment in and equity income from
their consolidated subsidiaries are presented in accordance with the equity method of accounting in
which the equity income from consolidated subsidiaries includes the results of operations of the
Partnership assets for periods including and subsequent to the Partnerships acquisition of the
Partnership assets.
21
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Income |
|
|
Three Months Ended June 30, 2011 |
|
|
Western |
|
|
|
|
|
Non- |
|
|
|
|
|
|
Gas |
|
Subsidiary |
|
Guarantor |
|
|
|
|
thousands |
|
Partners, LP |
|
Guarantors |
|
Subsidiary |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
(1,686 |
) |
|
$ |
148,972 |
|
|
$ |
14,462 |
|
|
$ |
|
|
|
$ |
161,748 |
|
Operating expenses |
|
|
13,405 |
|
|
|
96,645 |
|
|
|
8,673 |
|
|
|
|
|
|
|
118,723 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(15,091 |
) |
|
|
52,327 |
|
|
|
5,789 |
|
|
|
|
|
|
|
43,025 |
|
Interest income affiliates |
|
|
4,215 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
4,225 |
|
Interest expense |
|
|
(6,697 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,697 |
) |
Other income (expense), net |
|
|
(3,685 |
) |
|
|
|
|
|
|
3 |
|
|
|
|
|
|
|
(3,682 |
) |
Equity income from consolidated
subsidiaries |
|
|
55,197 |
|
|
|
2,955 |
|
|
|
|
|
|
|
(58,152 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
33,939 |
|
|
|
55,292 |
|
|
|
5,792 |
|
|
|
(58,152 |
) |
|
|
36,871 |
|
Income tax expense |
|
|
|
|
|
|
94 |
|
|
|
|
|
|
|
|
|
|
|
94 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
33,939 |
|
|
|
55,198 |
|
|
|
5,792 |
|
|
|
(58,152 |
) |
|
|
36,777 |
|
Net income attributable to
noncontrolling interests |
|
|
|
|
|
|
2,838 |
|
|
|
|
|
|
|
|
|
|
|
2,838 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to
Western Gas Partners, LP |
|
$ |
33,939 |
|
|
$ |
52,360 |
|
|
$ |
5,792 |
|
|
$ |
(58,152 |
) |
|
$ |
33,939 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Income |
|
|
Three Months Ended June 30, 2010 |
|
|
Western |
|
|
|
|
|
Non- |
|
|
|
|
|
|
Gas |
|
Subsidiary |
|
Guarantor |
|
|
|
|
thousands |
|
Partners, LP |
|
Guarantors |
|
Subsidiary |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
8,086 |
|
|
$ |
104,798 |
|
|
$ |
12,099 |
|
|
$ |
|
|
|
$ |
124,983 |
|
Operating expenses |
|
|
10,868 |
|
|
|
71,337 |
|
|
|
5,223 |
|
|
|
|
|
|
|
87,428 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(2,782 |
) |
|
|
33,461 |
|
|
|
6,876 |
|
|
|
|
|
|
|
37,555 |
|
Interest income affiliates |
|
|
4,217 |
|
|
|
15 |
|
|
|
|
|
|
|
|
|
|
|
4,232 |
|
Interest expense |
|
|
(3,598 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,598 |
) |
Other income (expense), net |
|
|
(2,395 |
) |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
(2,393 |
) |
Equity income from consolidated
subsidiaries |
|
|
27,969 |
|
|
|
3,508 |
|
|
|
|
|
|
|
(31,477 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
23,411 |
|
|
|
36,984 |
|
|
|
6,878 |
|
|
|
(31,477 |
) |
|
|
35,796 |
|
Income tax expense |
|
|
|
|
|
|
3,419 |
|
|
|
|
|
|
|
|
|
|
|
3,419 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
23,411 |
|
|
|
33,565 |
|
|
|
6,878 |
|
|
|
(31,477 |
) |
|
|
32,377 |
|
Net income attributable to
noncontrolling interests |
|
|
|
|
|
|
3,371 |
|
|
|
|
|
|
|
|
|
|
|
3,371 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to
Western Gas Partners, LP |
|
$ |
23,411 |
|
|
$ |
30,194 |
|
|
$ |
6,878 |
|
|
$ |
(31,477 |
) |
|
$ |
29,006 |
|
|
|
|
|
|
|
|
|
|
|
|
22
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Income |
|
|
Six Months Ended June 30, 2011 |
|
|
Western |
|
|
|
|
|
Non- |
|
|
|
|
|
|
Gas |
|
Subsidiary |
|
Guarantor |
|
|
|
|
thousands |
|
Partners, LP |
|
Guarantors |
|
Subsidiary |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
(719 |
) |
|
$ |
271,205 |
|
|
$ |
27,255 |
|
|
$ |
|
|
|
$ |
297,741 |
|
Operating expenses |
|
|
26,018 |
|
|
|
175,162 |
|
|
|
15,440 |
|
|
|
|
|
|
|
216,620 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(26,737 |
) |
|
|
96,043 |
|
|
|
11,815 |
|
|
|
|
|
|
|
81,121 |
|
Interest
income affiliates |
|
|
8,430 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
8,450 |
|
Interest expense |
|
|
(12,808 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,808 |
) |
Other income (expense), net |
|
|
(1,936 |
) |
|
|
9 |
|
|
|
5 |
|
|
|
|
|
|
|
(1,922 |
) |
Equity income from consolidated
subsidiaries |
|
|
101,974 |
|
|
|
6,029 |
|
|
|
|
|
|
|
(108,003 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
68,923 |
|
|
|
102,101 |
|
|
|
11,820 |
|
|
|
(108,003 |
) |
|
|
74,841 |
|
Income tax expense |
|
|
|
|
|
|
126 |
|
|
|
|
|
|
|
|
|
|
|
126 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
68,923 |
|
|
|
101,975 |
|
|
|
11,820 |
|
|
|
(108,003 |
) |
|
|
74,715 |
|
Net income attributable to
noncontrolling interests |
|
|
|
|
|
|
5,792 |
|
|
|
|
|
|
|
|
|
|
|
5,792 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to
Western Gas Partners, LP |
|
$ |
68,923 |
|
|
$ |
96,183 |
|
|
$ |
11,820 |
|
|
$ |
(108,003 |
) |
|
$ |
68,923 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Income |
|
|
Six Months Ended June 30, 2010 |
|
|
Western |
|
|
|
|
|
Non- |
|
|
|
|
|
|
Gas |
|
Subsidiary |
|
Guarantor |
|
|
|
|
thousands |
|
Partners, LP |
|
Guarantors |
|
Subsidiary |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
6,160 |
|
|
$ |
225,573 |
|
|
$ |
22,186 |
|
|
$ |
|
|
|
$ |
253,919 |
|
Operating expenses |
|
|
14,910 |
|
|
|
152,842 |
|
|
|
11,446 |
|
|
|
|
|
|
|
179,198 |
|
|
|
|
|
|
|
|
|
|
|
|
Operating income (loss) |
|
|
(8,750 |
) |
|
|
72,731 |
|
|
|
10,740 |
|
|
|
|
|
|
|
74,721 |
|
Interest
income affiliates |
|
|
8,436 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
8,462 |
|
Interest expense |
|
|
(7,126 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,126 |
) |
Other income (expense), net |
|
|
(2,377 |
) |
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
(2,373 |
) |
Equity income from consolidated
subsidiaries |
|
|
57,361 |
|
|
|
5,480 |
|
|
|
|
|
|
|
(62,841 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
47,544 |
|
|
|
78,237 |
|
|
|
10,744 |
|
|
|
(62,841 |
) |
|
|
73,684 |
|
Income tax expense |
|
|
|
|
|
|
8,975 |
|
|
|
|
|
|
|
|
|
|
|
8,975 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
47,544 |
|
|
|
69,262 |
|
|
|
10,744 |
|
|
|
(62,841 |
) |
|
|
64,709 |
|
Net income attributable to
noncontrolling interests |
|
|
|
|
|
|
5,265 |
|
|
|
|
|
|
|
|
|
|
|
5,265 |
|
|
|
|
|
|
|
|
|
|
|
|
Net income attributable to
Western Gas Partners, LP |
|
$ |
47,544 |
|
|
$ |
63,997 |
|
|
$ |
10,744 |
|
|
$ |
(62,841 |
) |
|
$ |
59,444 |
|
|
|
|
|
|
|
|
|
|
|
|
23
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
June 30, 2011 |
|
|
Western |
|
|
|
|
|
Non- |
|
|
|
|
|
|
Gas |
|
Subsidiary |
|
Guarantor |
|
|
|
|
thousands |
|
Partners, LP |
|
Guarantors |
|
Subsidiary |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
51,027 |
|
|
$ |
21,782 |
|
|
$ |
21,691 |
|
|
$ |
|
|
|
$ |
94,500 |
|
Note
receivable Anadarko |
|
|
260,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
260,000 |
|
Investment in consolidated
subsidiaries |
|
|
1,140,545 |
|
|
|
104,787 |
|
|
|
|
|
|
|
(1,245,332 |
) |
|
|
|
|
Net property, plant and equipment |
|
|
137 |
|
|
|
1,430,883 |
|
|
|
187,676 |
|
|
|
|
|
|
|
1,618,696 |
|
Other long-term assets |
|
|
9,017 |
|
|
|
155,008 |
|
|
|
|
|
|
|
|
|
|
|
164,025 |
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,460,726 |
|
|
$ |
1,712,460 |
|
|
$ |
209,367 |
|
|
$ |
(1,245,332 |
) |
|
$ |
2,137,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
4,181 |
|
|
$ |
47,963 |
|
|
$ |
6,475 |
|
|
$ |
|
|
|
$ |
58,619 |
|
Long-term debt |
|
|
668,946 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
668,946 |
|
Other long-term liabilities |
|
|
62 |
|
|
|
59,434 |
|
|
|
2,018 |
|
|
|
|
|
|
|
61,514 |
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
673,189 |
|
|
|
107,397 |
|
|
|
8,493 |
|
|
|
|
|
|
|
789,079 |
|
Partners capital |
|
|
787,537 |
|
|
|
1,508,915 |
|
|
|
200,874 |
|
|
|
(1,245,332 |
) |
|
|
1,251,994 |
|
Noncontrolling interests |
|
|
|
|
|
|
96,148 |
|
|
|
|
|
|
|
|
|
|
|
96,148 |
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities, equity
and partners capital |
|
$ |
1,460,726 |
|
|
$ |
1,712,460 |
|
|
$ |
209,367 |
|
|
$ |
(1,245,332 |
) |
|
$ |
2,137,221 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance Sheet |
|
|
December 31, 2010 |
|
|
Western |
|
|
|
|
|
Non- |
|
|
|
|
|
|
Gas |
|
Subsidiary |
|
Guarantor |
|
|
|
|
thousands |
|
Partners, LP |
|
Guarantors |
|
Subsidiary |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
24,972 |
|
|
$ |
208,208 |
|
|
$ |
10,346 |
|
|
$ |
(200,342 |
) |
|
$ |
43,184 |
|
Note
receivable Anadarko |
|
|
260,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
260,000 |
|
Investment in consolidated
subsidiaries |
|
|
1,052,073 |
|
|
|
97,018 |
|
|
|
|
|
|
|
(1,149,091 |
) |
|
|
|
|
Net property, plant and equipment |
|
|
165 |
|
|
|
1,177,971 |
|
|
|
181,214 |
|
|
|
|
|
|
|
1,359,350 |
|
Other long-term assets |
|
|
2,361 |
|
|
|
100,642 |
|
|
|
|
|
|
|
|
|
|
|
103,003 |
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
1,339,571 |
|
|
$ |
1,583,839 |
|
|
$ |
191,560 |
|
|
$ |
(1,349,433 |
) |
|
$ |
1,765,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
$ |
201,989 |
|
|
$ |
