þ
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
¨
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
Delaware
|
|
26-1075808
|
(State or other jurisdiction of incorporation or organization)
|
|
(I.R.S. Employer Identification No.)
|
|
|
|
1201 Lake Robbins Drive
The Woodlands, Texas
|
|
77380
|
(Address of principal executive offices)
|
|
(Zip Code)
|
Title of Each Class
Common Units Representing Limited Partner Interests
|
|
Name of Each Exchange on Which Registered
New York Stock Exchange
|
Large accelerated filer
þ
|
|
Accelerated filer
¨
|
|
Non-accelerated filer
¨
|
|
Smaller reporting company
¨
|
|
|
|
|
(Do not check if a smaller reporting company)
|
|
Item
|
|
Page
|
|
|
|
|
|
|
1 and 2.
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
1A.
|
||
1B.
|
||
3.
|
||
4.
|
||
|
|
|
|
|
|
|
|
|
5.
|
||
|
||
|
||
|
||
6.
|
||
7.
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
|
||
7A.
|
||
8.
|
||
9.
|
||
9A.
|
||
9B.
|
Item
|
|
Page
|
|
|
|
|
|
|
10.
|
||
11.
|
||
12.
|
||
13.
|
||
14.
|
||
|
|
|
|
|
|
|
|
|
15.
|
||
|
|
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|||
Natural gas gathering systems
|
|
13
|
|
|
1
|
|
|
5
|
|
Natural gas treating facilities
|
|
8
|
|
|
—
|
|
|
—
|
|
Natural gas processing facilities
|
|
8
|
|
|
3
|
|
|
—
|
|
NGL pipelines
|
|
3
|
|
|
—
|
|
|
—
|
|
Natural gas pipelines
|
|
3
|
|
|
—
|
|
|
—
|
|
Area
|
|
Asset Type
|
|
Miles of Pipeline
|
|
Approximate Number of Receipt Points
|
|
Gas Compression (Horsepower)
|
|
Processing or Treating Capacity (MMcf/d)
(1)
|
|
Average Gathering, Processing and Transportation Throughput (MMcf/d)
(2)
|
|||||
Rocky Mountains
|
|
Gathering, Processing and Treating
|
|
7,194
|
|
|
5,074
|
|
|
401,457
|
|
|
2,780
|
|
|
2,284
|
|
|
|
Transportation
|
|
1,192
|
|
|
25
|
|
|
30,002
|
|
|
—
|
|
|
79
|
|
Mid-Continent
|
|
Gathering
|
|
2,053
|
|
|
1,505
|
|
|
92,097
|
|
|
—
|
|
|
73
|
|
North-central Pennsylvania
|
|
Gathering
|
|
530
|
|
|
306
|
|
|
70,750
|
|
|
—
|
|
|
616
|
|
East Texas
|
|
Gathering and Treating
|
|
594
|
|
|
846
|
|
|
37,605
|
|
|
502
|
|
|
218
|
|
South and West Texas
|
|
Gathering, Processing and Treating
|
|
189
|
|
|
87
|
|
|
—
|
|
|
200
|
|
|
98
|
|
Total
|
|
|
|
11,752
|
|
|
7,843
|
|
|
631,911
|
|
|
3,482
|
|
|
3,368
|
|
(1)
|
Capacity excludes 170 MBbls/d of fractionation capacity.
|
(2)
|
Throughput includes 100% of Chipeta volumes, 50% of Newcastle volumes, 22% of Rendezvous volumes and 14.81% of Fort Union volumes. Throughput excludes
22
MBbls/d of average NGL pipeline volumes,
7
MBbls/d of average oil pipeline volumes representing our 10% share of average White Cliffs volumes, and 8 MBbls/d of average fractionated volumes representing our 25% share of average Mont Belvieu JV volumes. See
Properties
below for further descriptions of
these systems.
|
thousands except unit and percent amounts
|
|
Acquisition
Date
|
|
Percentage
Acquired
|
|
Borrowings
|
|
Cash
On Hand
|
|
Common
Units Issued
|
|
GP Units
Issued
|
|||||||
Non-Operated Marcellus Interest
(1)
|
|
03/01/2013
|
|
33.75
|
%
|
|
$
|
250,000
|
|
|
$
|
215,500
|
|
|
449,129
|
|
|
—
|
|
Anadarko-Operated Marcellus Interest
(2)
|
|
03/08/2013
|
|
33.75
|
%
|
|
133,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Mont Belvieu JV
(3)
|
|
06/05/2013
|
|
25
|
%
|
|
—
|
|
|
78,129
|
|
|
—
|
|
|
—
|
|
||
OTTCO
(4)
|
|
09/03/2013
|
|
100
|
%
|
|
27,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
We acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest.” In connection with the issuance of the common units, our general partner purchased 9,166 general partner units for consideration of $0.5 million in order to maintain its 2.0% general partner interest in us.
|
(2)
|
We acquired a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest.”
|
(3)
|
We acquired a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own two fractionators located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting.
|
(4)
|
We acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects our Red Desert and Granger complexes in southwestern Wyoming.
|
thousands except unit
and per-unit amounts
|
Common
Units Issued
(1)
|
|
GP Units
Issued
(2)
|
|
Price Per
Unit
|
|
Underwriting
Discount and
Other Offering
Expenses
|
|
Net
Proceeds
|
||||||||
May 2013 equity offering
|
7,015,000
|
|
|
143,163
|
|
|
$
|
61.18
|
|
|
$
|
13,203
|
|
|
$
|
424,733
|
|
December 2013 equity offering
(3)
|
4,500,000
|
|
|
91,837
|
|
|
61.51
|
|
|
8,716
|
|
|
273,728
|
|
(1)
|
Includes the issuance of
915,000
common units pursuant to the full exercise of the underwriters’ over-allotment option granted in connection with the May 2013 equity offering.
|
(2)
|
Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its
2.0%
general partner interest.
|
(3)
|
Excludes the issuance of 300,000 common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of 6,122 general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were $18.3 million.
|
•
|
Pursuing accretive acquisitions.
We expect to continue to pursue accretive acquisitions of midstream energy assets from Anadarko and third parties.
|
•
|
Capitalizing on organic growth opportunities.
We expect to grow certain of our systems organically over time by meeting Anadarko’s and our other customers’ midstream service needs that result from their drilling activity in our areas of operation. We continually evaluate economically attractive organic expansion opportunities in existing or new areas of operation that allow us to leverage our existing infrastructure, operating expertise and customer relationships by constructing and expanding systems to meet new or increased demand of our services.
|
•
|
Attracting third-party volumes to our systems.
We expect to continue to actively market our midstream services to, and pursue strategic relationships with, third-party producers and customers with the intention of attracting additional volumes and/or expansion opportunities.
|
•
|
Managing commodity price exposure.
We intend to continue limiting our direct exposure to commodity price changes and promote cash flow stability by pursuing a contract structure designed to mitigate exposure to commodity price uncertainty through the use of fee-based contracts and fixed-price hedges.
|
•
|
Maintaining investment grade ratings.
We intend to operate at appropriate leverage and distribution coverage levels in line with other partnerships in our sector that have received investment grade credit ratings. By maintaining an investment grade credit rating with all three credit rating agencies, in part through staying within leverage ratios appropriate for investment-grade partnerships, we believe that we will be able to pursue strategic acquisitions and large growth projects at a lower cost of fixed-income capital, which would enhance their accretion and overall return.
|
•
|
Affiliation with Anadarko.
We believe Anadarko is motivated to promote and support the successful execution of our business plan and to use its relationships throughout the energy industry, including those with producers and customers in the United States, to help pursue projects that help to enhance the value of our business. See
Our Relationship with Anadarko Petroleum Corporation
below.
|
•
|
Relatively stable and predictable cash flows.
Our cash flows are largely protected from fluctuations caused by commodity price volatility due to (i) the approximately three-fourths of our services that are provided pursuant to long-term, fee-based agreements and (ii) the commodity price swap agreements that limit our exposure to commodity price changes with respect to our percent-of-proceeds and keep-whole contracts. For the year ended
December 31, 2013
, 99% of our gross margin was derived from either long-term, fee-based contracts or from percent-of-proceeds or keep-whole agreements that were hedged with commodity price swap agreements.
|
•
|
Financial flexibility to pursue expansion and acquisition opportunities
.
We believe our operating cash flows, borrowing capacity, and access to debt and equity capital markets provide us with the financial flexibility to competitively pursue acquisition and expansion opportunities and to execute our strategy across capital market cycles. We currently have investment grade ratings from all three of the major rating agencies and, as of
December 31, 2013
, we had no outstanding borrowings under our $800.0 million senior unsecured revolving credit facility (“RCF”), and we had
$12.8 million
in outstanding letters of credit issued under the RCF.
|
•
|
Substantial presence in basins with strong producer economics.
Our portfolio includes midstream assets located in major onshore producing basins in Wyoming, Colorado, Utah, Kansas, Oklahoma, Pennsylvania, and Texas. Our interests in the Anadarko-Operated and Non-Operated Marcellus gathering systems serve dry gas production from the Marcellus shale, which provides attractive producer returns due to the overall scale and quality of the underlying resource, as well as its access to premium markets in the northeast United States. In addition, our Wattenberg, Platte Valley, and Brasada assets serve production in liquids-rich growth areas where the hydrocarbon production contains not only natural gas, but also oil, condensate, and significant amounts of NGLs. NGL prices have historically been correlated to crude oil prices as opposed to natural gas prices. Due to the relatively high current price of crude oil as compared to natural gas, production in these areas offers our customers higher margins and superior economics compared to basins in which the gas is predominantly dry. This pricing environment offers expansion opportunities for certain of our systems as producers attempt to increase their wet gas and crude oil production. See
Properties
below for further asset descriptions.
|
•
|
Well-positioned, well-maintained and efficient assets.
We believe that our asset portfolio across geographically diverse areas of operation provides us with opportunities to expand and attract additional volumes to our systems from multiple productive reservoirs. Moreover, our portfolio includes an integrated package of high-quality, well-maintained assets for which we have implemented modern processing, treating, measuring and operating technologies.
|
•
|
Consistent track record of accretive acquisitions.
Since our IPO in 2008, our management team has successfully executed eight related-party acquisitions and five third-party acquisitions, for an aggregate value of $2.9 billion. Our management team has demonstrated its ability to identify, evaluate, negotiate, consummate and integrate strategic acquisitions and expansion projects, and it intends to use its experience and reputation to continue to grow the Partnership through accretive acquisitions, focusing on opportunities to improve throughput volumes and cash flows.
|
•
|
Gathering.