38,420 |
|
|
$ |
2,127 |
|
|
$ |
(200,342 |
) |
|
$ |
42,194 |
|
Long-term debt |
|
|
474,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
474,000 |
|
Other long-term liabilities |
|
|
38 |
|
|
|
42,283 |
|
|
|
1,954 |
|
|
|
|
|
|
|
44,275 |
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
676,027 |
|
|
|
80,703 |
|
|
|
4,081 |
|
|
|
(200,342 |
) |
|
|
560,469 |
|
Partners capital |
|
|
663,544 |
|
|
|
1,412,674 |
|
|
|
187,479 |
|
|
|
(1,149,091 |
) |
|
|
1,114,606 |
|
Noncontrolling interests |
|
|
|
|
|
|
90,462 |
|
|
|
|
|
|
|
|
|
|
|
90,462 |
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities, equity
and partners capital |
|
$ |
1,339,571 |
|
|
$ |
1,583,839 |
|
|
$ |
191,560 |
|
|
$ |
(1,349,433 |
) |
|
$ |
1,765,537 |
|
|
|
|
|
|
|
|
|
|
|
|
24
WESTERN GAS PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
9. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS (CONTINUED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flows |
|
|
Six Months Ended June 30, 2011 |
|
|
Western |
|
|
|
|
|
Non- |
|
|
|
|
|
|
Gas |
|
Subsidiary |
|
Guarantor |
|
|
|
|
thousands |
|
Partners, LP |
|
Guarantors |
|
Subsidiary |
|
Eliminations |
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
68,923 |
|
|
$ |
101,975 |
|
|
$ |
11,820 |
|
|
$ |
(108,003 |
) |
|
$ |
74,715 |
|
Adjustments to reconcile net income to
net cash provided by operating
activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity income from consolidated
subsidiaries |
|
|
(101,974 |
) |
|
|
(6,029 |
) |
|
|
|
|
|
|
108,003 |
|
|
|
|
|
Depreciation, amortization and
impairments |
|
|
27 |
|
|
|
38,365 |
|
|
|
2,877 |
|
|
|
|
|
|
|
41,269 |
|
Change in other items, net |
|
|
(196,478 |
) |
|
|
195,113 |
|
|
|
(1,266 |
) |
|
|
|
|
|
|
(2,631 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
(used in) operating activities |
|
|
(229,502 |
) |
|
|
329,424 |
|
|
|
13,431 |
|
|
|
|
|
|
|
113,353 |
|
Net cash used in investing activities |
|
|
|
|
|
|
(335,333 |
) |
|
|
(5,767 |
) |
|
|
7,691 |
|
|
|
(333,409 |
) |
Net cash provided by
(used in) financing activities |
|
|
255,886 |
|
|
|
5,909 |
|
|
|
1,573 |
|
|
|
(7,691 |
) |
|
|
255,677 |
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash
equivalents |
|
|
26,384 |
|
|
|
|
|
|
|
9,237 |
|
|
|
|
|
|
|
35,621 |
|
Cash and cash equivalents
at beginning of period |
|
|
21,480 |
|
|
|
|
|
|
|
5,594 |
|
|
|
|
|
|
|
27,074 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
47,864 |
|
|
$ |
|
|
|
$ |
14,831 |
|
|
$ |
|
|
|
$ |
62,695 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statement of Cash Flows |
|
|
Six Months Ended June 30, 2010 |
|
|
Western |
|
|
|
|
|
Non- |
|
|
|
|
|
|
|
Gas |
|
Subsidiary |
|
Guarantor |
|
|
|
|
thousands |
|
Partners, LP |
|
|
Guarantors |
|
|
Subsidiary |
|
|
Eliminations |
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
47,544 |
|
|
$ |
69,262 |
|
|
$ |
10,744 |
|
|
$ |
(62,841 |
) |
|
$ |
64,709 |
|
Adjustments to reconcile net income to
net cash provided by operating
activities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity income from consolidated
subsidiaries |
|
|
(57,361 |
) |
|
|
(5,480 |
) |
|
|
|
|
|
|
62,841 |
|
|
|
|
|
Depreciation, amortization and
impairments |
|
|
27 |
|
|
|
32,436 |
|
|
|
2,869 |
|
|
|
|
|
|
|
35,332 |
|
Change in other items, net |
|
|
82,245 |
|
|
|
(79,097 |
) |
|
|
(3,463 |
) |
|
|
|
|
|
|
(315 |
) |
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
72,455 |
|
|
|
17,121 |
|
|
|
10,150 |
|
|
|
|
|
|
|
99,726 |
|
Net cash used in investing activities |
|
|
(241,680 |
) |
|
|
(48,759 |
) |
|
|
(1,740 |
) |
|
|
|
|
|
|
(292,179 |
) |
Net cash provided by
(used in) financing activities |
|
|
166,136 |
|
|
|
31,638 |
|
|
|
(10,903 |
) |
|
|
|
|
|
|
186,871 |
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
|
(3,089 |
) |
|
|
|
|
|
|
(2,493 |
) |
|
|
|
|
|
|
(5,582 |
) |
Cash and cash equivalents
at beginning of period |
|
|
61,632 |
|
|
|
|
|
|
|
8,352 |
|
|
|
|
|
|
|
69,984 |
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at end of period |
|
$ |
58,543 |
|
|
$ |
|
|
|
$ |
5,859 |
|
|
$ |
|
|
|
$ |
64,402 |
|
|
|
|
|
|
|
|
|
|
|
|
25
Item 2. Managements 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 in Part
I, Item 8 of our 2010 annual report on Form 10-K as filed with the Securities and Exchange
Commission, or SEC, on February 24, 2011. Unless the context otherwise requires, references to
we, us, our, the Partnership or Western Gas Partners refers to Western Gas Partners, LP
and its subsidiaries, including the financial results of the Partnership assets (described below)
from their respective acquisition dates, combined with the financial results and operations of the
Wattenberg assets (defined in Acquisitions) and 0.4% interest in White Cliffs (defined below) for
all periods presented. For ease of reference, we refer to the historical financial results of the
Partnership assets prior to our acquisitions as being our historical financial results.
Anadarko or Parent refers to Anadarko Petroleum Corporation and its consolidated subsidiaries,
excluding the Partnership and the general partner. Our general partner refers to Western Gas
Holdings, LLC, a wholly owned subsidiary of Anadarko and the general partner of the Partnership.
Affiliates refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the
Partnership, and also refers to Fort Union Gas Gathering, L.L.C., or Fort Union, and White Cliffs
Pipeline, L.L.C., or White Cliffs. References to the Partnership assets refer collectively to
the assets owned by the Partnership as of June 30, 2011.
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
We have made in this report, and may from time to time otherwise make in other public filings,
press releases and discussions by Partnership management, forward-looking statements concerning our
operations, economic performance and financial condition. These statements can be identified by the
use of forward-looking terminology including may, will, believe, expect, anticipate,
estimate, continue, or other similar words. These statements discuss future expectations,
contain projections of results of operations or financial condition or include other
forward-looking information. Although we believe that the expectations reflected in such
forward-looking statements are reasonable, we can give no 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 risks and uncertainties:
|
|
|
our assumptions about the energy market; |
|
|
|
|
future throughput, including Anadarkos production, which is gathered or processed by or
transported through our assets; |
|
|
|
|
operating results; |
|
|
|
|
competitive conditions; |
|
|
|
|
technology; |
|
|
|
|
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 and demand for, and the prices of, oil, natural gas, NGLs and other
products or services; |
|
|
|
|
the weather; |
|
|
|
|
inflation; |
|
|
|
|
the availability of goods and services; |
|
|
|
|
general economic conditions, either internationally, nationally or within the
jurisdictions in which we are doing business; |
26
|
|
|
changes in environmental and safety regulation; environmental risks; regulations by the
Federal Energy Regulatory Commission, or FERC; and liability under federal and state laws
and regulations; |
|
|
|
|
legislative or regulatory changes affecting our status as a partnership for federal
income tax purposes; |
|
|
|
|
changes in the financial or operational condition of our sponsor, Anadarko, including
changes as a result of the outcome of the Deepwater Horizon events; |
|
|
|
|
changes in Anadarkos capital program, strategy or desired areas of focus; |
|
|
|
|
our commitments to capital projects; |
|
|
|
|
the ability to utilize our revolving credit facility; |
|
|
|
|
the creditworthiness of Anadarko or our other counterparties, including financial
institutions, operating partners, and other parties; |
|
|
|
|
our ability to repay debt; |
|
|
|
|
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; |
|
|
|
|
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; and |
|
|
|
|
other factors discussed below and elsewhere in Risk Factors under Part I, Item 1A in
our 2010 annual report on Form 10-K, and in Managements Discussion and Analysis of
Financial Condition and Results of OperationsCritical Accounting Policies and Estimates
under Part II, Item 7 included in our 2010 annual report on Form 10-K, 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
report could cause our 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.
27
EXECUTIVE SUMMARY
We are a growth-oriented limited partnership organized by Anadarko to own, operate, acquire
and develop midstream energy assets. We currently operate in East and West Texas, the Rocky
Mountains (Colorado, Utah and Wyoming) and the Mid-Continent (Kansas and Oklahoma) and are engaged
primarily in the business of gathering, processing, compressing, treating and transporting natural
gas, condensate, NGLs and crude oil for Anadarko and third-party producers and customers. As of
June 30, 2011, our assets consist of eleven gathering systems, six natural gas treating facilities,
seven natural gas processing facilities, one NGL pipeline, one interstate pipeline, and interests
in a gas gathering system and a crude oil pipeline accounted for under the equity method.
Significant financial and operational highlights during the first six months of 2011 include
the following:
|
|
|
In February 2011, we acquired the Platte Valley gathering system and processing plant
from a third party for $303.6 million, funded primarily by borrowings under our revolving
credit facility. These assets are located in the Denver-Julesburg basin and consist of a
cryogenic processing plant, two fractionation trains and a natural gas gathering system. |
|
|
|
|
In March 2011, we issued 3,852,813 common units to the public, generating net proceeds of
$132.6 million, including the general partners proportionate capital contributions to
maintain its 2.0% general partner interest. Net proceeds from this offering were used
primarily to repay amounts outstanding under our revolving credit facility. |
|
|
|
|
In March 2011, we entered into an amended and restated $800.0 million senior unsecured
revolving credit facility to amend and restate the $450.0 million credit facility originally
entered into in October 2009. Refer to Liquidity and Capital Resources for additional
information. |
|
|
|
|
In May 2011, we issued $500.0 million aggregate principal amount of 5.375% Senior Notes
due 2021. Net proceeds from this issuance were used primarily to repay amounts outstanding
under our revolving credit facility. Refer to Liquidity and Capital Resources for additional
information. |
|
|
|
|
Our stable operating cash flow, combined with a focus on cost reduction and capital
spending discipline, enabled us to raise our distribution to $0.405 per unit for the second
quarter of 2011, representing a 4% increase over the distribution for the first quarter of
2011 and our ninth consecutive quarterly increase. |
|
|
|
|
Gross margin (total revenues less cost of product) attributable to Western Gas Partners,
LP for the three months ended June 30, 2011, averaged $0.67 per Mcf, representing a 22%
increase compared to the three months ended June 30, 2010, and averaged $0.65 per Mcf for
the six months ended June 30, 2011, representing an 18% increase compared to the six months
ended June 30, 2010. The increase in gross margin per Mcf is primarily due to the addition
of the Platte Valley system, the increase in ownership of the White Cliffs investment (as
defined in Acquisitions) and growth in higher-margin areas, which offset the impact of the
expiration of lower-margin contracts. The predominantly fee-based and fixed-price structure
of our contracts mitigated the impact of changes in commodity prices on our gross margin. |
|
|
|
|
Throughput attributable to Western Gas Partners, LP totaled 1,555 MMcf/d and 1,531 MMcf/d
for the three and six months ended June 30, 2011, respectively, representing a 5% and 7%
decrease, respectively, compared to the same periods in 2010. The throughput decrease is
primarily due to lower volumes at the MIGC and Fort Union systems
following the startup of the Bison pipeline,
and lower volumes at the Haley, Pinnacle, Dew and Hugoton systems due to natural
production declines and low drilling activity. These declines were partially offset by
increased throughput at the Granger, Chipeta and Wattenberg systems resulting from drilling
activity in these areas driven by favorable producer economics, and the additional
throughput attributable to the Platte Valley system acquired in 2011. |
28
ACQUISITIONS
Acquisitions. The following table presents our acquisitions completed during 2010 and 2011, and
details the funding for those acquisitions through borrowings, cash
on hand and/or the issuance of
equity:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands except unit and |
|
Acquisition |
|
Percentage |
|
|
|
|
|
Cash |
|
Common |
|
GP Units |
percent amounts |
|
Date |
|
Acquired |
|
Borrowings |
|
|
On Hand |
|
|
Units Issued |
|
|
Issued |
|
Granger (1) |
|
|
01/29/10 |
|
|
|
100 |
% |
|
$ |
210,000 |
|
|
$ |
31,680 |
|
|
|
620,689 |
|
|
|
12,667 |
|
Wattenberg (2) |
|
|
08/02/10 |
|
|
|
100 |
% |
|
|
450,000 |
|
|
|
23,100 |
|
|
|
1,048,196 |
|
|
|
21,392 |
|
White Cliffs (3) |
|
|
09/28/10 |
|
|
|
10 |
% |
|
|
|
|
|
|
38,047 |
|
|
|
|
|
|
|
|
|
Platte Valley (4) |
|
|
02/28/11 |
|
|
|
100 |
% |
|
|
303,000 |
|
|
|
602 |
|
|
|
|
|
|
|
|
|
Bison (5) |
|
|
07/08/11 |
|
|
|
100 |
% |
|
|
|
|
|
|
25,000 |
|
|
|
2,950,284 |
|
|
|
60,210 |
|
|
|
|
(1) |
|
The assets acquired from Anadarko include (i) the Granger gathering system, a
750-mile gathering system with related compressors and other facilities, and (ii) the Granger
complex, consisting of two cryogenic trains with combined capacity of 200 MMcf/d, a
refrigeration train with capacity of 100 MMcf/d, an NGLs fractionation facility with capacity
of 9,500 barrels per day, and ancillary equipment. These assets, located in southwestern
Wyoming, are referred to collectively as the Granger assets or Granger system and the
acquisition as the Granger acquisition. In connection with the acquisition, we entered into
a ten-year fee-based arrangement covering a majority of the Granger assets affiliate
throughput and five-year, fixed-price commodity swap agreements with Anadarko, which cover
non-fee-based volumes processed at the Granger complex. |
|
(2) |
|
The assets acquired from Anadarko include the Wattenberg gathering system and
related facilities, including the Fort Lupton processing plant. These assets, located in the
Denver-Julesburg Basin, north and east of Denver, Colorado, are referred to collectively as
the Wattenberg assets or Wattenberg system and the acquisition as the Wattenberg
acquisition. In connection with the acquisition, we entered into a ten-year fee-based
arrangement covering all of the Wattenberg assets affiliate throughput and five-year,
fixed-price commodity swap agreements with Anadarko, which fix the margin we will realize from
the purchase and sale of natural gas, condensate or NGLs at the Wattenberg assets. |
|
(3) |
|
White Cliffs owns a crude oil pipeline that originates in Platteville, Colorado and
terminates in Cushing, Oklahoma and that became operational in June 2009. Our acquisition of
the 0.4% interest in White Cliffs and related purchase option from Anadarko combined with the
acquisition of an additional 9.6% interest in White Cliffs from
a third party, are referred to collectively as the
White Cliffs acquisition. Our interest in White Cliffs is referred to as the White Cliffs
investment. |
|
(4) |
|
The assets acquired from a third party include (i) a processing plant with cryogenic
capacity of 84 MMcf/d, (ii) two fractionation trains, (iii) a 1,098 mile natural gas gathering
system that delivers gas to the Platte Valley plant, either directly or through our Wattenberg
gathering system, and (iv) related equipment. These assets, located in the Denver-Julesburg
Basin, are referred to collectively as the Platte Valley assets or Platte Valley system
and the acquisition as the Platte Valley acquisition. In connection with the acquisition, we
entered into long-term fee-based agreements with the seller to gather and process its existing
gas production, as well as to expand the existing gathering systems and processing capacity.
We financed the Platte Valley acquisition with borrowings under our revolving credit facility. |
|
(5) |
|
Subsequent to June 30, 2011, we acquired Anadarkos Bison gas treating facility and
related assets located in the Powder River Basin in northeastern Wyoming, including (i) three
amine treating units with a combined CO2 treating capacity of 450 MMcf/d, (ii) three
compressor units with combined compression of 5,230 horsepower, and (iii) five generators with
combined power output of 6.5 megawatts. These assets are referred to collectively as the
Bison assets and the acquisition as the Bison acquisition. |
29
Presentation of Partnership acquisitions. References to the Partnership assets refer
collectively to the assets owned by the Partnership as of June 30, 2011. Because of Anadarkos
control of the Partnership through its ownership of our general partner, each acquisition of
Partnership assets, except for the acquisitions of the Platte Valley assets and the 9.6% interest
in White Cliffs from third parties, was considered a transfer of net assets between entities under
common control. Accordingly, our consolidated financial statements include the financial results
and operations of the Partnership assets since the date of common control. Anadarko acquired the
Wattenberg assets in connection with its August 10, 2006, acquisition of Kerr-McGee Corporation and
made its initial investment in White Cliffs on January 29, 2007.
Our historical financial statements for the three and six months ended June 30, 2010, as
presented in our second quarter 2010 Form 10-Q as filed with the SEC on August 5, 2010, have been
recast in this quarterly report on Form 10-Q to include the results attributable to the Wattenberg
assets and the 0.4% interest in White Cliffs as if we owned such assets for all periods presented.
Unless otherwise noted, references to periods prior to our acquisition of the Partnership assets
and similar phrases refer to periods prior to July 2010 with respect to the Wattenberg assets and
periods prior to September 2010 with respect to the White Cliffs investment. Reference to periods
including and subsequent to our acquisition of the Partnership assets and similar phrases refer to
periods including and subsequent to July 2010 with respect to the Wattenberg assets and periods
including and subsequent to September 2010 with respect to the White Cliffs investment. In
addition, certain amounts in prior periods have been reclassified to conform to the current
presentation. Our noncontrolling interests represent the aggregate 49% interest in Chipeta
Processing LLC (Chipeta) held by Anadarko and a third party.
EQUITY OFFERINGS
Equity offerings. We completed the following public equity offerings during 2010 and 2011:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Underwriting |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount and |
|
|
|
|
thousands except unit |
|
Common |
|
|
GP Units |
|
|
Price Per |
|
|
Other Offering |
|
|
Net |
|
and per-unit amounts |
|
Units Issued (2) |
|
|
Issued (3) |
|
|
Unit |
|
|
Expenses |
|
|
Proceeds (4) |
|
May 2010 equity offering (1) |
|
|
4,558,700 |
|
|
|
93,035 |
|
|
$ |
22.25 |
|
|
$ |
4,427 |
|
|
$ |
99,074 |
|
November 2010 equity offering |
|
|
8,415,000 |
|
|
|
171,734 |
|
|
|
29.92 |
|
|
|
10,279 |
|
|
|
246,729 |
|
March 2011 equity offering |
|
|
3,852,813 |
|
|
|
78,629 |
|
|
|
35.15 |
|
|
|
5,621 |
|
|
|
132,569 |
|
|
|
|
(1) |
|
The May 2010 equity offering refers collectively to the May 2010
equity offering issuance, and the June 2010 exercise of the
underwriters over-allotment option. |
|
(2) |
|
Common units issued includes the issuance of 558,700 common units, 915,000 common
units and 302,813 common units pursuant to the exercise, in full or in part, of the
underwriters over-allotment options granted in connection with the May 2010, November 2010
and March 2011 equity offerings, respectively. |
|
(3) |
|
GP units issued represent general partner units issued to the general partner in
exchange for the general partners proportionate capital contribution to maintain its 2.0%
interest. |
|
(4) |
|
Net proceeds were primarily used to repay amounts outstanding under our revolving
credit facility. |
30
RESULTS OF OPERATIONS
OPERATING RESULTS
The following tables and discussion present a summary of our results of operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
Revenues (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering, processing and transportation of natural gas and
natural gas liquids |
|
$ |
67,509 |
|
|
$ |
55,491 |
|
|
$ |
128,639 |
|
|
$ |
112,406 |
|
Natural gas, natural gas liquids and condensate sales |
|
|
90,557 |
|
|
|
67,033 |
|
|
|
161,962 |
|
|
|
136,905 |
|
Equity income and other, net |
|
|
3,682 |
|
|
|
2,459 |
|
|
|
7,140 |
|
|
|
4,608 |
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
161,748 |
|
|
|
124,983 |
|
|
|
297,741 |
|
|
|
253,919 |
|
|
|
|
|
|
|
|
|
|
Operating expenses (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product |
|
|
62,317 |
|
|
|
38,506 |
|
|
|
109,137 |
|
|
|
80,479 |
|
Operation and maintenance |
|
|
23,639 |
|
|
|
22,205 |
|
|
|
44,501 |
|
|
|
44,596 |
|
General and administrative |
|
|
7,082 |
|
|
|
5,455 |
|
|
|
13,780 |
|
|
|
11,523 |
|
Property and other taxes |
|
|
3,974 |
|
|
|
3,649 |
|
|
|
7,933 |
|
|
|
7,268 |
|
Depreciation, amortization and impairments |
|
|
21,711 |
|
|
|
17,613 |
|
|
|
41,269 |
|
|
|
35,332 |
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
118,723 |
|
|
|
87,428 |
|
|
|
216,620 |
|
|
|
179,198 |
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
43,025 |
|
|
|
37,555 |
|
|
|
81,121 |
|
|
|
74,721 |
|
Interest
income affiliates |
|
|
4,225 |
|
|
|
4,232 |
|
|
|
8,450 |
|
|
|
8,462 |
|
Interest expense |
|
|
(6,697 |
) |
|
|
(3,598 |
) |
|
|
(12,808 |
) |
|
|
(7,126 |
) |
Other expense, net |
|
|
(3,682 |
) |
|
|
(2,393 |
) |
|
|
(1,922 |
) |
|
|
(2,373 |
) |
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
36,871 |
|
|
|
35,796 |
|
|
|
74,841 |
|
|
|
73,684 |
|
Income tax expense |
|
|
94 |
|
|
|
3,419 |
|
|
|
126 |
|
|
|
8,975 |
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
36,777 |
|
|
|
32,377 |
|
|
|
74,715 |
|
|
|
64,709 |
|
Net income attributable to noncontrolling interests |
|
|
2,838 |
|
|
|
3,371 |
|
|
|
5,792 |
|
|
|
5,265 |
|
|
|
|
|
|
|
|
|
|
Net income attributable to Western Gas Partners, LP |
|
$ |
33,939 |
|
|
$ |
29,006 |
|
|
$ |
68,923 |
|
|
$ |
59,444 |
|
|
|
|
|
|
|
|
|
|
Key Performance Metrics (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross margin |
|
$ |
99,431 |
|
|
$ |
86,477 |
|
|
$ |
188,604 |
|
|
$ |
173,440 |
|
Adjusted EBITDA attributable to Western Gas Partners, LP |
|
$ |
63,479 |
|
|
$ |
51,552 |
|
|
$ |
119,793 |
|
|
$ |
104,182 |
|
Distributable cash flow |
|
$ |
56,619 |
|
|
$ |
46,901 |
|
|
$ |
106,345 |
|
|
$ |
94,739 |
|
|
|
|
(1) |
|
Revenues include affiliate amounts earned by the Partnership from services
provided to our affiliates, as well as from sale of residue gas, condensate 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 4.