At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures. In connection with our gathering services, we sometimes retain, stabilize and sell drip condensate, which falls out of the natural gas stream during gathering.
|
•
|
Compression.
Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered more efficiently and delivered into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.
|
•
|
Treating and dehydration.
To the extent that gathered natural gas contains contaminants, such as water vapor, carbon dioxide and/or hydrogen sulfide, such natural gas is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.
|
•
|
Processing.
Processing removes the heavier and more valuable hydrocarbon components, which are extracted as NGLs. The residue remaining after extraction of NGLs meets the quality standards for long-haul pipeline transportation or commercial use.
|
•
|
Fractionation.
Fractionation is the process of applying various levels of higher pressure and lower temperature to separate a stream of NGLs into ethane, propane, normal butane, isobutane and natural gasoline for end-use sale.
|
•
|
Storage, transportation and marketing.
Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts. We do not currently offer storage services or conduct marketing activities.
|
•
|
Fee-based.
Under fee-based arrangements, the service provider typically receives a fee for each unit of natural gas gathered, treated and/or processed at its facilities. As a result, the price per unit received by the service provider does not vary with commodity price changes, minimizing the service provider’s direct commodity price risk exposure.
|
•
|
Percent-of-proceeds, percent-of-value or percent-of-liquids.
Percent-of-proceeds, percent-of-value or percent-of-liquids arrangements may be used for gathering and processing services. Under these arrangements, the service provider typically remits to the producers either a percentage of the proceeds from the sale of residue and/or NGLs or a percentage of the actual residue and/or NGLs at the tailgate. These types of arrangements expose the processor to commodity price risk, as the revenues from the contracts directly correlate with the fluctuating price of natural gas and/or NGLs.
|
•
|
Keep-whole.
Keep-whole arrangements may be used for processing services. Under these arrangements, the service provider keeps 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, the processor compensates the producer for the amount of gas used and removed in processing by supplying additional gas or by paying an agreed-upon value for the gas utilized. These arrangements have the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are based on the price of NGLs.
|
•
|
Firm.
Firm transportation service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a demand or capacity reservation fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a usage fee based on the amount of natural gas transported.
|
•
|
Interruptible.
Interruptible transportation service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of gas actually transported. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and, as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline.
|
•
|
Colorado Interstate Gas Company (“CIG”);
|
•
|
Kinder Morgan Interstate Gas Transportation Company; and
|
•
|
Wyoming Interstate Gas Company.
|
•
|
CIG;
|
•
|
Tallgrass Interstate Gas Transmission, LLC; and
|
•
|
Wyoming Interstate Gas Company.
|
•
|
CIG;
|
•
|
The Kern River and Mountain Gas Transportation, Inc. (“MGTI”) pipelines via a connect with Rendezvous Pipeline Company;
|
•
|
Northwest Pipeline Co. (“NWPL”);
|
•
|
OTTCO; and
|
•
|
QEP Resources (“QEP”).
|
•
|
CIG;
|
•
|
Questar Pipeline Company; and
|
•
|
WIC.
|
•
|
Anadarko’s Wattenberg processing plant;
|
•
|
our Fort Lupton processing plant; and
|
•
|
our Platte Valley processing plant.
|
•
|
Atmos Texas pipeline;
|
•
|
Enbridge Pipelines (East Texas) LP pipeline;
|
•
|
Energy Transfer Fuels pipeline;
|
•
|
Enterprise Texas Pipeline, LP pipeline;
|
•
|
ETC Texas Pipeline, Ltd pipeline; and
|
•
|
Kinder Morgan Tejas pipeline.
|
•
|
Lancaster plant in the DJ Basin:
We are currently constructing a new cryogenic plant which will process production from the Niobrara and Codell formations in the Wattenberg field. The first train of the new plant has a capacity of 300 MMcf/d and is expected to begin service in the first quarter of 2014. Anadarko has agreed to a fee-based contract with a 10-year throughput guarantee of 270 MMcf/d, which will begin on the plant’s in-service date. A second train has been approved that will provide an additional 300 MMcf/d of capacity and is expected to be completed in the second quarter of 2015. Anadarko has agreed to a fee-based contract with a 10-year throughput guarantee of 200 MMcf/d, which will begin on the plant’s in-service date.
|
System
|
|
Competitor(s)
|
|
|
|
Anadarko-Operated Marcellus Interest gathering systems
|
|
PVR Midstream and National Fuel Gas Midstream
|
Bison treating facility
|
|
Thunder Creek Gas Services and Fort Union (treating only)
|
Brasada processing facility, pipeline and stabilization facility
|
|
Enterprise, Energy Transfer, and Kinder Morgan, Inc.
|
Chipeta processing complex
|
|
QEP and Kinder Morgan, Inc.
|
Dew and Pinnacle gathering systems and Pinnacle treating facility
|
|
ETC Texas Pipeline, Ltd., Enbridge Pipelines (East Texas) LP, XTO Energy and Kinder Morgan Tejas Pipeline, LP
|
Fort Union gathering system and treating facility
|
|
Bison treating facility (carbon dioxide treating services only), MIGC, Thunder Creek Gas Services, and TransCanada
|
Granger gathering system and processing complex
|
|
Williams Field Services, Enterprise/TEPPCO and QEP
|
Haley gathering system
|
|
Anadarko’s Delaware Basin Joint Venture, Enterprise GC, LP, Regency Gas Services, LP and Targa Midstream Services, LP
|
Helper and Clawson gathering systems and treating facilities
|
|
XTO Energy
|
Hilight gathering system and processing plant
|
|
DCP Midstream, ONEOK Gas Gathering Company, Thunder Creek Gas Services, Crestwood-Access, Tallgrass Energy Partners, and Rowdy Gathering Company
|
Hugoton gathering system
|
|
ONEOK Gas Gathering Company, DCP Midstream Partners, LP, Pioneer Natural Resources and Linn Energy
|
Mont Belvieu JV fractionation trains
|
|
Targa Resources LP, Phillips 66, Lone Star NGL LLC, and ONEOK Partners, LP
|
Newcastle gathering system and processing plant
|
|
DCP Midstream
|
Non-Operated Marcellus Interest gathering systems
|
|
PVR Midstream
|
Platte Valley gathering system and processing plant
|
|
DCP Midstream and AKA Energy
|
Red Desert gathering system and processing complex
|
|
Williams Field Services and QEP
|
Rendezvous gathering system
|
|
Enterprise/TEPPCO
|
Wattenberg gathering system and processing plant
|
|
DCP Midstream and AKA Energy
|
•
|
rates, services, and terms and conditions of service;
|
•
|
types of services MIGC may offer to its customers;
|
•
|
certification and construction of new facilities;
|
•
|
acquisition, extension, disposition or abandonment of facilities;
|
•
|
maintenance of accounts and records;
|
•
|
internet posting requirements for available capacity, discounts and other matters;
|
•
|
pipeline segmentation to allow multiple simultaneous shipments under the same contract;
|
•
|
capacity release to create a secondary market for MIGC’s transportation services;
|
•
|
relationships between affiliated companies involved in certain aspects of the natural gas business;
|
•
|
initiation and discontinuation of services;
|
•
|
market manipulation in connection with interstate sales, purchases or transportation of natural gas and NGLs; and
|
•
|
participation by interstate pipelines in cash management arrangements.
|
•
|
requiring the acquisition of various permits to conduct regulated activities;
|
•
|
requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;
|
•
|
limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
|
•
|
requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by our operations or attributable to former operations; and
|
•
|
imposing substantial liabilities for pollution resulting from our midstream activities.
|
•
|
our ability to pay distributions to our unitholders;
|
•
|
our and Anadarko’s assumptions about the energy market;
|
•
|
future throughput, including Anadarko’s production, which is gathered or processed by or transported through our assets;
|
•
|
operating results;
|
•
|
competitive conditions;
|
•
|
technology;
|
•
|
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;
|
•
|
supply of, demand for, and the price of, oil, natural gas, NGLs and related products or services;
|
•
|
weather;
|
•
|
inflation;
|
•
|
availability of goods and services;
|
•
|
general economic conditions, either internationally or domestically or in the jurisdictions in which we are doing business;
|
•
|
changes in regulations at the federal, state and local level or the inability to timely obtain or maintain permits that could affect our and our customers’ activities; environmental risks; regulations by 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 Anadarko;
|
•
|
changes in Anadarko’s capital program, strategy or desired areas of focus;
|
•
|
our commitments to capital projects;
|
•
|
ability to use our RCF;
|
•
|
creditworthiness of Anadarko or our other counterparties, including financial institutions, operating partners and other parties;
|
•
|
our ability to repay debt;
|
•
|
our ability to mitigate commodity price risks inherent in our percent-of-proceeds and keep-whole contracts;
|
•
|
conflicts of interest among us, our general partner, WGP and its general partner, and affiliates, including Anadarko;
|
•
|
our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;
|
•
|
our ability to acquire assets on acceptable terms;
|
•
|
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;
|
•
|
timing, amount and terms of future issuances of equity and debt securities; and
|
•
|
other factors discussed below and elsewhere in this Item 1A, under the caption Critical Accounting Policies and Estimates included under Item 7 of this Form 10-K, and in our other public filings and press releases.
|
•
|
the volatility of natural gas and oil prices, which could have a negative effect on the value of Anadarko’s oil and natural gas properties, its drilling programs or its ability to finance its operations;
|
•
|
the availability of capital on an economic basis to fund Anadarko’s exploration and development activities;
|
•
|
a reduction in or reallocation of Anadarko’s capital budget, which could reduce the gathering, transportation and treating volumes available to us as a midstream operator, limit our midstream opportunities for organic growth or limit the inventory of midstream assets we may acquire from Anadarko;
|
•
|
Anadarko’s ability to replace reserves;
|
•
|
Anadarko’s operations in foreign countries, which are subject to political, economic and other uncertainties;
|
•
|
Anadarko’s drilling and operating risks, including potential environmental liabilities;
|
•
|
transportation capacity constraints and interruptions;
|
•
|
adverse effects of governmental and environmental regulation; and
|
•
|
adverse effects from current or future litigation, including the Tronox Adversary Proceeding, as defined and described in
Note 17—Contingencies—Tronox Litigation
in the
Notes to the Consolidated Financial Statements
under Item 8 of Anadarko’s Form 10-K for the year ended December 31, 2013 (which is not, and shall not be deemed to be, incorporated by reference herein).
|
•
|
the prices of, level of production of, and demand for natural gas;
|
•
|
the volume of natural gas we gather, compress, process, treat and transport;
|
•
|
the volumes and prices of NGLs and condensate that we retain and sell;
|
•
|
demand charges and volumetric fees associated with our transportation services;
|
•
|
the level of competition from other midstream energy companies;
|
•
|
regulatory action affecting the supply of or demand for natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
|
•
|
prevailing economic conditions.