Transactions with Affiliates in the Notes to Consolidated Financial Statements under Part I,
Item 1 of this Form 10-Q. |
|
(2) |
|
Gross margin, Adjusted EBITDA attributable to Western Gas Partners, LP (Adjusted
EBITDA) and Distributable cash flow are defined under the caption Operating results within
this Item 2. Such caption also includes reconciliations of Adjusted EBITDA and Distributable
cash flow to their most directly comparable measures calculated and presented in accordance
with generally accepted accounting principles (GAAP). |
31
For purposes of the following discussion, any increases or decreases for the three
months ended June 30, 2011 refer to the comparison of the three months ended June 30, 2011, to the
three months ended June 30, 2010, any increases or decreases for the six months ended June 30,
2011 refer to the comparison of the six months ended June 30, 2011, to the six months ended June
30, 2010, and any increases or decreases for the three and six months ended June 30, 2011 refer
to both the comparison for the three months ended June 30, 2011, and to the comparison for the six
months ended June 30, 2011.
Operating Statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
MMcf/d except percentages |
|
2011 |
|
2010 |
|
Δ |
|
|
2011 |
|
2010 |
|
Δ |
|
Gathering and transportation
throughput (1) |
|
|
884 |
|
|
|
1,059 |
|
|
|
(17)% |
|
|
|
893 |
|
|
|
1,068 |
|
|
|
(16)% |
|
Processing throughput (2) |
|
|
851 |
|
|
|
664 |
|
|
|
28% |
|
|
|
800 |
|
|
|
649 |
|
|
|
23% |
|
Equity investment throughput (3) |
|
|
54 |
|
|
|
114 |
|
|
|
(53)% |
|
|
|
64 |
|
|
|
118 |
|
|
|
(46)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput (4) |
|
|
1,789 |
|
|
|
1,837 |
|
|
|
(3)% |
|
|
|
1,757 |
|
|
|
1,835 |
|
|
|
(4)% |
|
Throughput attributable to
noncontrolling interests |
|
|
234 |
|
|
|
198 |
|
|
|
18% |
|
|
|
226 |
|
|
|
194 |
|
|
|
16% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total throughput attributable to
Western Gas Partners, LP |
|
|
1,555 |
|
|
|
1,639 |
|
|
|
(5)% |
|
|
|
1,531 |
|
|
|
1,641 |
|
|
|
(7)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Excludes average NGL pipeline volumes of 23 MBbls/d and 16 MBbls/d, for the
three months ended June 30, 2011 and 2010, respectively, and 22 MBbls/d and 16 MBbls/d, for
the six months ended June 30, 2011 and 2010, respectively. |
|
(2) |
|
Consists of 100% of Chipeta, Granger and Hilight system volumes and 50% of Newcastle
system volumes for all periods presented as well as throughput beginning March 2011
attributable to the Platte Valley system. |
|
(3) |
|
Represents our 14.81% share of Fort Unions gross volumes and excludes crude oil
throughput measured in barrels attributable to White Cliffs. |
|
(4) |
|
Includes affiliate, third-party and equity-investment volumes. |
Gathering and transportation throughput decreased by 175 MMcf/d for both the three and
six months ended June 30, 2011, primarily due to lower throughput at the MIGC system resulting from
the January 2011 expiration of certain contracts which were not renewed due to the start up of the
Bison pipeline, and throughput decreases at the Haley, Pinnacle, Dew and Hugoton systems resulting
from natural production declines and reduced drilling activity in those areas. These declines were
partially offset by throughput increases at the Wattenberg system due to increased drilling
activity in the area.
Processing throughput increased by 187 MMcf/d and 151 MMcf/d for the three and six months
ended June 30, 2011, respectively, primarily due to the additional throughput from the Platte
Valley system acquired in February 2011, as well as throughput increases at the Chipeta, Granger
and Hilight systems, resulting from drilling activity in these areas driven by the relatively high
liquid content of the gas volumes produced.
Equity investment volumes decreased by 60 MMcf/d and by 54 MMcf/d for the three and six months
ended June 30, 2011, respectively, due to lower throughput at the Fort Union system following the
start up of the Bison pipeline.
32
Natural Gas Gathering, Processing and Transportation Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
thousands except percentages |
|
2011 |
|
|
2010 |
|
|
Δ |
|
|
2011 |
|
|
2010 |
|
|
Δ |
|
Gathering, processing and transportation
of natural gas and natural gas liquids |
|
$ |
67,509 |
|
|
$ |
55,491 |
|
|
|
22% |
|
|
$ |
128,639 |
|
|
$ |
112,406 |
|
|
|
14% |
|
Gathering, processing and transportation of natural gas and natural gas liquids revenues
increased by $12.0 million and $16.2 million for the three and six months ended June 30, 2011,
respectively, due to the acquisition of the Platte Valley system, increased fee revenue at the
Wattenberg system as a result of changes in affiliate contract terms (from primarily keep-whole and
percentage-of-proceeds arrangements to fee-based arrangements)
effective July 2010, and increased
throughput at the Chipeta system due to additional drilling activity. These increases were
partially offset by decreased fee revenue at the MIGC, Haley, Hugoton and Dew systems
resulting from decreased throughput.
Natural Gas, Natural Gas Liquids and Condensate Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
thousands except percentages and |
|
June 30, |
|
|
June 30, |
|
per-unit amounts |
|
2011 |
|
2010 |
|
Δ |
|
|
2011 |
|
2010 |
|
Δ |
|
Natural gas sales |
|
$ |
29,259 |
|
|
$ |
14,876 |
|
|
|
97% |
|
|
$ |
49,689 |
|
|
$ |
29,588 |
|
|
|
68% |
|
Natural gas liquids sales |
|
|
52,494 |
|
|
|
44,701 |
|
|
|
17% |
|
|
|
95,216 |
|
|
|
89,671 |
|
|
|
6% |
|
Drip condensate sales |
|
|
8,804 |
|
|
|
7,456 |
|
|
|
18% |
|
|
|
17,057 |
|
|
|
17,646 |
|
|
|
(3)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
90,557 |
|
|
$ |
67,033 |
|
|
|
35% |
|
|
$ |
161,962 |
|
|
$ |
136,905 |
|
|
|
18% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average price per unit: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
|
$ |
5.91 |
|
|
$ |
5.70 |
|
|
|
4% |
|
|
$ |
5.86 |
|
|
$ |
5.60 |
|
|
|
5% |
|
Natural gas liquids (per Bbl) |
|
$ |
44.72 |
|
|
$ |
43.14 |
|
|
|
4% |
|
|
$ |
46.20 |
|
|
$ |
40.24 |
|
|
|
15% |
|
Drip condensate (per Bbl) |
|
$ |
74.00 |
|
|
$ |
71.70 |
|
|
|
3% |
|
|
$ |
73.53 |
|
|
$ |
71.47 |
|
|
|
3% |
|
Including
the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $23.5 million for the
three months ended June 30, 2011, which
consisted of a $14.4 million increase in natural gas sales, a $7.8 million increase in NGLs sales
and a $1.3 million increase in drip condensate sales.
For the three months ended June 30, 2011, natural gas sales increased due to an 88% increase
in the volume of natural gas sold and NGLs sales increased due to a 10% increase in the volume of
NGLs sold as a result of higher throughput at the Granger and Hilight systems, as well as the
acquisition of the Platte Valley system. Increases are also attributable to 4% increases in both
natural gas and NGLs sales prices. The increase in drip condensate sales for the three months ended
June 30, 2011, was primarily due to an increase in the average sales prices at the Hugoton and
Wattenberg systems along with Platte Valley sales beginning March 2011, partially offset by a
decrease in the volume of condensate sold.
Including
the effects of commodity price swap agreements, total natural gas, natural gas liquids and condensate sales increased by $25.1 million for the
six months ended June 30, 2011, which
consisted of a $20.1 million increase in natural gas sales and a $5.5 million increase in NGLs
sales, partially offset by a $0.6 million decrease in drip condensate sales.
The increase in natural gas sales was due to a 60% increase in the volume of natural gas sold
and a 5% increase in the average price. The increase in NGLs sales was primarily due to a 15%
increase in average price, partially offset by a 7% decrease in volumes sold attributable to the
decrease in volumes sold at the Wattenberg system as a result of changes in affiliate contract
terms (from primarily keep-whole and percentage-of-proceeds arrangements to fee-based arrangements,
whereby the producer takes product in kind) effective July 2010. The decrease in drip condensate
sales for the six months ended June 30, 2011, was primarily due to a decrease in the volume of
condensate sold, partially offset by higher average sales price at the Hugoton system and Platte
Valley sales beginning March 2011.
33
The average natural gas and NGLs prices for the three and six months ended June 30, 2011,
include the effects of commodity price swap agreements attributable to sales for the Granger,
Wattenberg, Hilight, Newcastle and Hugoton systems. The average natural gas and NGLs prices for the
three and six months ended June 30, 2010, include the effects of commodity price swap agreements
attributable to sales for only the Granger, Hilight and Newcastle systems. See Note 4. Transactions
with AffiliatesCommodity price swap agreements in the Notes to Consolidated Financial Statements
under Part I, Item 1 of this Form 10-Q.
Equity Income and Other Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
thousands except percentages |
|
2011 |
|
2010 |
|
Δ |
|
|
2011 |
|
2010 |
|
Δ |
|
Equity income |
|
$ |
2,646 |
|
|
$ |
1,308 |
|
|
|
102% |
|
|
$ |
4,690 |
|
|
$ |
2,687 |
|
|
|
75% |
|
Other revenues, net |
|
|
1,036 |
|
|
|
1,151 |
|
|
|
(10)% |
|
|
|
2,450 |
|
|
|
1,921 |
|
|
|
28% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity income
and other revenues, net |
|
$ |
3,682 |
|
|
$ |
2,459 |
|
|
|
50% |
|
|
$ |
7,140 |
|
|
$ |
4,608 |
|
|
|
55% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity income increased by $1.3 million and $2.0 million for the three and six months ended
June 30, 2011, respectively, due to the increase in the ownership interest in White Cliffs in
September 2010.
Other revenues decreased by $0.1 million and increased by $0.5 million for the three and six
months ended June 30, 2011, respectively, primarily due to changes in gas imbalance positions at
the Wattenberg, Granger, Hilight and MIGC systems.
Cost of Product and Operation and Maintenance Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
thousands except percentages |
|
2011 |
|
2010 |
|
Δ |
|
|
2011 |
|
2010 |
|
Δ |
|
Cost of product |
|
$ |
62,317 |
|
|
$ |
38,506 |
|
|
|
62% |
|
|
$ |
109,137 |
|
|
$ |
80,479 |
|
|
|
36% |
|
Operation and maintenance |
|
|
23,639 |
|
|
|
22,205 |
|
|
|
6% |
|
|
|
44,501 |
|
|
|
44,596 |
|
|
|
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total cost of product and operation and
maintenance expenses |
|
$ |
85,956 |
|
|
$ |
60,711 |
|
|
|
42% |
|
|
$ |
153,638 |
|
|
$ |
125,075 |
|
|
|
23% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost of product expense increased by $23.8 million for the three months ended June 30, 2011,
which includes a $27.6 million increase due to the acquisition of the Platte Valley
system and increased throughput at systems subject to percent-of-proceeds and keep-whole
contracts, partially offset by a $3.8 million decrease due to changes in gas imbalance positions.
Cost of product expense increased by $28.7 million for the six months ended June 30, 2011,
which includes a $36.4 million increase primarily due to the acquisition of the Platte Valley
system as well as increased throughput at systems subject to percent-of-proceeds and keep-whole
contracts, partially offset by a $7.7 million decrease due to changes in gas imbalance positions.
Cost of product expense includes the effects of commodity price swap agreements attributable
to purchases for the three and six months ended June 30, 2011 and 2010. See Note 4. Transactions
with AffiliatesCommodity price swap agreements in the Notes to Consolidated Financial Statements
under Part I, Item 1 of this Form 10-Q.