|
•
|
the level of capital expenditures we make;
|
•
|
the level of our operating and maintenance and general and administrative costs;
|
•
|
our debt service requirements and other liabilities;
|
•
|
fluctuations in our working capital needs;
|
•
|
our ability to borrow funds and access capital markets;
|
•
|
our treatment as a flow-through entity for U.S. federal income tax purposes;
|
•
|
restrictions contained in debt agreements to which we are a party; and
|
•
|
the amount of cash reserves established by our general partner.
|
•
|
domestic and worldwide economic conditions;
|
•
|
weather conditions and seasonal trends;
|
•
|
the ability to develop recently discovered fields or deploy new technologies to existing fields;
|
•
|
the levels of domestic production and consumer demand, as affected by, among other things, concerns over inflation, geopolitical issues and the availability and cost of credit;
|
•
|
the availability of imported or a market for exported liquefied natural gas (“LNG”);
|
•
|
the availability of transportation systems with adequate capacity;
|
•
|
the volatility and uncertainty of regional pricing differentials such as in the Mid-Continent or Rocky Mountains;
|
•
|
the price and availability of alternative fuels;
|
•
|
the effect of energy conservation measures;
|
•
|
the nature and extent of governmental regulation and taxation; and
|
•
|
the anticipated future prices of natural gas, NGLs and other commodities.
|
•
|
incur additional indebtedness or guarantee other indebtedness;
|
•
|
grant liens to secure obligations other than our obligations under the Notes or RCF or agree to restrictions on our ability to grant additional liens to secure our obligations under the Notes or RCF;
|
•
|
engage in transactions with affiliates;
|
•
|
make any material change to the nature of our business from the midstream energy business; or
|
•
|
enter into a merger, consolidate, liquidate, wind up or dissolve.
|
•
|
our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
|
•
|
our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;
|
•
|
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
|
•
|
our flexibility in responding to changing business and economic conditions may be limited.
|
•
|
mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;
|
•
|
an inability to successfully integrate the acquired assets or businesses;
|
•
|
the assumption of unknown liabilities;
|
•
|
limitations on rights to indemnity from the seller;
|
•
|
mistaken assumptions about the overall costs of equity or debt;
|
•
|
the diversion of management’s and employees’ attention from other business concerns;
|
•
|
unforeseen difficulties operating in new geographic areas; and
|
•
|
customer or key employee losses at the acquired businesses.
|
•
|
rates, services and terms and conditions of service;
|
•
|
the certification and construction of new facilities;
|
•
|
the acquisition, extension, disposition or abandonment of facilities;
|
•
|
the maintenance of accounts and records;
|
•
|
relationships between affiliated companies involved in certain aspects of the natural gas business; and
|
•
|
market manipulation in connection with interstate sales, purchases or transportation of natural gas.
|
•
|
perform ongoing assessments of pipeline integrity;
|
•
|
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
|
•
|
improve data collection, integration and analysis;
|
•
|
repair and remediate the pipeline as necessary; and
|
•
|
implement preventive and mitigating actions.
|
•
|
the federal Clean Air Act and analogous state laws that impose obligations related to emissions of air pollutants;
|
•
|
the federal Comprehensive Environmental Response, Compensation and Liability Act and analogous state laws that require and regulate the cleanup of hazardous substances that have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal;
|
•
|
the federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws that regulate discharges from our facilities into state and federal waters, including wetlands;
|
•
|
the federal Resources Conservation and Recovery Act and analogous state laws that impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities; and
|
•
|
the federal Toxic Substances Control Act and analogous state laws that impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.
|
•
|
damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;
|
•
|
inadvertent damage from construction, farm and utility equipment;
|
•
|
leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities;
|
•
|
leaks of natural gas containing hazardous quantities of hydrogen sulfide from our Pinnacle gathering system or Bethel treating facility;
|
•
|
fires and explosions; and
|
•
|
other hazards that could also result in personal injury, loss of life, pollution, natural resource damages and/or suspension of operations.
|
•
|
Neither our partnership agreement nor any other agreement requires Anadarko to pursue a business strategy that favors us.
|
•
|
Anadarko is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.
|
•
|
Our general partner is allowed to take into account the interests of parties other than us, such as Anadarko, in resolving conflicts of interest.
|
•
|
The officers of our general partner will also devote significant time to the business of Anadarko and will be compensated by Anadarko accordingly.
|
•
|
Our partnership agreement limits the liability of and reduces the default state law fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under state law.
|
•
|
Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
|
•
|
Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.
|
•
|
Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner.
|
•
|
Our general partner determines which costs incurred by it are reimbursable by us.
|
•
|
Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make IDR payments.
|
•
|
Our partnership agreement permits us to classify up to $31.8 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the IDRs.
|
•
|
Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.
|
•
|
Our general partner intends to limit its liability regarding our contractual and other obligations.
|
•
|
Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.
|
•
|
Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.
|
•
|
Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
|
•
|
Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to the IDRs without the approval of the special committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
|
•
|
how to allocate corporate opportunities among us and its affiliates;
|
•
|
whether to exercise its limited call right;
|
•
|
how to exercise its voting rights with respect to the units it owns;
|
•
|
whether to exercise its registration rights;
|
•
|
whether to elect to reset target distribution levels; and
|
•
|
whether to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.
|
•
|
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
|
•
|
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of the Partnership;
|
•
|
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
|
•
|
provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is any of the following:
|
(a)
|
approved by the special committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
|
(b)
|
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;
|
(c)
|
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
|
(d)
|
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
|
•
|
our existing unitholders’ proportionate ownership interest in us will decrease;
|
•
|
the amount of cash available for distribution on each unit may decrease;
|
•
|
the ratio of taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding unit may be diminished; and
|
•
|
the market price of the common units may decline.
|
•
|
we were conducting business in a state but had not complied with that particular state’s partnership statute; or
|
•
|
such unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
|
•
|
changes in securities analysts’ recommendations regarding Anadarko or us and their estimates of Anadarko’s and our financial performance;
|
•
|
the public’s reaction to Anadarko’s or our press releases, announcements and filings with the SEC;
|
•
|
legislative or regulatory changes affecting our status as a partnership for federal income tax purposes;
|
•
|
fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly traded limited partnerships;
|
•
|
changes in market valuations of similar companies;
|
•
|
departures of key personnel;
|
•
|
commencement of or involvement in litigation;
|
•
|
variations in our quarterly results of operations or those of midstream companies;
|
•
|
variations in the amount of our quarterly cash distributions;
|
•
|
future issuances and sales of our common units; and
|
•
|
changes in general conditions in the U.S. economy, financial markets or the midstream industry.
|
|
Fourth
Quarter
|
|
Third
Quarter
|
|
Second
Quarter
|
|
First
Quarter
|
||||||||
2013
|
|
|
|
|
|
|
|
||||||||
High Price
|
$
|
64.07
|
|
|
$
|
65.16
|
|
|
$
|
65.11
|
|
|
$
|
59.81
|
|
Low Price
|
$
|
57.54
|
|
|
$
|
54.58
|
|
|
$
|
55.57
|
|
|
$
|
46.82
|
|
Distribution per common unit
|
$
|
0.60
|
|
|
$
|
0.58
|
|
|
$
|
0.56
|
|
|
$
|
0.54
|
|
2012
|
|
|
|
|
|
|
|
||||||||
High Price
|
$
|
53.17
|
|
|
$
|
51.28
|
|
|
$
|
47.50
|
|
|
$
|
47.97
|
|
Low Price
|
$
|
45.10
|
|
|
$
|
43.29
|
|
|
$
|
41.15
|
|
|
$
|
38.94
|
|
Distribution per common unit
|
$
|
0.52
|
|
|
$
|
0.50
|
|
|
$
|
0.48
|
|
|
$
|
0.46
|
|
|
|
Total Quarterly Distribution
Target Amount
|
|
Marginal Percentage
Interest in Distributions
|
||
|
|
|
Unitholders
|
|
General Partner
|
|
Minimum quarterly distribution
|
|
$0.300
|
|
98.0%
|
|
2.0%
|
First target distribution
|
|
up to $0.345
|
|
98.0%
|
|
2.0%
|
Second target distribution
|
|
above $0.345 up to $0.375
|
|
85.0%
|
|
15.0%
|
Third target distribution
|
|
above $0.375 up to $0.450
|
|
75.0%
|
|
25.0%
|
Thereafter
|
|
above $0.450
|
|
50.0%
|
|
50.0%
|
(1)
|
Income earned by the Partnership, a non-taxable entity for U.S. federal income tax purposes, on the date of and subsequent to our acquisition of the Partnership assets from Anadarko, except for the Chipeta assets, was subject only to Texas margin tax, while income earned prior to our acquisition of the Partnership assets, except for the Chipeta assets, was subject to federal and state income tax. Income attributable to Chipeta was subject to federal and state income tax prior to June 1, 2008, at which time substantially all of the Chipeta assets were contributed to a non-taxable entity for U.S. federal income tax purposes. See
Note 1—Summary of Significant Accounting Policies
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(2)
|
Adjusted EBITDA attributable to Western Gas Partners, LP (“Adjusted EBITDA”) and Distributable cash flow are not defined in the generally accepted accounting principles in the United States (“GAAP”). For descriptions and reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see the caption
How We Evaluate Our Operations
under Item 7 of this Form 10-K.
|
(3)
|
Net income earned on and subsequent to the date of our 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. Prior to our acquisition of the Partnership assets, all income is attributed to Anadarko. All subordinated units were converted into common units on August 15, 2011, on a one-for-one basis. For purposes of calculating net income per common and subordinated unit, the conversion of the subordinated units is deemed to have occurred on July 1, 2011. See
Note 4—Equity and Partners’ Capital
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(4)
|
Excludes average NGL pipeline volumes of
22
MBbls/d,
25
MBbls/d,
24
MBbls/d, 14 MBbls/d and 11 MBbls/d for the years ended December 31,
2013
,
2012
,
2011
,
2010
and
2009
, respectively. Includes 100% of Wattenberg system volumes for all periods presented, throughput beginning March 2013 attributable to the Anadarko-Operated Marcellus Interest, and throughput beginning September 2013 attributable to OTTCO.
|
(5)
|
Consists of 100% of Chipeta and Hilight system volumes, 100% of the Granger and Red Desert complex volumes, 50% of Newcastle volumes, and throughput beginning March 2011 attributable to the Platte Valley system.
|
(6)
|
Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes. Excludes
7
MBbls/d,
6
MBbls/d,
4
MBbls/d and 3 MBbls/d of average oil pipeline volumes for the years ended December 31,
2013
,
2012
,
2011
and
2010
, respectively, representing our 10% share of average White Cliffs pipeline volumes (our 0.4% share of White Cliffs volumes for 2009 was not material) and excludes 8 MBbls/d of average fractionated volumes for the year ended December 31,
2013
, representing our 25% share of average Mont Belvieu JV volumes.
|
(7)
|
Average for period. Calculated as gross margin (total revenues less cost of product) divided by total throughput (excluding throughput measured in barrels), including 100% of gross margin and volumes attributable to Chipeta, our 14.81% interest in income and volumes attributable to Fort Union and our 22% interest in income and volumes attributable to Rendezvous. Gross margin also includes 100% of gross margin attributable to our NGL pipelines, our 10% interest in income attributable to White Cliffs, and our 25% interest in income attributable to the Mont Belvieu JV.
|
(8)
|
Calculated as described in footnote seven above, except also excludes the noncontrolling interest owners’ proportionate share of revenues, cost of product and throughput.
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|||
Natural gas gathering systems
|
|
13
|
|
|
1
|
|
|
5
|
|
Natural gas treating facilities
|
|
8
|
|
|
—
|
|
|
—
|
|
Natural gas processing facilities
|
|
8
|
|
|
3
|
|
|
—
|
|
NGL pipelines
|
|
3
|
|
|
—
|
|
|
—
|
|
Natural gas pipelines
|
|
3
|
|
|
—
|
|
|
—
|
|
•
|
We issued $250.0 million aggregate principal amount of 2.600% Senior Notes due 2018. Net proceeds were used to repay amounts then outstanding under our revolving credit facility. See
Liquidity and Capital Resources
within this Item 7 for additional information.
|
•
|
We completed construction and commenced operations in June 2013 of the 200 MMcf/d Brasada processing and stabilization facility in the Eagleford shale area of South Texas.
|
•
|
We announced a project to expand the processing capacity at our Lancaster plant by another 300 MMcf/d with a second cryogenic processing train. The expansion project is currently under construction.
|
•
|
We completed the following acquisitions: (i) Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems in north-central Pennsylvania, (ii) a third party’s 33.75% interest (operated by Anadarko) in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, also in north-central Pennsylvania, (iii) a 25% interest in the Mont Belvieu JV, an entity formed to design, construct and own two NGL fractionation trains located in Mont Belvieu, Texas, and (iv) Overland Trail Transmission, LLC, which owns and operates a natural gas pipeline connecting our Red Desert and Granger complexes in southwestern Wyoming. See
Acquisitions
under Items 1 and 2 of this Form 10-K for additional information.
|
•
|
We issued
12,200,735
common units to the public, generating net proceeds of
$740.3 million
, including the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Net proceeds were used to repay a portion of the amount outstanding under our revolving credit facility, with the remaining net proceeds used for general partnership purposes, including the funding of capital expenditures.
|
•
|
We raised our distribution to
$0.60
per unit for the
fourth
quarter of
2013
, representing a
3%
increase
over the distribution for the third quarter of 2013, a
15%
increase
over the distribution for the
fourth
quarter of
2012
, and our nineteenth consecutive quarterly increase.
|
•
|
Throughput attributable to Western Gas Partners, LP totaled
3,200
MMcf/d for the
year ended December 31, 2013
, representing a
14%
increase
compared to the year ended December 31, 2012.
|
•
|
Gross margin (total revenues less cost of product) attributable to Western Gas Partners, LP averaged
$0.58
per Mcf for the
year ended December 31, 2013
, representing a
7%
increase
compared to the
year ended December 31, 2012
.
|
•
|
expenses associated with annual and quarterly reporting;
|
•
|
tax return and Schedule K-1 preparation and distribution expenses;
|
•
|
expenses associated with listing on the New York Stock Exchange; and
|
•
|
independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.
|
•
|
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.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Reconciliation of Adjusted EBITDA to Net income attributable to Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
457,773
|
|
|
$
|
377,929
|
|
|
$
|
361,653
|
|
Less:
|
|
|
|
|
|
|
||||||
Distributions from equity investees
|
|
22,136
|
|
|
20,660
|
|
|
15,999
|
|
|||
Non-cash equity-based compensation expense
(1)
|
|
3,575
|
|
|
73,508
|
|
|
13,754
|
|
|||
Interest expense
|
|
51,797
|
|
|
42,060
|
|
|
30,345
|
|
|||
Income tax expense
|
|
4,431
|
|
|
20,715
|
|
|
32,150
|
|
|||
Depreciation, amortization and impairments
(2)
|
|
143,375
|
|
|
118,279
|
|
|
110,380
|
|
|||
Other expense
(2)
|
|
175
|
|
|
1,665
|
|
|
3,683
|
|
|||
Add:
|
|
|
|
|
|
|
||||||
Equity income, net
|
|
23,732
|
|
|
16,111
|
|
|
11,261
|
|
|||
Interest income, net – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
24,106
|
|
|||
Other income
(2) (3)
|
|
419
|
|
|
368
|
|
|
2,049
|
|
|||
Income tax benefit
|
|
1,801
|
|
|
—
|
|
|
—
|
|
|||
Net income attributable to Western Gas Partners, LP
|
|
$
|
275,136
|
|
|
$
|
134,421
|
|
|
$
|
192,758
|
|
Reconciliation of Adjusted EBITDA to Net cash provided by operating activities
|
|
|
|
|
|
|
||||||
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
457,773
|
|
|
$
|
377,929
|
|
|
$
|
361,653
|
|
Adjusted EBITDA attributable to noncontrolling interests
|
|
13,348
|
|
|
17,214
|
|
|
16,850
|
|
|||
Interest income (expense), net
|
|
(34,897
|
)
|
|
(25,160
|
)
|
|
(6,239
|
)
|
|||
Non-cash equity based compensation expense
(1)
|
|
(54
|
)
|
|
(69,791
|
)
|
|
(10,264
|
)
|
|||
Debt-related amortization and other items, net
|
|
2,449
|
|
|
2,319
|
|
|
3,110
|
|
|||
Current income tax (benefit) expense
|
|
(2,944
|
)
|
|
9,398
|
|
|
(15,570
|
)
|
|||
Other income (expense), net
(3)
|
|
253
|
|
|
(1,292
|
)
|
|
(1,628
|
)
|
|||
Distributions from equity investees less than (in excess of) equity income, net
|
|
1,596
|
|
|
(4,549
|
)
|
|
(4,738
|
)
|
|||
Changes in operating working capital:
|
|
|
|
|
|
|
||||||
Accounts receivable and natural gas imbalance receivable
|
|
(35,934
|
)
|
|
23,520
|
|
|
(47,415
|
)
|
|||
Accounts payable, accrued liabilities and natural gas imbalance payable
|
|
21,952
|
|
|
5,045
|
|
|
30,884
|
|
|||
Other
|
|
(7,821
|
)
|
|
3,393
|
|
|
(13,805
|
)
|
|||
Net cash provided by operating activities
|
|
$
|
415,721
|
|
|
$
|
338,026
|
|
|
$
|
312,838
|
|
Cash flow information of Western Gas Partners, LP
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
415,721
|
|
|
$
|
338,026
|
|
|
$
|
312,838
|
|
Net cash used in investing activities
|
|
$
|
(1,416,066
|
)
|
|
$
|
(1,249,942
|
)
|
|
$
|
(479,722
|
)
|
Net cash provided by financing activities
|
|
$
|
681,092
|
|
|
$
|
1,105,338
|
|
|
$
|
366,369
|
|
(1)
|
For the year ended December 31, 2012, includes $69.8 million of equity-based compensation associated with the Western Gas Holdings, LLC Equity Incentive Plan, as amended and restated (the “Incentive Plan”) (as defined and described in
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K), paid and contributed by Anadarko.
|
(2)
|
Includes our 51% share prior to August 1, 2012, and our 75% share after August 1, 2012, of depreciation, amortization and impairments; other expense; and other income attributable to Chipeta. See
Note 2—Acquisitions
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(3)
|
Excludes income of
$1.6 million
for each of the
years ended December 31, 2013
,
2012
and
2011
, related to a component of a gas processing agreement accounted for as a capital lease.
|
|
|
Year Ended December 31,
|
||||||||||
thousands except Coverage ratio
|
|
2013
|
|
2012
|
|
2011
|
||||||
Reconciliation of Distributable cash flow to Net income attributable to Western Gas Partners, LP and calculation of the Coverage ratio
|
|
|
|
|
|
|
||||||
Distributable cash flow
|
|
$
|
380,529
|
|
|
$
|
309,945
|
|
|
$
|
319,294
|
|
Less:
|
|
|
|
|
|
|
||||||
Distributions from equity investees
|
|
22,136
|
|
|
20,660
|
|
|
15,999
|
|
|||
Non-cash equity-based compensation expense
(1)
|
|
3,575
|
|
|
73,508
|
|
|
13,754
|
|
|||
Interest expense, net (non-cash settled)
|
|
—
|
|
|
326
|
|
|
—
|
|
|||
Income tax expense
|
|
2,630
|
|
|
20,715
|
|
|
32,150
|
|
|||
Depreciation, amortization and impairments
(2)
|
|
143,375
|
|
|
118,279
|
|
|
110,380
|
|
|||
Other expense
(1)
|
|
175
|
|
|
1,665
|
|
|
3,683
|
|
|||
Add:
|
|
|
|
|
|
|
||||||
Equity income, net
|
|
23,732
|
|
|
16,111
|
|
|
11,261
|
|
|||
Cash paid for maintenance capital expenditures
(2) (3)
|
|
29,850
|
|
|
36,459
|
|
|
28,304
|
|
|||
Capitalized interest
|
|
11,945
|
|
|
6,196
|
|
|
420
|
|
|||
Cash paid for income taxes
|
|
552
|
|
|
495
|
|
|
190
|
|
|||
Other income
(2) (4)
|
|
419
|
|
|
368
|
|
|
2,049
|
|
|||
Interest income, net (non-cash settled)
|
|
—
|
|
|
—
|
|
|
7,206
|
|
|||
Net income attributable to Western Gas Partners, LP
|
|
$
|
275,136
|
|
|
$
|
134,421
|
|
|
$
|
192,758
|
|
|
|
|
|
|
|
|
||||||
Distributions declared
(5)
|
|
|
|
|
|
|
||||||
Limited partners
|
|
$
|
255,308
|
|
|
|
|
|
||||
General partner
|
|
70,745
|
|
|
|
|
|
|||||
Total
|
|
$
|
326,053
|
|
|
|
|
|
||||
Coverage ratio
|
|
1.17
|
|
x
|
|
|
|
(1)
|
For the year ended December 31, 2012, includes $69.8 million of equity-based compensation associated with the Incentive Plan (as defined and described in
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K), paid and contributed by Anadarko.