Operation and maintenance expense increased by $1.4 million for the three months ended June
30, 2011, primarily due to the acquisition of the Platte Valley system.
34
General and Administrative, Depreciation and Other Expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
thousands except percentages |
|
2011 |
|
2010 |
|
Δ |
|
|
2011 |
|
2010 |
|
Δ |
|
General and administrative |
|
$ |
7,082 |
|
|
$ |
5,455 |
|
|
|
30% |
|
|
$ |
13,780 |
|
|
$ |
11,523 |
|
|
|
20% |
|
Property and other taxes |
|
|
3,974 |
|
|
|
3,649 |
|
|
|
9% |
|
|
|
7,933 |
|
|
|
7,268 |
|
|
|
9% |
|
Depreciation, amortization and impairments |
|
|
21,711 |
|
|
|
17,613 |
|
|
|
23% |
|
|
|
41,269 |
|
|
|
35,332 |
|
|
|
17% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total general and administrative,
depreciation and other expenses |
|
$ |
32,767 |
|
|
$ |
26,717 |
|
|
|
23% |
|
|
$ |
62,982 |
|
|
$ |
54,123 |
|
|
|
16% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
General and administrative expenses increased by $1.6 million and $2.3 million for the three
and six months ended June 30, 2011, respectively, due to (i) an increase in noncash payroll
expenses primarily due to an increase in the value of incentive plan awards, (ii) an increase in
corporate and management personnel costs allocated to us pursuant to the omnibus agreement, and
(iii) an increase in legal, consultation and accounting transition fees related to the Platte
Valley acquisition. These increases were partially offset by the management fee allocated to the
Wattenberg assets during the three and six months ended June 30, 2010, which was discontinued upon
contribution of the assets to us effective July 2010.
Property and other taxes increased by $0.3 million and $0.7 million for the three and six
months ended June 30, 2011, respectively, primarily due to the ad valorem tax for the Platte Valley
assets.
Depreciation, amortization and impairments increased by $4.1 million and $5.9 million for the
three and six months ended June 30, 2011, respectively, primarily attributable to the addition of
the Platte Valley system, depreciation associated with previously leased compressors used at the
Granger and Wattenberg systems purchased and contributed to us during 2010, and capital projects
completed at the Hugoton system.
Interest Income and Interest Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
thousands except percentages |
|
2011 |
|
2010 |
|
Δ |
|
2011 |
|
2010 |
|
Δ |
Interest income on note receivable |
|
$ |
4,225 |
|
|
$ |
4,225 |
|
|
|
% |
|
|
$ |
8,450 |
|
|
$ |
8,450 |
|
|
|
% |
|
Interest income, net on affiliate balances |
|
|
|
|
|
|
7 |
|
|
|
(100)% |
|
|
|
|
|
|
|
12 |
|
|
|
(100)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest income affiliates |
|
$ |
4,225 |
|
|
$ |
4,232 |
|
|
nm (1) |
|
|
$ |
8,450 |
|
|
$ |
8,462 |
|
|
nm (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third Parties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense on long-term debt |
|
$ |
(4,474) |
|
|
$ |
(1,130) |
|
|
|
296% |
|
|
$ |
(7,150) |
|
|
$ |
(2,107) |
|
|
|
239% |
|
Amortization of debt issuance costs and
commitment fees |
|
|
(1,003) |
|
|
|
(683) |
|
|
|
47% |
|
|
|
(3,204) |
|
|
|
(1,449) |
|
|
|
121% |
|
Capitalized interest |
|
|
13 |
|
|
|
|
|
|
nm |
|
|
|
13 |
|
|
|
|
|
|
nm |
|
Affiliates |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense on notes payable |
|
|
(1,233) |
|
|
|
(1,750) |
|
|
|
(30)% |
|
|
|
(2,467) |
|
|
|
(3,500) |
|
|
|
(30)% |
|
Credit facility commitment fees |
|
|
|
|
|
|
(35) |
|
|
|
(100)% |
|
|
|
|
|
|
|
(70) |
|
|
|
(100)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense |
|
$ |
(6,697) |
|
|
$ |
(3,598) |
|
|
|
86% |
|
|
$ |
(12,808) |
|
|
$ |
(7,126) |
|
|
|
80% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Percent change is not meaningful (nm). |
Interest expense increased by $3.1 million and by $5.7 million for the three and six
months ended June 30, 2011, respectively, due to interest expense incurred on the 5.375% Senior
Notes issued in May 2011, higher interest expense on the amounts outstanding on our revolving
credit facility during 2011, interest expense during 2011 under the Wattenberg term loan (described
in Liquidity and Capital Resources), as well as $1.3 million of accelerated amortization expense
related to the early repayment of the Wattenberg term loan in March 2011. This increase is
partially offset by a decrease in interest expense on the Note Payable to Anadarko which was
amended in December 2010 reducing the interest rate from 4.00% to 2.82% for the remainder of the
term. See Note 7. Debt and Interest Expense in the Notes to Consolidated Financial Statements
included under Part I, Item 1 of this Form 10-Q.
35
Other Income (Expense), Net
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
thousands except percentages |
|
2011 |
|
|
2010 |
|
|
Δ |
|
|
2011 |
|
|
2010 |
|
|
Δ |
|
Other expense, net |
|
$ |
(3,682) |
|
|
$ |
(2,393) |
|
|
|
54% |
|
|
$ |
(1,922) |
|
|
$ |
(2,373) |
|
|
|
(19)% |
|
Other expense, net for the three months ended June 30, 2011, primarily consists of the
reversal of a $1.7 million unrealized gain on our terminated forward-starting interest-rate swap
agreement, previously recorded in March 2011, and a $1.9 million loss, realized upon termination of
the interest-rate swap agreement in May 2011. Other expense, net for the six months ended June 30,
2011, primarily consists of the $1.9 million loss realized upon termination of the interest-rate
swap agreement in May 2011. Other expense, net for the three and six months ended June 30, 2010,
primarily consists of expense incurred in contemplation of refinancing existing borrowings under
our revolving credit agreement with long-term fixed-rate notes. In April 2010 we entered into
financial agreements to fix the underlying ten-year Treasury rates with respect to potential note
issuances that were under consideration at that time. Upon reaching our decision not to issue the
notes in May 2010, we terminated the agreements at a cost of $2.4 million.
Income Tax Expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
thousands except percentages |
|
2011 |
|
|
2010 |
|
|
Δ |
|
|
2011 |
|
|
2010 |
|
|
Δ |
|
Income before income taxes |
|
$ |
36,871 |
|
|
$ |
35,796 |
|
|
|
3% |
|
|
$ |
74,841 |
|
|
$ |
73,684 |
|
|
|
2% |
|
Income tax expense |
|
|
94 |
|
|
|
3,419 |
|
|
|
(97)% |
|
|
|
126 |
|
|
|
8,975 |
|
|
|
(99)% |
|
Effective tax rate |
|
|
|
% |
|
|
10 |
% |
|
|
|
|
|
|
|
% |
|
|
12 |
% |
|
|
|
|
We are not a taxable entity for U.S. federal income tax purposes. For the three and six months
ended June 30, 2011, only the portion of our income allocable to Texas was subject to Texas margin
tax. For the three and six months ended June 30, 2010, other than income earned by the Granger and
Wattenberg assets, only the portion of our income allocable to Texas was subject to Texas margin
tax. Income attributable to the Wattenberg assets prior to and including July 2010 and income
attributable to the Granger assets prior to and including January 2010 were subject to federal and
state income tax, resulting in the lower income tax expense for the three and six months ended June
30, 2011. Income earned by the Granger and Wattenberg assets for periods subsequent to January 2010
and July 2010, respectively, was subject only to Texas margin tax.
For 2011 and 2010, the Partnerships variance from the federal statutory rate is primarily
attributable to the Partnerships status as a non-taxable entity for U.S. federal income tax
purposes.
Noncontrolling Interests
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
thousands except percentages |
|
2011 |
|
|
2010 |
|
|
Δ |
|
|
2011 |
|
|
2010 |
|
|
Δ |
|
Net income attributable to
noncontrolling interests |
|
$ |
2,838 |
|
|
$ |
3,371 |
|
|
|
(16)% |
|
|
$ |
5,792 |
|
|
$ |
5,265 |
|
|
|
10% |
|
For the three months ended June 30, 2011, net income attributable to noncontrolling interests
decreased by $0.5 million, primarily due to decreased NGL recoveries resulting from a cryogenic
unit outage at Chipeta during April 2011. Net income attributable to noncontrolling interests
increased by $0.5 million for the six months ended June 30, 2011, due to the higher overall year to
date volumes and improved liquids recoveries at the Chipeta system.
36
Key Performance Metrics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Six Months Ended |
|
thousands except percentages |
|
June 30, |
|
|
June 30, |
|
and gross margin per Mcf |
|
2011 |
|
|
2010 |
|
|
Δ |
|
|
2011 |
|
|
2010 |
|
|
Δ |
|
Gross margin |
|
$ |
99,431 |
|
|
$ |
86,477 |
|
|
|
15% |
|
|
$ |
188,604 |
|
|
$ |
173,440 |
|
|
|
9% |
|
Gross margin per Mcf (1) |
|
|
0.61 |
|
|
|
0.52 |
|
|
|
17% |
|
|
|
0.59 |
|
|
|
0.52 |
|
|
|
13% |
|
Gross margin per Mcf attributable to
Western Gas Partners, LP (2) |
|
|
0.67 |
|
|
|
0.55 |
|
|
|
22% |
|
|
|
0.65 |
|
|
|
0.55 |
|
|
|
18% |
|
Adjusted EBITDA (3) |
|
|
63,479 |
|
|
|
51,552 |
|
|
|
23% |
|
|
|
119,793 |
|
|
|
104,182 |
|
|
|
15% |
|
Distributable cash flow (3) |
|
$ |
56,619 |
|
|
$ |
46,901 |
|
|
|
21% |
|
|
$ |
106,345 |
|
|
$ |
94,739 |
|
|
|
12% |
|
|
|
|
(1) |
|
Average for period. Calculated as gross margin (total revenues less cost of
product) divided by total throughput, including 100% of gross margin and volumes attributable
to Chipeta and our 14.81% interest in income and volumes attributable to Fort Union. |
|
(2) |
|
Average for period. Calculated as gross margin, excluding the noncontrolling
interest owners proportionate share of revenues and cost of product, divided by total
throughput attributable to Western Gas Partners, LP. Calculation includes income attributable
to our investments in Fort Union and White Cliffs and volumes attributable to our investment
in Fort Union. |
|
(3) |
|
For a reconciliation of Adjusted EBITDA and Distributable cash flow to their most
directly comparable financial measures calculated and presented in accordance with GAAP,
please read the descriptions below under the captions Adjusted EBITDA and Distributable cash
flow. |
Gross margin and Gross margin per Mcf. Gross margin increased by $13.0 million for the three
months ended June 30, 2011, primarily due to the acquisition of the Platte Valley system; higher
margins at the Wattenberg and Hilight systems due to an increase in prices and volumes, including
the impact of commodity price swap agreements; and the increase in our interest in White Cliffs
from 0.4% to 10% in September 2010. These increases were partially offset by (i) lower gross
margins at the Haley and Hugoton systems due to naturally declining production volumes and (ii)
lower gross margin at the MIGC system due to the expiration of certain firm transportation
contracts in January 2011. For the three months ended June 30, 2011, gross margin per Mcf increased
by 17% and gross margin per Mcf attributable to Western Gas Partners, LP increased by 22%,
primarily due to the acquisition of the Platte Valley system in 2011, the additional interest in
the White Cliffs system in September 2010 and changes in the throughput mix of the portfolio.