|
(2)
|
Includes our 51% share prior to August 1, 2012, and our 75% share after August 1, 2012, of depreciation, amortization and impairments; other expense; cash paid for maintenance capital expenditures; and other income attributable to Chipeta. See
Note 2—Acquisitions
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(3)
|
Net of a prior period adjustment reclassifying $0.7 million from capital expenditures to operating expenses for the
year ended December 31, 2012
.
|
(4)
|
Excludes income of
$1.6 million
for each of the
years ended December 31, 2013
,
2012
and
2011
, related to a component of a gas processing agreement accounted for as a capital lease. See
Note 2—Acquisitions
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(5)
|
Reflects distributions of
$2.28
per unit declared for the
year ended December 31, 2013
.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
General and administrative expenses
|
|
$
|
16,882
|
|
|
$
|
14,904
|
|
|
$
|
11,754
|
|
Public company expenses
|
|
7,152
|
|
|
6,830
|
|
|
7,735
|
|
|||
Total reimbursement
|
|
$
|
24,034
|
|
|
$
|
21,734
|
|
|
$
|
19,489
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
$
|
482,542
|
|
|
$
|
382,330
|
|
|
$
|
347,469
|
|
Natural gas, natural gas liquids and condensate sales
|
|
541,244
|
|
|
508,339
|
|
|
502,383
|
|
|||
Equity income and other, net
|
|
29,709
|
|
|
19,918
|
|
|
19,553
|
|
|||
Total revenues
(1)
|
|
1,053,495
|
|
|
910,587
|
|
|
869,405
|
|
|||
Total operating expenses
(1)
|
|
731,853
|
|
|
715,693
|
|
|
624,111
|
|
|||
Operating income
|
|
321,642
|
|
|
194,894
|
|
|
245,294
|
|
|||
Interest income, net – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
24,106
|
|
|||
Interest expense
|
|
(51,797
|
)
|
|
(42,060
|
)
|
|
(30,345
|
)
|
|||
Other income (expense), net
|
|
1,837
|
|
|
292
|
|
|
(44
|
)
|
|||
Income before income taxes
|
|
288,582
|
|
|
170,026
|
|
|
239,011
|
|
|||
Income tax expense
|
|
2,630
|
|
|
20,715
|
|
|
32,150
|
|
|||
Net income
|
|
285,952
|
|
|
149,311
|
|
|
206,861
|
|
|||
Net income attributable to noncontrolling interests
|
|
10,816
|
|
|
14,890
|
|
|
14,103
|
|
|||
Net income attributable to Western Gas Partners, LP
|
|
$
|
275,136
|
|
|
$
|
134,421
|
|
|
$
|
192,758
|
|
Key performance metrics
(2)
|
|
|
|
|
|
|
||||||
Gross margin
|
|
$
|
689,210
|
|
|
$
|
574,508
|
|
|
$
|
542,034
|
|
Adjusted EBITDA attributable to Western Gas Partners, LP
|
|
$
|
457,773
|
|
|
$
|
377,929
|
|
|
$
|
361,653
|
|
Distributable cash flow
|
|
$
|
380,529
|
|
|
$
|
309,945
|
|
|
$
|
319,294
|
|
(1)
|
Revenues include amounts earned from services provided to our affiliates, as well as from the sale of residue, 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 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(2)
|
Gross margin, Adjusted EBITDA and Distributable cash flow are defined under the caption
How We Evaluate Our Operations—Non-GAAP financial measures
within this Item 7
.
For reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see
How We Evaluate Our Operations—Reconciliation to GAAP Measures
within this Item 7.
|
|
|
Year Ended December 31,
|
|||||||||||||
MMcf/d
|
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
|||||
Gathering, treating and transportation
(1)
|
|
1,803
|
|
|
1,601
|
|
|
13
|
%
|
|
1,555
|
|
|
3
|
%
|
Processing
(2)
|
|
1,359
|
|
|
1,187
|
|
|
14
|
%
|
|
962
|
|
|
23
|
%
|
Equity investment
(3)
|
|
206
|
|
|
235
|
|
|
(12
|
)%
|
|
198
|
|
|
19
|
%
|
Total throughput
(4)
|
|
3,368
|
|
|
3,023
|
|
|
11
|
%
|
|
2,715
|
|
|
11
|
%
|
Throughput attributable to noncontrolling interests
|
|
168
|
|
|
228
|
|
|
(26
|
)%
|
|
242
|
|
|
(6
|
)%
|
Total throughput attributable to Western Gas Partners, LP
|
|
3,200
|
|
|
2,795
|
|
|
14
|
%
|
|
2,473
|
|
|
13
|
%
|
(1)
|
Excludes average NGL pipeline vo
lumes of
22
MBbls/d,
25
MBbls/d and
24
MBbls/d for the
years ended December 31, 2013
,
2012
and
2011
, respectively. Includes 100% of Wattenberg system volumes for all periods presented, throughput beginning March 2013 attributable to the Anadarko-Operated Marcellus Interest, and throughput beginning September 2013 attributable to the Overland Trail Transmission, LLC (“OTTCO”).
|
(2)
|
Consists of 100% of Chipeta, Hilight and Platte Valley system volumes, 100% of the Granger and Red Desert complex volumes, and 50% of Newcastle volumes.
|
(3)
|
Represents our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes. Excludes our 10% share of average White Cliffs
pipeline volumes consisting of
7
MBbls/d,
6
MBbls/d and
4
MBbls/d for the
years ended December 31, 2013
,
2012
and
2011
, respectively, and for the
year ended December 31, 2013
, excludes 8 MBbls/d of average fractionated volumes, representing our 25% share of average fractionated Mont Belvieu JV volumes.
|
(4)
|
Includes affiliate, third-party and equity-investment volumes (as equity-investment volumes are defined in the above footnote).
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
||||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
$
|
482,542
|
|
|
$
|
382,330
|
|
|
26
|
%
|
|
$
|
347,469
|
|
|
10
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and per-unit amounts
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
|||||||||
Natural gas sales
|
|
$
|
118,134
|
|
|
$
|
101,116
|
|
|
17
|
%
|
|
$
|
129,939
|
|
|
(22
|
)%
|
Natural gas liquids sales
|
|
391,608
|
|
|
377,377
|
|
|
4
|
%
|
|
345,375
|
|
|
9
|
%
|
|||
Drip condensate sales
|
|
31,502
|
|
|
29,846
|
|
|
6
|
%
|
|
27,069
|
|
|
10
|
%
|
|||
Total
|
|
$
|
541,244
|
|
|
$
|
508,339
|
|
|
6
|
%
|
|
$
|
502,383
|
|
|
1
|
%
|
Average price per unit:
|
|
|
|
|
|
|
|
|
|
|
||||||||
Natural gas (per Mcf)
|
|
$
|
4.58
|
|
|
$
|
4.24
|
|
|
8
|
%
|
|
$
|
5.32
|
|
|
(20
|
)%
|
Natural gas liquids (per Bbl)
|
|
$
|
47.69
|
|
|
$
|
48.22
|
|
|
(1
|
)%
|
|
$
|
47.44
|
|
|
2
|
%
|
Drip condensate (per Bbl)
|
|
$
|
76.62
|
|
|
$
|
75.88
|
|
|
1
|
%
|
|
$
|
73.60
|
|
|
3
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
||||||||
Equity income
|
|
$
|
23,732
|
|
|
$
|
16,111
|
|
|
47
|
%
|
|
$
|
11,261
|
|
|
43
|
%
|
Other revenues, net
|
|
5,977
|
|
|
3,807
|
|
|
57
|
%
|
|
8,292
|
|
|
(54
|
)%
|
|||
Total
|
|
$
|
29,709
|
|
|
$
|
19,918
|
|
|
49
|
%
|
|
$
|
19,553
|
|
|
2
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
||||||||
Cost of product
|
|
$
|
364,285
|
|
|
$
|
336,079
|
|
|
8
|
%
|
|
$
|
327,371
|
|
|
3
|
%
|
Operation and maintenance
|
|
168,657
|
|
|
140,106
|
|
|
20
|
%
|
|
126,464
|
|
|
11
|
%
|
|||
Total cost of product and operation and maintenance expenses
|
|
$
|
532,942
|
|
|
$
|
476,185
|
|
|
12
|
%
|
|
$
|
453,835
|
|
|
5
|
%
|
•
|
an $11.6 million net increase in residue purchases primarily at the Wattenberg system and the Red Desert complex, partially offset by decreases at the Platte Valley system and the Granger complex; and
|
•
|
a $10.7 million net increase in NGL purchases primarily at the Red Desert complex, the Hilight system, and the Wattenberg system, partially offset by decreases at Chipeta, the Platte Valley system, and the Granger complex.
|
•
|
a $22.8 million net increase in NGL purchases primarily at Chipeta, the Hilight system, and the Wattenberg system due to volume fluctuations noted in
Throughput
and
Natural Gas, Natural Gas Liquids and Condensate Sales
within this Item 7, and an increase for the MGR assets as a result of entering into commodity price swap agreements that became effective in January 2012, partially offset by a decrease at the Platte Valley system due to lower pricing subsequent to its acquisition in February 2011; and
|
•
|
a $12.6 million net decrease in residue purchases at the Hilight system due to declines in residue purchase prices, partially offset by an increase in cost of product expense for residue purchases for the MGR assets as a result of entering into commodity price swap agreements that became effective in January 2012.
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
||||||||
General and administrative
|
|
$
|
29,751
|
|
|
$
|
99,212
|
|
|
(70
|
)%
|
|
$
|
40,564
|
|
|
145
|
%
|
Property and other taxes
|
|
23,244
|
|
|
19,688
|
|
|
18
|
%
|
|
16,579
|
|
|
19
|
%
|
|||
Depreciation, amortization and impairments
|
|
145,916
|
|
|
120,608
|
|
|
21
|
%
|
|
113,133
|
|
|
7
|
%
|
|||
Total general and administrative, depreciation and other expenses
|
|
$
|
198,911
|
|
|
$
|
239,508
|
|
|
(17
|
)%
|
|
$
|
170,276
|
|
|
41
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
||||||||
Interest income on note receivable
|
|
$
|
16,900
|
|
|
$
|
16,900
|
|
|
—
|
%
|
|
$
|
16,900
|
|
|
—
|
%
|
Interest income, net on affiliate balances
(1)
|
|
—
|
|
|
—
|
|
|
—
|
%
|
|
7,206
|
|
|
(100
|
)%
|
|||
Interest income, net – affiliates
|
|
$
|
16,900
|
|
|
$
|
16,900
|
|
|
—
|
%
|
|
$
|
24,106
|
|
|
(30
|
)%
|
Third parties
|
|
|
|
|
|
|
|
|
|
|
||||||||
Interest expense on long-term debt
|
|
$
|
(59,293
|
)
|
|
$
|
(41,171
|
)
|
|
44
|
%
|
|
$
|
(20,533
|
)
|
|
101
|
%
|
Amortization of debt issuance costs and commitment fees
(2)
|
|
(4,449
|
)
|
|
(4,319
|
)
|
|
3
|
%
|
|
(5,297
|
)
|
|
(18
|
)%
|
|||
Capitalized interest
|
|
11,945
|
|
|
6,196
|
|
|
93
|
%
|
|
420
|
|
|
NM
|
|
|||
Affiliates
|
|
|
|
|
|
|
|
|
|
|
||||||||
Interest expense on note payable to Anadarko
(3)
|
|
—
|
|
|
(2,440
|
)
|
|
(100
|
)%
|
|
(4,935
|
)
|
|
(51
|
)%
|
|||
Interest expense on affiliate balances
(4)
|
|
—
|
|
|
(326
|
)
|
|
(100
|
)%
|
|
—
|
|
|
NM
|
|
|||
Interest expense
|
|
$
|
(51,797
|
)
|
|
$
|
(42,060
|
)
|
|
23
|
%
|
|
$
|
(30,345
|
)
|
|
39
|
%
|
(1)
|
Incurred on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets, and the Bison assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the Partnership assets prior to their acquisition were entirely settled through an adjustment to net investment by Anadarko.
|
(2)
|
For the
year ended December 31, 2013
, includes
$1.2 million
of amortization of debt issuance costs and underwriters’ fees for the 2022 Notes, the 2021 Notes, and the 2018 Notes. For the
year ended December 31, 2012
, includes
$1.1 million
of amortization of debt issuance costs and underwriters’ fees for the 2022 Notes and the 2021 Notes.
|
(3)
|
In June 2012, the note payable to Anadarko was repaid in full. See
Note 10—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(4)
|
Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. In the fourth quarter of 2012, we repaid the reimbursement payable to Anadarko associated with the construction of the Brasada facility and Lancaster plant. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
|
|
Year Ended December 31,
|
||||||||||||||
thousands
|
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
||||||
Other income (expense), net
|
|
$
|
1,837
|
|
|
$
|
292
|
|
|
NM
|
|
$
|
(44
|
)
|
|
NM
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
||||||||
Income before income taxes
|
$
|
288,582
|
|
|
$
|
170,026
|
|
|
70
|
%
|
|
$
|
239,011
|
|
|
(29
|
)%
|
Income tax expense
|
2,630
|
|
|
20,715
|
|
|
(87
|
)%
|
|
32,150
|
|
|
(36
|
)%
|
|||
Effective tax rate
|
1
|
%
|
|
12
|
%
|
|
|
|
13
|
%
|
|
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages
|
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
||||||||
Net income attributable to noncontrolling interests
|
|
$
|
10,816
|
|
|
$
|
14,890
|
|
|
(27
|
)%
|
|
$
|
14,103
|
|
|
6
|
%
|
|
|
Year Ended December 31,
|
||||||||||||||||
thousands except percentages and gross margin per Mcf
|
|
2013
|
|
2012
|
|
Inc/
(Dec)
|
|
2011
|
|
Inc/
(Dec)
|
||||||||
Gross margin
|
|
$
|
689,210
|
|
|
$
|
574,508
|
|
|
20
|
%
|
|
$
|
542,034
|
|
|
6
|
%
|
Gross margin per Mcf
(1)
|
|
0.56
|
|
|
0.52
|
|
|
8
|
%
|
|
0.55
|
|
|
(5
|
)%
|
|||
Gross margin per Mcf attributable to Western Gas Partners, LP
(2)
|
|
0.58
|
|
|
0.54
|
|
|
7
|
%
|
|
0.58
|
|
|
(7
|
)%
|
|||
Adjusted EBITDA attributable to Western Gas Partners, LP
(3)
|
|
457,773
|
|
|
377,929
|
|
|
21
|
%
|
|
361,653
|
|
|
5
|
%
|
|||
Distributable cash flow
(3)
|
|
$
|
380,529
|
|
|
$
|
309,945
|
|
|
23
|
%
|
|
$
|
319,294
|
|
|
(3
|
)%
|
(1)
|
Average for period. Calculated as gross margin (total revenues less cost of product) divided by total throughput (excluding throughput measured in barrels), including 100% of gross margin and volumes attributable to Chipeta, our 14.81% interest in income and volumes attributable to Fort Union and our 22% interest in income and volumes attributable to Rendezvous. Gross margin also includes 100% of gross margin attributable to our NGL pipelines, our 10% interest in income attributable to White Cliffs, and our 25% interest in income attributable to the Mont Belvieu JV.
|
(2)
|
Calculated as described in footnote one above, except also excludes the noncontrolling interest owners’ proportionate share of revenues, cost of product and throughput.
|
(3)
|
For reconciliations of Adjusted EBITDA and Distributable cash flow to their most directly comparable financial measures calculated and presented in accordance with GAAP, see
How We Evaluate Our Operations
—
Reconciliation to GAAP measures
within this Item 7.
|
•
|
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 expenditures to construct new midstream infrastructure and 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.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Acquisitions
|
|
$
|
716,985
|
|
|
$
|
611,719
|
|
|
$
|
330,794
|
|
|
|
|
|
|
|
|
||||||
Expansion capital expenditures
|
|
$
|
615,924
|
|
|
$
|
600,893
|
|
|
$
|
121,318
|
|
Maintenance capital expenditures
|
|
29,930
|
|
|
37,228
|
|
|
28,399
|
|
|||
Total capital expenditures
(1)
|
|
$
|
645,854
|
|
|
$
|
638,121
|
|
|
$
|
149,717
|
|
|
|
|
|
|
|
|
||||||
Capital incurred
(2)
|
|
$
|
628,285
|
|
|
$
|
690,041
|
|
|
$
|
182,536
|
|
(1)
|
Capital expenditures for the
years ended December 31, 2013
and 2012, included $10.6 million and $6.8 million, respectively, of capitalized interest. Capital expenditures included the noncontrolling interest owners’ share of Chipeta’s capital expenditures, funded by contributions from the noncontrolling interest owners for all periods presented. Capital expenditures for the
years ended December 31, 2012
and
2011
, included $178.8 million and $20.1 million, respectively, of pre-acquisition capital expenditures for the Non-Operated Marcellus Interest, the MGR assets, and the Bison assets.
|
(2)
|
Includes the noncontrolling interest owners’ share of Chipeta’s capital incurred, funded by contributions from the noncontrolling interest owners for all periods presented. Capital incurred for the
years ended December 31, 2013
and 2012, included $10.6 million and $6.8 million, respectively, of capitalized interest. Capital incurred for the
years ended December 31, 2013
, 2012 and
2011
, included $8.8 million, $160.9 million and $45.7 million, respectively, of pre-acquisition capital incurred for the Non-Operated Marcellus Interest, the MGR assets, and the Bison assets.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
||||||
Operating activities
|
|
$
|
415,721
|
|
|
$
|
338,026
|
|
|
$
|
312,838
|
|
Investing activities
|
|
(1,416,066
|
)
|
|
(1,249,942
|
)
|
|
(479,722
|
)
|
|||
Financing activities
|
|
681,092
|
|
|
1,105,338
|
|
|
366,369
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
$
|
(319,253
|
)
|
|
$
|
193,422
|
|
|
$
|
199,485
|
|
•
|
$465.5 million of cash paid for the acquisition of the Non-Operated Marcellus Interest;
|
•
|
$646.5 million
of capital expenditures, net of $0.6 million of contributions in aid of construction costs from affiliates;
|
•
|
$134.6 million of cash paid for the acquisition of the Anadarko-Operated Marcellus Interest;
|
•
|
$78.1 million of cash paid for the acquisition of the Mont Belvieu JV;
|
•
|
$37.3 million of capital contributions to the Mont Belvieu JV to fund our share of construction costs for the fractionation facilities completed in the fourth quarter of 2013;
|
•
|
$27.5 million of cash paid for the acquisition of OTTCO;
|
•
|
$19.1 million of cash paid related to a White Cliffs expansion project anticipated to be completed in the first half of 2014; and
|
•
|
$11.2 million of cash paid for equipment purchases from Anadarko.
|
•
|
$458.6 million of cash paid for the acquisition of the MGR assets;
|
•
|
$638.1 million
of capital expenditures;
|
•
|
$128.3 million of cash paid for the additional Chipeta interest; and
|
•
|
$24.7 million of cash paid for equipment purchases from Anadarko.
|
•
|
$302.0 million of cash paid for the acquisition of the Platte Valley system;
|
•
|
$149.7 million of capital expenditures;
|
•
|
$25.0 million of cash paid for the acquisition of the Bison facility; and
|
•
|
$3.8 million for equipment purchases from Anadarko.
|
•
|
$273.7 million
of net proceeds from our December 2013 equity offering, including net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest, $215.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;
|
•
|
$424.7 million of net proceeds from our May 2013 equity offering, including net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest, $245.0 million of which was used to repay a portion of our outstanding borrowings under our RCF;
|
•
|
$247.6 million of net proceeds from our 2018 Notes offering in August 2013, after underwriting and original issue discounts and offering costs, all of which was used to repay a portion of our outstanding borrowings under our RCF, including $250.0 million of borrowings to fund the acquisition of the Non-Operated Marcellus Interest;
|
•
|
$133.5 million of borrowings to fund the acquisition of the Anadarko-Operated Marcellus Interest;
|
•
|
$299.0 million of borrowings to fund capital expenditures;
|
•
|
$27.5 million of borrowings to fund the acquisition of OTTCO;
|
•
|
$41.8 million of net proceeds from activity under our Continuous Offering Program (as defined and discussed in
Registered Securities
within this Item 7), including net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest; and
|
•
|
$0.5 million of net proceeds from the issuance of general partner units to our general partner to maintain its 2.0% general partner interest after common units were issued in conjunction with the acquisition of the Non-Operated Marcellus Interest.
|
•
|
$511.3 million and $156.4 million of net proceeds from our 2022 Notes offering in June 2012 and October 2012, respectively, after underwriting and original issue discounts, original issue premiums and offering costs;
|
•
|
$409.4 million of net proceeds from the issuance of WES common and general partner units sold in connection with the closing of the WGP IPO;
|
•
|
$299.0 million of borrowings to fund the acquisition of the MGR assets; and
|
•
|
$216.4 million of net proceeds from our June 2012 equity offering.