Gross margin increased by $15.2 million for the six months ended June 30, 2011, primarily due
to the acquisition of the Platte Valley system; higher margins at the Chipeta and Hilight systems
due to an increase in volumes and prices, including the impact of commodity price swap agreements
at the Hilight system; and the increase in our interest in White Cliffs from 0.4% to 10% in
September 2010. These increases were partially offset by (i) lower gross margins at the Haley and
Hugoton systems due to naturally declining production volumes and (ii) lower gross margin at the
MIGC system due to the expiration of certain firm transportation contracts in January 2011. For the
six months ended June 30, 2011, gross margin per Mcf increased by 13% and gross margin per Mcf
attributable to Western Gas Partners, LP increased by 18%, due to the acquisition of the Platte
Valley system in 2011, the additional interest in the White Cliffs system in September 2010 and
changes in the throughput mix of the portfolio.
Adjusted EBITDA. We define Adjusted EBITDA as net income (loss) attributable to Western Gas
Partners, LP, plus distributions from equity investees, non-cash equity-based compensation expense,
general and administrative expense in excess of the omnibus cap (if any), interest expense, income
tax expense, depreciation, amortization and impairments, and other expense, less income from equity
investments, interest income, income tax benefit, other income and other nonrecurring adjustments
that are not settled in cash.
37
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 companys ability to incur and service debt, fund capital
expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure, which
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 increased by $11.9 million for the three months ended June 30, 2011, primarily
due to a $35.4 million increase in total revenues excluding equity income, a $1.9 million increase
in distributions from Fort Union and White Cliffs and a $0.5 million decrease in net income
attributable to noncontrolling interests. These changes were partially offset by a $23.8 million
increase in cost of product, a $0.4 million increase in general and administrative expenses
excluding non-cash equity-based compensation and a $1.4 million increase in operation and
maintenance expenses.
Adjusted EBITDA increased by $15.6 million for the six months ended June 30, 2011, primarily
due to a $41.8 million increase in total revenues excluding equity income and a $3.2 million
increase in distributions from Fort Union and White Cliffs. These changes were partially offset by
a $28.7 million increase in cost of product and a $0.5 million increase in net income attributable
to noncontrolling interests.
Distributable cash flow. We define Distributable cash flow as Adjusted EBITDA, plus interest
income, less net cash paid for interest expense (including amortization of deferred debt issuance
costs originally paid in cash), maintenance capital expenditures, and income taxes. 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. We
also 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 estimated cash flows to
planned cash distributions.
Distributable cash flow increased by $9.7 million for the three months ended June 30, 2011,
primarily due to the $11.9 million increase in Adjusted EBITDA and a $0.9 million decrease in cash
paid for maintenance capital expenditures, partially offset by a $3.1 million increase in interest
expense on borrowings.
Distributable cash flow increased by $11.6 million for the six months ended June 30, 2011,
primarily due to the $15.6 million increase in Adjusted EBITDA and a $1.7 million decrease in cash
paid for maintenance capital expenditures, partially offset by a $5.7 million increase in interest
expense on borrowings.
Reconciliation to GAAP measures. Adjusted EBITDA and Distributable cash flow are not defined in
GAAP. The GAAP measures most directly comparable to Adjusted EBITDA are net income attributable to
Western Gas Partners, LP and net cash provided by operating activities, while the GAAP measure most
directly comparable to Distributable cash flow is net income attributable to Western Gas Partners,
LP. Our non-GAAP financial measures of Adjusted EBITDA and Distributable cash flow should not be
considered as alternatives to the GAAP measures of net income attributable to Western Gas Partners,
LP or net cash provided by operating activities. Adjusted EBITDA has important limitations as an
analytical tool because it excludes some, but not all, items that affect net income and net cash
provided by operating activities. You should not consider Adjusted EBITDA or Distributable cash
flow in isolation or as a substitute for analysis of our results as reported under GAAP. Our
definitions of Adjusted EBITDA and Distributable cash flow may not be comparable to similarly
titled measures of other companies in our industry, thereby diminishing their utility. Furthermore,
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.
38
Management compensates for the limitations of Adjusted EBITDA and Distributable cash flow as
analytical tools by reviewing the comparable GAAP measures, understanding the differences between
Adjusted EBITDA and Distributable cash flow compared to (as applicable) net income 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 non-GAAP financial measure of
Adjusted EBITDA to the GAAP financial measures of net income attributable to Western Gas Partners,
LP and net cash provided by operating activities, and (b) a reconciliation of the non-GAAP
financial measure of Distributable cash flow to the GAAP financial measure of net income
attributable to Western Gas Partners, LP:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
Reconciliation of Adjusted EBITDA to Net income
attributable to Western Gas Partners, LP |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA attributable to Western Gas Partners, LP |
|
$ |
63,479 |
|
|
$ |
51,552 |
|
|
$ |
119,793 |
|
|
$ |
104,182 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions from equity investees |
|
|
3,013 |
|
|
|
1,088 |
|
|
|
5,447 |
|
|
|
2,238 |
|
Non-cash equity-based compensation expense |
|
|
1,918 |
|
|
|
681 |
|
|
|
3,846 |
|
|
|
1,248 |
|
Interest expense |
|
|
6,697 |
|
|
|
3,598 |
|
|
|
12,808 |
|
|
|
7,126 |
|
Income tax expense (1) |
|
|
94 |
|
|
|
3,419 |
|
|
|
126 |
|
|
|
8,975 |
|
Depreciation, amortization and impairments (1) |
|
|
21,007 |
|
|
|
16,907 |
|
|
|
39,860 |
|
|
|
33,926 |
|
Other expense (1) |
|
|
3,682 |
|
|
|
2,393 |
|
|
|
3,682 |
|
|
|
2,393 |
|
Add: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity income, net |
|
|
2,646 |
|
|
|
1,308 |
|
|
|
4,690 |
|
|
|
2,687 |
|
Interest
income affiliates |
|
|
4,225 |
|
|
|
4,232 |
|
|
|
8,450 |
|
|
|
8,462 |
|
Other income (1) |
|
|
|
|
|
|
|
|
|
|
1,759 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
Net income attributable to Western Gas Partners, LP |
|
$ |
33,939 |
|
|
$ |
29,006 |
|
|
$ |
68,923 |
|
|
$ |
59,444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Adjusted EBITDA to Net cash
provided by operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDA attributable to Western Gas Partners, LP |
|
$ |
63,479 |
|
|
$ |
51,552 |
|
|
$ |
119,793 |
|
|
$ |
104,182 |
|
Adjusted EBITDA attributable to noncontrolling interests |
|
|
3,542 |
|
|
|
4,077 |
|
|
|
7,200 |
|
|
|
6,670 |
|
Interest income (expense), net |
|
|
(2,472 |
) |
|
|
634 |
|
|
|
(4,358 |
) |
|
|
1,336 |
|
Non-cash equity-based compensation expense |
|
|
(1,918 |
) |
|
|
(681 |
) |
|
|
(3,846 |
) |
|
|
(1,248 |
) |
Current income tax expense |
|
|
(77 |
) |
|
|
(4,267 |
) |
|
|
(167 |
) |
|
|
(11,608 |
) |
Other expense, net |
|
|
(3,682 |
) |
|
|
(2,393 |
) |
|
|
(1,922 |
) |
|
|
(2,373 |
) |
Distributions from equity investees less than
(in excess of) equity income, net |
|
|
(367 |
) |
|
|
220 |
|
|
|
(757 |
) |
|
|
449 |
|
Changes in operating working capital: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable and natural gas imbalance receivable |
|
|
(9,030 |
) |
|
|
(788 |
) |
|
|
(17,715 |
) |
|
|
(6,317 |
) |
Accounts payable, accrued liabilities and natural gas imbalance payable |
|
|
6,302 |
|
|
|
(1,623 |
) |
|
|
12,189 |
|
|
|
8,106 |
|
Other |
|
|
2,512 |
|
|
|
536 |
|
|
|
2,936 |
|
|
|
529 |
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
58,289 |
|
|
$ |
47,267 |
|
|
$ |
113,353 |
|
|
$ |
99,726 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes our 51% share of income tax expense; depreciation, amortization and
impairments; other income; and other expense attributable to Chipeta. |
39
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
Six Months Ended |
|
|
June 30, |
|
June 30, |
thousands |
|
2011 |
|
2010 |
|
2011 |
|
2010 |
Reconciliation of Distributable cash flow to Net income
attributable to Western Gas Partners, LP |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributable cash flow |
|
$ |
56,619 |
|
|
$ |
46,901 |
|
|
$ |
106,345 |
|
|
$ |
94,739 |
|
Less: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions from equity investees |
|
|
3,013 |
|
|
|
1,088 |
|
|
|
5,447 |
|
|
|
2,238 |
|
Non-cash equity-based compensation expense |
|
|
1,918 |
|
|
|
681 |
|
|
|
3,846 |
|
|
|
1,248 |
|
Income tax expense (1) |
|
|
94 |
|
|
|
3,419 |
|
|
|
126 |
|
|
|
8,975 |
|
Depreciation, amortization and impairments (1) |
|
|
21,007 |
|
|
|
16,907 |
|
|
|
39,860 |
|
|
|
33,926 |
|
Other expense (1) |
|
|
3,682 |
|
|
|
2,393 |
|
|
|
3,682 |
|
|
|
2,393 |
|
Add: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity income, net |
|
|
2,646 |
|
|
|
1,308 |
|
|
|
4,690 |
|
|
|
2,687 |
|
Cash paid for maintenance capital expenditures (1) |
|
|
4,375 |
|
|
|
5,278 |
|
|
|
9,077 |
|
|
|
10,767 |
|
Capitalized interest |
|
|
13 |
|
|
|
|
|
|
|
13 |
|
|
|
|
|
Interest income, net (non-cash settled) |
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
12 |
|
Other income (1) |
|
|
|
|
|
|
|
|
|
|
1,759 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
Net income attributable to Western Gas Partners, LP |
|
$ |
33,939 |
|
|
$ |
29,006 |
|
|
$ |
68,923 |
|
|
$ |
59,444 |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes our 51% share of income tax expense; depreciation, amortization and
impairments; other expense; cash paid for maintenance capital expenditures; and other income
attributable to Chipeta. |
LIQUIDITY AND CAPITAL RESOURCES
Our primary cash requirements are for acquisitions and other capital expenditures, debt
service, customary operating expenses, quarterly distributions to our limited partners and general
partner, and distributions to our noncontrolling interest owners. Our sources of liquidity as of
June 30, 2011, include cash flows generated from operations, including interest income on our
$260.0 million note receivable from Anadarko, available borrowing capacity under our revolving
credit facility, and issuances of additional common and general partner units or debt securities.
We believe that cash flows generated from the sources above will be sufficient to satisfy our
short-term working capital requirements and long-term maintenance capital expenditure requirements.
The amount of future distributions to unitholders will depend on results of operations, financial
conditions, capital requirements and other factors, and will be determined by the board of
directors of our general partner on a quarterly basis. Due to our cash distribution policy, we
expect to rely on external financing sources, including debt and common unit 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 revolving credit facility to pay distributions or fund other
short-term working capital requirements.
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
subsequent to the end of each quarter. We have made cash distributions to our unitholders and have
increased our quarterly distribution each quarter from the second quarter of 2009 through the
second quarter of 2011. On June 30, 2011, the board of directors of our general partner declared a
cash distribution to our unitholders of $0.405 per unit, or $36.1 million in aggregate, including
incentive distributions. The cash distribution is payable on August 12, 2011, to unitholders of
record at the close of business on July 29, 2011.
Management continuously monitors our leverage position and coordinates its capital expenditure
program, quarterly distributions and acquisition strategy with its 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
statement. Our ability to generate cash flows is subject to a number of factors, some of which are
beyond our control. Please read Item 1ARisk Factors of our 2010 annual report on Form 10-K.
40
Working capital. As of June 30, 2011, we had $35.9 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.
Capital expenditures. Our business can be capital intensive, requiring significant investment to
maintain and improve existing facilities. 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; or |
|
|
|
|
expansion capital expenditures, which include those expenditures incurred in order 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 and capital incurred were as follows:
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, |
thousands |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
Acquisitions |
|
$ |
303,602 |
|
|
$ |
241,680 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expansion capital expenditures |
|
$ |
20,840 |
|
|
$ |
39,298 |
|
Maintenance capital expenditures |
|
|
9,116 |
|
|
|
10,891 |
|
|
|
|
|
|
Total capital expenditures (1) |
|
$ |
29,956 |
|
|
$ |
50,189 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital incurred (2) |
|
$ |
34,193 |
|
|
$ |
50,323 |
|
|
|
|
|
|
|
|
|
(1) |
|
Capital expenditures for the
six months ended June 30, 2010, include $40.6
million of pre-acquisition capital expenditures for Partnership assets and capital
expenditures for the six months ended June 30, 2011 and 2010, include the noncontrolling
interest owners share of Chipetas capital expenditures, funded by contributions from the
noncontrolling interest owners. |
|
(2) |
|
Capital incurred for the six
months ended June 30, 2010, includes $41.4 million of
pre-acquisition capital incurred for the Partnership assets and capital incurred for the six
months ended June 30, 2011 and 2010, includes the noncontrolling interest owners share of
Chipetas capital incurred, funded by contributions from the noncontrolling interest
owners. |
Acquisitions include the Platte Valley acquisition and the Granger acquisition
described under the caption Acquisitions within this Item 2.
Capital expenditures, excluding acquisitions, decreased by $20.2 million for the six months
ended June 30, 2011. Expansion capital expenditures decreased by $18.5 million for the six months
ended June 30, 2011, primarily due to the purchase of previously leased compressors at the
Wattenberg system during the six months ended June 30, 2010 for
$37.5 million,
partially offset by an increase of $19.0 million in
expenditures primarily at our Chipeta and Hilight systems during the six months ended June 30, 2011.
Maintenance capital expenditures decreased by $1.8 million, primarily as a result of fewer well
connections at the Haley, Hugoton and Granger systems in 2011 and improvements at the Granger
system completed during 2010, partially offset by power system upgrades at the Dew system in 2011.
41
Historical cash flow. The following table presents a summary of our net cash flows from operating
activities, investing activities and financing activities.
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
June 30, |
thousands |
|
2011 |
|
2010 |
|
|
|
|
|
|
|
|
|
Net cash provided by (used in): |
|
|
|
|
|
|
|
|
Operating activities |
|
$ |
113,353 |
|
|
$ |
99,726 |
|
Investing activities |
|
|
(333,409 |
) |
|
|
(292,179 |
) |
Financing activities |
|
|
255,677 |
|
|
|
186,871 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net increase (decrease) in cash and cash equivalents |
|
$ |
35,621 |
|
|
$ |
(5,582 |
) |
|
|
|
|
|
Operating Activities. Net cash provided by operating activities increased by $13.6 million for the
six months ended June 30, 2011, as compared to the six months ended June 30, 2010, primarily due to
the following items:
|
|
|
a $41.8 million increase in revenues, excluding equity income; |
|
|
|
|
an $11.4 million decrease in current income tax expense; |
|
|
|
|
a $6.5 million increase due to changes in accounts payable balances and other
items; |
|
|
|
|
a $0.3 million decrease in general and administrative expenses, excluding non-cash
equity-based compensation; and |
|
|
|
|
a $0.1 million decrease in operating and maintenance expenses. |
The impact of the above items was offset by the following:
|
|
|
a $28.7 million increase in cost of product expense; |
|
|
|
|
an $11.4 million decrease due to changes in accounts receivable balances; |
|
|
|
|
a $5.7 million increase in interest expense; and |
|
|
|
|
a $0.7 million increase in property and other taxes expense. |
Investing Activities. Net cash used in investing activities for the six months ended June 30, 2011,
included $303.6 million of cash paid for the Platte Valley acquisition and $30.0 million of capital
expenditures. Net cash used in investing activities for the six months ended June 30, 2010,
included $241.7 million of cash paid for the Granger acquisition and $50.2 million of capital
expenditures. See the sub-caption Capital expenditures above within this Liquidity and Capital
Resources discussion.
42
Financing Activities. Net cash provided by financing activities for the six months ended June 30,
2011, included $303.0 million of borrowings to fund the Platte Valley acquisition, $132.6 million
of net proceeds from our March 2011 equity offering and $493.9 million net proceeds from our Notes
offering in May 2011, after debt discount and offering costs, each offset by repayment of amounts
due under our revolving credit facility using the offering proceeds. Financing activities for the
six months ended June 30, 2011, also included the $250.0 million repayment of the Wattenberg term
loan (described below) using borrowings from our revolving credit facility. Financing activities
for the six months ended June 30, 2010 included the $210.0 million of borrowings to partially fund
the Granger acquisition. For the six months ended June 30, 2011 and 2010, we paid $63.7 million and
$43.4 million, respectively, of cash distributions to our unitholders. Contributions from
noncontrolling interest owners to Chipeta totaled $7.4 million and $2.1 million during the six
months ended June 30, 2011 and 2010, respectively, primarily for expansion of the cryogenic units.
Distributions from Chipeta to noncontrolling interest owners totaled $7.5 million and $6.4 million
for the six months ended June 30, 2011 and 2010, respectively, representing the distributions for
the two preceding quarterly periods ended March 31st of the respective year.
Debt and credit facilities. As of June 30, 2011, our outstanding debt consisted of $493.9 million
of 5.375% Senior Notes and the $175.0 million note payable to Anadarko. See Note 7. Debt and
Interest Expense in the Notes to Consolidated Financial Statements included under Part I, Item 1 of
this Form 10-Q.
5.375% Senior Notes due 2021. In May 2011, we completed the offering of $500.0 million aggregate
principal amount of 5.375% Senior Notes (the Notes) at a public offering price of 98.778%.
Interest on the Notes will be paid semi-annually on June 1 and December 1 of each year, commencing
on December 1, 2011. The Notes mature on June 1, 2021,
unless redeemed, in whole or in part, at any
time prior to maturity, at a redemption price that includes a make-whole premium. Proceeds from the
offering of the Notes (net of the underwriting discount of $3.3 million and debt issuance costs)
were used to repay the then-outstanding balance on the revolving credit facility, with the
remainder used for general partnership purposes.
The Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our
wholly owned subsidiaries (the Subsidiary Guarantors). The Subsidiary Guarantors guarantees will
be released if, among other things, the Subsidiary Guarantors are released from their obligations
under our revolving credit facility.
The Notes indenture contains customary events of default including, among others, (i) default
in any payment of interest on any debt securities when due that continues for 30 days; (ii) default
in payment, when due, of principal of or premium, if any, on the Notes at maturity; and (iii)
certain events of bankruptcy or insolvency with respect to the Partnership. The indenture governing
the Notes also contains covenants that will, among other things, limit our ability, as well as that
of the Subsidiary Guarantors, to create liens on our principal properties, engage in sale and
leaseback transactions, and merge or consolidate with another entity or sell, lease or transfer
substantially all of our properties or assets to another entity. At June 30, 2011, we were in
compliance with all covenants under the Notes.
Note payable to Anadarko. In December 2008, we entered into a five-year $175.0 million term loan
agreement with Anadarko. The interest rate was fixed at 4.00% through November 2010, and is fixed
at 2.82% thereafter, reflecting an amendment to the term loan agreement made in December 2010. We
have the option, at any time, to repay the outstanding principal amount in whole or in part.
The provisions of the five-year term loan agreement contain customary events of default,
including (i) nonpayment of principal when due or nonpayment of interest or other amounts within
three business days of when due, (ii) certain events of bankruptcy or insolvency with respect to
the Partnership and (iii) a change of control. At June 30, 2011, we were in compliance with all
covenants under this agreement.
Revolving credit facility. In March 2011, we entered into an amended and restated $800.0 million
senior unsecured revolving credit facility, or the RCF, and borrowed $250.0 million under the RCF
to repay the Wattenberg term loan (described below). The RCF amended and restated our $450.0
million credit facility, which was originally entered into in October 2009. The RCF matures in
March 2016 and bears interest at London Interbank Offered Rate, or LIBOR, plus applicable margins
ranging from 1.30% to 1.90%, or an alternate base rate equal to the greatest of (a) the Prime Rate,
(b) the Federal Rate plus 0.5%, and (c) LIBOR plus 1%, plus applicable margins ranging from 0.30%
to 0.90%. We are also required to pay a quarterly facility fee ranging from 0.20% to 0.35% of the
commitment amount (whether used or unused), based upon our consolidated leverage ratio as defined
in the RCF.
43
The RCF contains covenants that limit, among other things, our, and certain of our
subsidiaries, ability to incur additional indebtedness, grant certain liens, merge, consolidate or
allow any material change in the character of our business, sell all or substantially all of our
assets, make certain transfers, enter into certain affiliate transactions, make distributions or
other payments other than distributions of available cash under certain conditions and use proceeds
other than for partnership purposes. The RCF also contains various customary covenants, customary
events of default and certain financial tests, as of the end of each quarter, including a maximum
consolidated leverage ratio, as defined in the RCF, of 5.0 to 1.0, or a consolidated leverage ratio
of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain
acquisitions, and a minimum consolidated interest coverage ratio, as defined in the RCF, of 2.0 to
1.0.
All amounts due under the RCF are unconditionally guaranteed by our wholly owned subsidiaries.
We will no longer be required to comply with the minimum consolidated interest coverage ratio as
well as the subsidiary guarantees and certain of the aforementioned covenants, if we obtain two of
the following three ratings: BBB- or better by S&P, Baa3 or better by Moodys or BBB- or better by
Fitch. As of June 30, 2011, no amounts were outstanding under the RCF, with $800.0 million
available for borrowing. At June 30, 2011, we were in compliance with all covenants under the RCF.
Wattenberg term loan. In connection with the Wattenberg acquisition, in August 2010, we borrowed
$250.0 million under a three-year term loan from a group of banks (Wattenberg term loan). The
Wattenberg term loan incurred interest at LIBOR plus a margin, ranging from 2.50% to 3.50%
depending on our consolidated leverage ratio, as defined in the Wattenberg term loan agreement. We
repaid the Wattenberg term loan in March 2011 using borrowings from our RCF.
Registered securities. We may issue an indeterminate amount of limited partner common units and
various debt securities under our effective shelf registration statement on file with the SEC.
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 customers 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 the substantial majority of our natural
gas volumes 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 gas, 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, which was issued concurrently with the
closing of our initial public offering. 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 commodity price risk and are
subject to performance risk thereunder.
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, its note payable to us, the omnibus agreement,
the services and secondment agreement, contribution agreements or the commodity price swap
agreements.
44
CONTRACTUAL OBLIGATIONS
Our contractual obligations include a note payable to Anadarko, a revolving credit facility,
other third-party long-term debt, a corporate office lease and warehouse lease, for which
information is provided in Note 7. Debt and Interest Expense and Note 8. Commitments and
Contingencies included in the Notes to Consolidated Financial Statements under Part I, Item 1 of
this Form 10-Q. Our contractual obligations also include asset retirement obligations, which have
not changed significantly since December 31, 2010, except for asset retirement obligations assumed
in connection with the Platte Valley acquisition for which information is provided under Note 1.
Description of Business and Basis of PresentationAcquisitions in the Notes to Consolidated
Financial Statements under Part I, Item 1 of this Form 10-Q.
OFF-BALANCE SHEET ARRANGEMENTS
We do not have any off-balance sheet arrangements other than operating leases. The information
pertaining to operating leases required for this item is provided under Note 8. Commitments and
Contingencies included in the Notes to Consolidated Financial Statements under Part I, Item 1 of
this Form 10-Q.