|
•
|
$493.9 million of net proceeds from our 2021 Notes offering in May 2011, after underwriting and original issue discounts and offering costs;
|
•
|
$303.0 million of borrowings to fund the acquisition of the Platte Valley system;
|
•
|
$250.0 million repayment of the Wattenberg term loan (described below) using borrowings from our RCF;
|
•
|
$202.8 million of net proceeds from our September 2011 equity offering; and
|
•
|
$132.6 million of net proceeds from our March 2011 equity offering.
|
|
|
Obligations by Period
|
||||||||||||||||||||||||||
thousands
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
Thereafter
|
|
Total
|
||||||||||||||
Long-term debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Principal
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
250,000
|
|
|
1,170,000
|
|
|
1,420,000
|
|
|||||||
Interest
|
|
59,652
|
|
|
59,634
|
|
|
59,614
|
|
|
59,595
|
|
|
56,324
|
|
|
160,275
|
|
|
455,094
|
|
|||||||
Asset retirement obligations
|
|
1,966
|
|
|
1,755
|
|
|
127
|
|
|
—
|
|
|
—
|
|
|
74,187
|
|
|
78,035
|
|
|||||||
Capital expenditures
|
|
47,112
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
47,112
|
|
|||||||
Credit facility fees
|
|
2,000
|
|
|
2,000
|
|
|
460
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,460
|
|
|||||||
Environmental obligations
|
|
932
|
|
|
532
|
|
|
532
|
|
|
135
|
|
|
135
|
|
|
579
|
|
|
2,845
|
|
|||||||
Operating leases
|
|
309
|
|
|
245
|
|
|
233
|
|
|
157
|
|
|
34
|
|
|
—
|
|
|
978
|
|
|||||||
Total
|
|
$
|
111,971
|
|
|
$
|
64,166
|
|
|
$
|
60,966
|
|
|
$
|
59,887
|
|
|
$
|
306,493
|
|
|
$
|
1,405,041
|
|
|
$
|
2,008,524
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
/s/ Donald R. Sinclair
|
|
Donald R. Sinclair
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
|
2013
|
|
2012
|
|
2011
|
||||||
Revenues – affiliates
|
|
|
|
|
|
|
||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
$
|
306,810
|
|
|
$
|
249,997
|
|
|
$
|
227,535
|
|
Natural gas, natural gas liquids and condensate sales
|
|
496,848
|
|
|
436,423
|
|
|
417,547
|
|
|||
Equity income and other, net
|
|
25,600
|
|
|
17,717
|
|
|
13,598
|
|
|||
Total revenues – affiliates
|
|
829,258
|
|
|
704,137
|
|
|
658,680
|
|
|||
Revenues – third parties
|
|
|
|
|
|
|
||||||
Gathering, processing and transportation of natural gas and natural gas liquids
|
|
175,732
|
|
|
132,333
|
|
|
119,934
|
|
|||
Natural gas, natural gas liquids and condensate sales
|
|
44,396
|
|
|
71,916
|
|
|
84,836
|
|
|||
Other, net
|
|
4,109
|
|
|
2,201
|
|
|
5,955
|
|
|||
Total revenues – third parties
|
|
224,237
|
|
|
206,450
|
|
|
210,725
|
|
|||
Total revenues
|
|
1,053,495
|
|
|
910,587
|
|
|
869,405
|
|
|||
Operating expenses
|
|
|
|
|
|
|
||||||
Cost of product
(1)
|
|
364,285
|
|
|
336,079
|
|
|
327,371
|
|
|||
Operation and maintenance
(1)
|
|
168,657
|
|
|
140,106
|
|
|
126,464
|
|
|||
General and administrative
(1)
|
|
29,751
|
|
|
99,212
|
|
|
40,564
|
|
|||
Property and other taxes
|
|
23,244
|
|
|
19,688
|
|
|
16,579
|
|
|||
Depreciation, amortization and impairments
|
|
145,916
|
|
|
120,608
|
|
|
113,133
|
|
|||
Total operating expenses
|
|
731,853
|
|
|
715,693
|
|
|
624,111
|
|
|||
Operating income
|
|
321,642
|
|
|
194,894
|
|
|
245,294
|
|
|||
Interest income, net – affiliates
|
|
16,900
|
|
|
16,900
|
|
|
24,106
|
|
|||
Interest expense
(2)
|
|
(51,797
|
)
|
|
(42,060
|
)
|
|
(30,345
|
)
|
|||
Other income (expense), net
|
|
1,837
|
|
|
292
|
|
|
(44
|
)
|
|||
Income before income taxes
|
|
288,582
|
|
|
170,026
|
|
|
239,011
|
|
|||
Income tax expense
|
|
2,630
|
|
|
20,715
|
|
|
32,150
|
|
|||
Net income
|
|
285,952
|
|
|
149,311
|
|
|
206,861
|
|
|||
Net income attributable to noncontrolling interests
|
|
10,816
|
|
|
14,890
|
|
|
14,103
|
|
|||
Net income attributable to Western Gas Partners, LP
|
|
$
|
275,136
|
|
|
$
|
134,421
|
|
|
$
|
192,758
|
|
Limited partners’ interest in net income:
|
|
|
|
|
|
|
||||||
Net income attributable to Western Gas Partners, LP
|
|
$
|
275,136
|
|
|
$
|
134,421
|
|
|
$
|
192,758
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
|
(4,637
|
)
|
|
(27,435
|
)
|
|
(52,599
|
)
|
|||
General partner interest in net (income) loss
(3)
|
|
(69,633
|
)
|
|
(28,089
|
)
|
|
(8,599
|
)
|
|||
Limited partners’ interest in net income
(3)
|
|
$
|
200,866
|
|
|
$
|
78,897
|
|
|
$
|
131,560
|
|
Net income per common unit – basic and diluted
|
|
$
|
1.83
|
|
|
$
|
0.84
|
|
|
$
|
1.64
|
|
Net income per subordinated unit – basic and diluted
(4)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.28
|
|
(1)
|
Cost of product includes product purchases from Anadarko (as defined in
Note 1
) of
$129.0 million
,
$145.3 million
and
$83.7 million
for the
years ended December 31, 2013
,
2012
and
2011
, respectively. Operation and maintenance includes charges from Anadarko of
$56.4 million
,
$51.2 million
and
$51.3 million
for the
years ended December 31, 2013
,
2012
and
2011
, respectively. General and administrative includes charges from Anadarko of
$23.4 million
,
$92.8 million
and
$33.3 million
for the
years ended December 31, 2013
,
2012
and
2011
, respectively. See
Note 5
.
|
(2)
|
Includes affiliate (as defined in
Note 1
) interest expense of
zero
,
$2.8 million
and
$4.9 million
for the
years ended December 31, 2013
,
2012
and
2011
, respectively. See
Note 10
.
|
(3)
|
Represents net income earned on and subsequent to the date of the acquisition of the Partnership assets (as defined in
Note 1
). See
Note 4
.
|
(4)
|
All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See
Note 4
.
|
|
|
December 31,
|
||||||
thousands except number of units
|
|
2013
|
|
2012
|
||||
ASSETS
|
|
|
|
|
||||
Current assets
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
100,728
|
|
|
$
|
419,981
|
|
Accounts receivable, net
(1)
|
|
84,060
|
|
|
50,233
|
|
||
Other current assets
(2)
|
|
10,022
|
|
|
6,998
|
|
||
Total current assets
|
|
194,810
|
|
|
477,212
|
|
||
Note receivable – Anadarko
|
|
260,000
|
|
|
260,000
|
|
||
Property, plant and equipment
|
|
|
|
|
||||
Cost
|
|
4,239,100
|
|
|
3,432,392
|
|
||
Less accumulated depreciation
|
|
855,845
|
|
|
714,436
|
|
||
Net property, plant and equipment
|
|
3,383,255
|
|
|
2,717,956
|
|
||
Goodwill
|
|
105,336
|
|
|
105,336
|
|
||
Other intangible assets
|
|
53,606
|
|
|
55,490
|
|
||
Equity investments
|
|
243,619
|
|
|
106,130
|
|
||
Other assets
|
|
27,401
|
|
|
27,798
|
|
||
Total assets
|
|
$
|
4,268,027
|
|
|
$
|
3,749,922
|
|
LIABILITIES, EQUITY AND PARTNERS’ CAPITAL
|
|
|
|
|
||||
Current liabilities
|
|
|
|
|
||||
Accounts and natural gas imbalance payables
(3)
|
|
$
|
39,589
|
|
|
$
|
25,154
|
|
Accrued ad valorem taxes
|
|
13,860
|
|
|
11,949
|
|
||
Income taxes payable
|
|
—
|
|
|
552
|
|
||
Accrued liabilities
(4)
|
|
137,011
|
|
|
147,651
|
|
||
Total current liabilities
|
|
190,460
|
|
|
185,306
|
|
||
Long-term debt
|
|
1,418,169
|
|
|
1,168,278
|
|
||
Deferred income taxes
|
|
309
|
|
|
47,153
|
|
||
Asset retirement obligations and other
|
|
79,145
|
|
|
68,749
|
|
||
Total long-term liabilities
|
|
1,497,623
|
|
|
1,284,180
|
|
||
Total liabilities
|
|
1,688,083
|
|
|
1,469,486
|
|
||
Equity and partners’ capital
|
|
|
|
|
||||
Common units (117,322,812 and 104,660,553 units issued and outstanding at December 31, 2013 and 2012, respectively)
|
|
2,431,193
|
|
|
1,957,066
|
|
||
General partner units (2,394,345 and 2,135,930 units issued and outstanding at December 31, 2013 and 2012, respectively)
|
|
78,157
|
|
|
52,752
|
|
||
Net investment by Anadarko
|
|
—
|
|
|
199,960
|
|
||
Total partners’ capital
|
|
2,509,350
|
|
|
2,209,778
|
|
||
Noncontrolling interests
|
|
70,594
|
|
|
70,658
|
|
||
Total equity and partners’ capital
|
|
2,579,944
|
|
|
2,280,436
|
|
||
Total liabilities, equity and partners’ capital
|
|
$
|
4,268,027
|
|
|
$
|
3,749,922
|
|
(1)
|
Accounts receivable, net includes amounts receivable from affiliates (as defined in
Note 1
) of
$47.9 million
and
$19.1 million
as of
December 31, 2013
and
2012
, respectively.
|
(2)
|
Other current assets includes natural gas imbalance receivables from affiliates of
$0.1 million
and
$0.4 million
as of
December 31, 2013
and
2012
, respectively.