RECENT ACCOUNTING DEVELOPMENTS
Recently issued accounting standards not yet adopted. In May 2011, the Financial Accounting
Standards Board (the FASB) issued an Accounting Standards Update (ASU) amending guidance on
fair value measurements and related disclosures. The ASU clarifies the FASBs intent regarding the
application of existing fair value measurement requirements, changes the fair value measurement
requirements for certain financial instruments and requires additional disclosures about fair value
measurements. This ASU will apply to our consolidated financial statements prospectively beginning
January 1, 2012, and the impact, if any, is currently under evaluation.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity price risk. Pursuant to certain of our contracts, we retain and sell drip condensate that
is recovered during the gathering of natural gas. As part of this arrangement, we are required to
provide a thermally equivalent volume of natural gas or the cash equivalent thereof to the shipper.
Thus, our revenues for this portion of our contractual arrangement are based on the price received
for the drip condensate and our costs for this portion of our contractual arrangement depend on the
price of natural gas. Historically, drip condensate sells at a price representing a discount to the
price of New York Mercantile Exchange, or NYMEX, West Texas Intermediate crude oil.
In addition, certain of our processing services are provided under percent-of-proceeds and
keep-whole agreements in which Anadarko is typically responsible for the marketing of the natural
gas and NGLs. Under percent-of-proceeds agreements, we receive a specified percentage of the net
proceeds from the sale of natural gas and NGLs. Under keep-whole agreements, we keep 100% of the
NGLs produced, and the processed natural gas, or value of the gas, is returned to the producer.
Since some of the gas is used and removed during processing, we compensate the producer for this
amount of gas by supplying additional gas or by paying an agreed-upon value for the gas utilized.
To mitigate our exposure to changes in commodity prices as a result of the purchase and sale
of natural gas, condensate or NGLs, we currently have in place fixed-price swap agreements with
Anadarko expiring at various times through September 2015. For additional information on the
commodity price swap agreements, see Note 4. Transactions with AffiliatesCommodity price swap
agreements in the Notes to Consolidated Financial Statements under Part I, Item 1 of this Form
10-Q.
We consider our exposure to commodity price risk associated with the above-described
arrangements to be minimal given the existence of the commodity price swap agreements with Anadarko
and the relatively small amount of our operating income that is impacted by changes in market
prices. Accordingly, we do not expect a 10% change in natural gas or NGL prices to have a material
direct impact on our operating income, financial condition or cash flows for the next twelve
months, excluding the effect of natural gas imbalances described below.
45
We also bear a limited degree of commodity price risk with respect to settlement of our
natural gas imbalances that arise from differences in gas volumes received into our systems and gas
volumes delivered by us to customers. Natural gas volumes owed to or by us that are subject to
monthly cash settlement are valued according to the terms of the contract as of the balance sheet
dates, and generally reflect market index prices. Other natural gas volumes owed to or by us are
valued at our weighted average cost of natural gas as of the balance sheet dates and are settled
in-kind. Our exposure to the impact of changes in commodity prices on outstanding imbalances
depends on the timing of settlement of the imbalances.
Interest rate risk. Interest rates during 2010 and 2011 were low compared to historic rates. Only
our revolving credit facility carries interest at variable rates based on LIBOR, and we did not
have an outstanding balance as of June 30, 2011. If interest rates rise, our future financing costs
could increase if we incur borrowings under our revolving credit facility.
We entered into a forward-starting interest-rate swap agreement in March 2011 to mitigate the
risk of rising interest rates prior to the issuance of the Notes. In May 2011, we issued the Notes
and terminated the swap agreement, realizing a loss of
$1.9 million, which is included in other expense, net
on our consolidated statements of income. For the three months ended June 30, 2011, a 10% change in
LIBOR would have resulted in a nominal change in interest expense.
We may incur additional debt in the future, either under our revolving credit facility or
other financing sources, including commercial bank borrowings or debt issuances.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and Chief Financial
Officer of the Partnerships general partner performed an evaluation of the Partnerships
disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Securities
Exchange Act of 1934. Our disclosure controls and procedures are designed to ensure that
information required to be disclosed by us in the reports that we file or submit under the Exchange
Act is recorded, processed, summarized and reported, within the time periods specified in the rules
and forms of the SEC and to ensure that the information required to be disclosed by us in reports
that we file under the Exchange Act is accumulated and communicated to our management, including
our principal executive officer and principal financial officer, as appropriate, to allow timely
decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and
Chief Financial Officer have concluded that the Partnerships disclosure controls and procedures
are effective as of June 30, 2011.
Changes in Internal Control Over Financial Reporting. There has been no change in our internal
control over financial reporting during the quarter ended June 30, 2011, that has materially
affected, or is reasonably likely to materially affect, the Partnerships internal control over
financial reporting.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
We are not a party to any legal, regulatory or administrative proceedings other than
proceedings arising in the ordinary course of our business. Management believes that there are no
such proceedings for which final disposition could have a material adverse effect on our financial
condition, results of operations or cash flows, or for which disclosure is required by Item 103 of
Regulation S-K.
Item 1A. Risk Factors
Security holders and potential investors in our securities should carefully consider the risk
factors under Part 1, Item 1A set forth in our annual report on Form 10-K for the year ended
December 31, 2010, together with all of the other information included in this document; the
Partnerships annual report on Form 10-K; and in our other public filings, press releases, and
discussions with management of the Partnership. Additionally, for a full discussion of the risks
associated with Anadarkos business, see Item 1A under Part I in Anadarkos annual report on Form
10-K for the year ended December 31, 2010, Anadarkos quarterly reports on Form 10-Q and Anadarkos
other public filings, press releases and discussions with Anadarko management. We have identified
these risk factors as important factors that could cause our actual results to differ materially
from those contained in any written or oral forward-looking statements made by us or on our behalf.
46
Item 6. Exhibits
Exhibits designated by an asterisk (*) are filed herewith and those designated with asterisks
(**) are furnished herewith; all exhibits not so designated are incorporated herein by reference to
a prior filing as indicated.
|
|
|
2.1
|
|
Contribution, Conveyance and Assumption Agreement by and among Western Gas Partners, LP,
Western Gas Holdings, LLC, Anadarko Petroleum Corporation, WGR Holdings, LLC, Western Gas
Resources, Inc., WGR Asset Holding Company LLC, Western Gas Operating, LLC and WGR Operating,
LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas
Partners, LPs Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046). |
|
|
|
2.2
|
|
Contribution Agreement, dated as of November 11, 2008, by and among Western Gas Resources,
Inc., WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, Western Gas
Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by reference to
Exhibit 10.1 to Western Gas Partners, LPs Current Report on Form 8-K filed on November 13,
2008, File No. 001-34046). |
|
|
|
2.3
|
|
Contribution Agreement, dated as of July 10, 2009, by and among Western Gas Resources, Inc.,
WGR Asset Holding Company LLC, Anadarko Uintah Midstream, LLC, WGR Holdings, LLC, Western Gas
Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR
Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LPs Current
Report on Form 8-K filed on July 23, 2009, File No. 001-34046). |
|
|
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2.4
|
|
Contribution Agreement, dated as of January 29, 2010 by and among Western Gas Resources,
Inc., WGR Asset Holding Company LLC, Mountain Gas Resources LLC, WGR Holdings, LLC, Western
Gas Holdings, LLC, WES GP, Inc., Western Gas Partners, LP, Western Gas Operating, LLC and WGR
Operating, LP. (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LPs Current
Report on Form 8-K filed on February 3, 2010 File No. 001-34046). |
|
|
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2.5
|
|
Contribution Agreement, dated as of July 30, 2010, by and among Western Gas Resources, Inc.,
WGR Asset Holding Company LLC, WGR Holdings, LLC, Western Gas Holdings, LLC, WES GP, Inc.,
Western Gas Partners, LP, Western Gas Operating, LLC and WGR Operating, LP. (incorporated by
reference to Exhibit 2.1 to Western Gas Partners, LPs Current Report on Form 8-K filed on
August 5, 2010, File No. 001-34046). |
|
|
|
2.6
|
|
Purchase and Sale Agreement, dated as of January 14, 2011, by and among Western Gas Partners,
LP, Kerr-McGee Gathering LLC and Encana Oil & Gas (USA) Inc. (incorporated by reference to
Exhibit 2.1 to Western Gas Partners, LPs Current Report on Form 8-K filed on January 18, 2011
File No. 001-34046). |
|
|
|
3.1
|
|
Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to
Exhibit 3.1 to Western Gas Partners, LPs Registration Statement on Form S-1 filed on October
15, 2007, File No. 333-146700). |
|
|
|
3.2
|
|
First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP,
dated May 14, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LPs
Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046). |
|
|
|
3.3
|
|
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Western Gas
Partners, LP dated December 19, 2008 (incorporated by reference to Exhibit 3.1 to Western Gas
Partners, LPs Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046). |
|
|
|
3.4
|
|
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Western Gas
Partners, LP, dated as of April 15, 2009 (incorporated by reference to Exhibit 3.1 to Western
Gas Partners, LPs Current Report on Form 8-K filed on April 20, 2009, File No. 001-34046). |
|
|
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3.5
|
|
Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Western Gas
Partners, LP dated July 22, 2009 (incorporated by reference to Exhibit 3.1 to Western Gas
Partners, LPs Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046). |
47
|
|
|
3.6
|
|
Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Western Gas
Partners, LP dated January 29, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas
Partners, LPs Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046). |
|
|
|
3.7
|
|
Amendment No. 5 to First Amended and Restated Agreement of Limited Partnership of Western Gas
Partners, LP, dated August 2, 2010 (incorporated by reference to Exhibit 3.1 to Western Gas
Partners, LPs Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046). |
|
|
|
3.8
|
|
Amendment No. 6 to First Amended and Restated Agreement of Limited Partnership of Western Gas
Partners, LP, dated July 8, 2011 (incorporated by reference to Exhibit 3.1 to Western Gas
Partners, LPs Current Report on Form 8-K filed on July 8, 2011, File No. 001-34046). |
|
|
|
3.9
|
|
Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit
3.3 to Western Gas Partners, LPs Registration Statement on Form S-1 filed on October 15,
2007, File No. 333-146700). |
|
|
|
3.10
|
|
Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated
as of May 14, 2008 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LPs
Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046). |
|
|
|
4.1
|
|
Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to
Western Gas Partners, LPs Quarterly Report on Form 10-Q filed on June 13, 2008, File No.
001-34046). |
|
|
|
4.2
|
|
Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as Issuer, the
Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National
Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners,
LPs Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046). |
|
|
|
4.3
|
|
First Supplemental Indenture, dated as of May 18, 2011, among Western Gas Partners, LP, as
Issuer, the Subsidiary Guarantors named therein, as Guarantors, and Wells Fargo Bank, National
Association, as Trustee (incorporated by reference to Exhibit 4.2 to Western Gas Partners,
LPs Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046). |
|
|
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4.4
|
|
Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to Western Gas
Partners, LPs Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046). |
|
|
|
31.1*
|
|
Certification of Chief Executive Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
31.2*
|
|
Certification of Chief Financial Officer, pursuant to Rule 13a-14(a)/15d-14(a), as adopted
pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
|
|
|
32.1*
|
|
Certifications of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|
|
|
101.INS**
|
|
XBRL Instance Document |
|
|
|
101.SCH**
|
|
XBRL Schema Document |
|
|
|
101.CAL**
|
|
XBRL Calculation Linkbase Document |
|
|
|
101.LAB**
|
|
XBRL Label Linkbase Document |
|
|
|
101.PRE**
|
|
XBRL Presentation Linkbase Document |
|
|
|
101.DEF**
|
|
XBRL Definition Linkbase Document |
48
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
|
|
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|
|
WESTERN GAS PARTNERS, LP |
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|
August 4, 2011 |
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|
|
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|
/s/ Donald R. Sinclair |
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Donald R. Sinclair |
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President and Chief Executive Officer |
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Western Gas Holdings, LLC |
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(as general partner of Western Gas Partners, LP) |
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August 4, 2011 |
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/s/ Benjamin M. Fink |
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Benjamin M. Fink |
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Senior Vice President, Chief Financial Officer and Treasurer |
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Western Gas Holdings, LLC |
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(as general partner of Western Gas Partners, LP) |
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