|
(3)
|
Accounts and natural gas imbalance payables includes amounts payable to affiliates of
$2.3 million
and
$2.5 million
as of
December 31, 2013
and
2012
, respectively.
|
(4)
|
Accrued liabilities include amounts payable to affiliates of
$0.1 million
as of
December 31, 2013
and
2012
.
|
|
|
Partners’ Capital
|
|
|
|
|
||||||||||||||||||
thousands
|
|
Net
Investment
by Anadarko
|
|
Common
Units
|
|
Subordinated
Units
|
|
General
Partner Units
|
|
Noncontrolling
Interests
|
|
Total
|
||||||||||||
Balance at December 31, 2010
|
|
$
|
408,243
|
|
|
$
|
810,717
|
|
|
$
|
282,384
|
|
|
$
|
21,505
|
|
|
$
|
90,462
|
|
|
$
|
1,613,311
|
|
Net income
|
|
52,599
|
|
|
110,542
|
|
|
21,018
|
|
|
8,599
|
|
|
14,103
|
|
|
206,861
|
|
||||||
Conversion of subordinated units to common units
(1)
|
|
—
|
|
|
272,222
|
|
|
(272,222
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Issuance of common and general partner units, net of offering expenses
|
|
—
|
|
|
328,345
|
|
|
—
|
|
|
6,972
|
|
|
—
|
|
|
335,317
|
|
||||||
Contributions from noncontrolling interest owners
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
33,637
|
|
|
33,637
|
|
||||||
Distributions to noncontrolling interest owners
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17,478
|
)
|
|
(17,478
|
)
|
||||||
Distributions to unitholders
|
|
—
|
|
|
(102,091
|
)
|
|
(31,180
|
)
|
|
(6,847
|
)
|
|
—
|
|
|
(140,118
|
)
|
||||||
Acquisition from affiliates
|
|
(92,666
|
)
|
|
66,313
|
|
|
—
|
|
|
1,353
|
|
|
—
|
|
|
(25,000
|
)
|
||||||
Contributions of equity-based compensation from Anadarko
(2)
|
|
—
|
|
|
9,472
|
|
|
—
|
|
|
194
|
|
|
—
|
|
|
9,666
|
|
||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
(33,785
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(33,785
|
)
|
||||||
Elimination of net deferred tax liabilities
|
|
22,072
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
22,072
|
|
||||||
Other
|
|
—
|
|
|
(267
|
)
|
|
—
|
|
|
(47
|
)
|
|
—
|
|
|
(314
|
)
|
||||||
Balance at December 31, 2011
|
|
$
|
356,463
|
|
|
$
|
1,495,253
|
|
|
$
|
—
|
|
|
$
|
31,729
|
|
|
$
|
120,724
|
|
|
$
|
2,004,169
|
|
Net income
|
|
27,435
|
|
|
78,897
|
|
|
—
|
|
|
28,089
|
|
|
14,890
|
|
|
149,311
|
|
||||||
Issuance of common and general partner units, net of offering expenses
|
|
—
|
|
|
613,188
|
|
|
—
|
|
|
12,689
|
|
|
—
|
|
|
625,877
|
|
||||||
Contributions from noncontrolling interest owners
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29,108
|
|
|
29,108
|
|
||||||
Distributions to noncontrolling interest owners
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(17,303
|
)
|
|
(17,303
|
)
|
||||||
Distributions to unitholders
|
|
—
|
|
|
(175,639
|
)
|
|
—
|
|
|
(22,211
|
)
|
|
—
|
|
|
(197,850
|
)
|
||||||
Acquisition from affiliates
|
|
(482,701
|
)
|
|
23,458
|
|
|
—
|
|
|
479
|
|
|
—
|
|
|
(458,764
|
)
|
||||||
Acquisition of additional 24% interest in Chipeta
(3)
|
|
—
|
|
|
(44,071
|
)
|
|
—
|
|
|
162
|
|
|
(77,195
|
)
|
|
(121,104
|
)
|
||||||
Contributions of equity-based compensation from Anadarko
(2)
|
|
—
|
|
|
84,971
|
|
|
—
|
|
|
2,086
|
|
|
—
|
|
|
87,057
|
|
||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
192,259
|
|
|
(106,597
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
85,662
|
|
||||||
Net distributions of other assets to Anadarko
|
|
—
|
|
|
(15,002
|
)
|
|
—
|
|
|
(273
|
)
|
|
(21
|
)
|
|
(15,296
|
)
|
||||||
Elimination of net deferred tax liabilities
|
|
106,504
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
106,504
|
|
||||||
Other
|
|
—
|
|
|
2,608
|
|
|
—
|
|
|
2
|
|
|
455
|
|
|
3,065
|
|
||||||
Balance at December 31, 2012
|
|
$
|
199,960
|
|
|
$
|
1,957,066
|
|
|
$
|
—
|
|
|
$
|
52,752
|
|
|
$
|
70,658
|
|
|
$
|
2,280,436
|
|
Net income
|
|
4,637
|
|
|
200,866
|
|
|
—
|
|
|
69,633
|
|
|
10,816
|
|
|
285,952
|
|
||||||
Issuance of common and general partner units, net of offering expenses
|
|
—
|
|
|
724,811
|
|
|
—
|
|
|
15,775
|
|
|
—
|
|
|
740,586
|
|
||||||
Contributions from noncontrolling interest owners
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2,247
|
|
|
2,247
|
|
||||||
Distributions to noncontrolling interest owners
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(13,127
|
)
|
|
(13,127
|
)
|
||||||
Distributions to unitholders
|
|
—
|
|
|
(239,157
|
)
|
|
—
|
|
|
(59,944
|
)
|
|
—
|
|
|
(299,101
|
)
|
||||||
Acquisitions from affiliates
|
|
(255,635
|
)
|
|
(209,865
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(465,500
|
)
|
||||||
Contributions of equity-based compensation from Anadarko
(2)
|
|
—
|
|
|
2,865
|
|
|
—
|
|
|
58
|
|
|
—
|
|
|
2,923
|
|
||||||
Net pre-acquisition contributions from (distributions to) Anadarko
|
|
4,508
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4,508
|
|
||||||
Net distributions of other assets to Anadarko
|
|
—
|
|
|
(5,738
|
)
|
|
—
|
|
|
(117
|
)
|
|
|
|
|
(5,855
|
)
|
||||||
Elimination of net deferred tax liabilities
|
|
46,530
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
46,530
|
|
||||||
Other
|
|
—
|
|
|
345
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
345
|
|
||||||
Balance at December 31, 2013
|
|
$
|
—
|
|
|
$
|
2,431,193
|
|
|
$
|
—
|
|
|
$
|
78,157
|
|
|
$
|
70,594
|
|
|
$
|
2,579,944
|
|
(1)
|
All subordinated units were converted to common units on a one-for-one basis on August 15, 2011. See
Note 4
.
|
(2)
|
Associated with the Anadarko Incentive Plans for the years ended December 31, 2011 and 2013, associated with the Anadarko Incentive Plans and the Incentive Plan for the year ended December 31, 2012, as defined and described in
Note 1
and
Note 5
.
|
(3)
|
See
Note 2
for a description of the acquisition of Anadarko’s then-remaining
24%
membership interest in Chipeta in August 2012. The
$43.9 million
decrease to partners’ capital resulting from the August 2012 Chipeta acquisition together with net income attributable to Western Gas Partners, LP totaled
$90.5 million
for the year ended December 31, 2012.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Cash flows from operating activities
|
|
|
|
|
|
|
||||||
Net income
|
|
$
|
285,952
|
|
|
$
|
149,311
|
|
|
$
|
206,861
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Depreciation, amortization and impairments
|
|
145,916
|
|
|
120,608
|
|
|
113,133
|
|
|||
Non-cash equity-based compensation expense
|
|
3,521
|
|
|
3,717
|
|
|
3,490
|
|
|||
Deferred income taxes
|
|
(314
|
)
|
|
30,113
|
|
|
16,580
|
|
|||
Debt-related amortization and other items, net
|
|
2,449
|
|
|
2,319
|
|
|
3,110
|
|
|||
Changes in assets and liabilities:
|
|
|
|
|
|
|
||||||
(Increase) decrease in accounts receivable, net
|
|
(34,019
|
)
|
|
22,916
|
|
|
(44,725
|
)
|
|||
Increase (decrease) in accounts and natural gas imbalance payables and accrued liabilities, net
|
|
21,952
|
|
|
5,045
|
|
|
30,884
|
|
|||
Change in other items, net
|
|
(9,736
|
)
|
|
3,997
|
|
|
(16,495
|
)
|
|||
Net cash provided by operating activities
|
|
415,721
|
|
|
338,026
|
|
|
312,838
|
|
|||
Cash flows from investing activities
|
|
|
|
|
|
|
||||||
Capital expenditures
|
|
(646,471
|
)
|
|
(638,121
|
)
|
|
(149,717
|
)
|
|||
Contributions in aid of construction costs from affiliates
|
|
617
|
|
|
—
|
|
|
—
|
|
|||
Acquisitions from affiliates
|
|
(476,711
|
)
|
|
(611,719
|
)
|
|
(28,837
|
)
|
|||
Acquisitions from third parties
|
|
(240,274
|
)
|
|
—
|
|
|
(301,957
|
)
|
|||
Investments in equity affiliates
|
|
(51,974
|
)
|
|
(862
|
)
|
|
(93
|
)
|
|||
Proceeds from the sale of assets to affiliates
|
|
85
|
|
|
760
|
|
|
382
|
|
|||
Other
|
|
(1,338
|
)
|
|
—
|
|
|
500
|
|
|||
Net cash used in investing activities
|
|
(1,416,066
|
)
|
|
(1,249,942
|
)
|
|
(479,722
|
)
|
|||
Cash flows from financing activities
|
|
|
|
|
|
|
||||||
Borrowings, net of debt issuance costs
|
|
957,503
|
|
|
1,041,648
|
|
|
1,055,939
|
|
|||
Repayments of debt
|
|
(710,000
|
)
|
|
(549,000
|
)
|
|
(869,000
|
)
|
|||
Increase (decrease) in outstanding checks
|
|
(1,763
|
)
|
|
1,800
|
|
|
4,039
|
|
|||
Proceeds from the issuance of common and general partner units, net of offering expenses
|
|
740,825
|
|
|
625,877
|
|
|
335,317
|
|
|||
Distributions to unitholders
|
|
(299,101
|
)
|
|
(197,850
|
)
|
|
(140,118
|
)
|
|||
Contributions from noncontrolling interest owners
|
|
2,247
|
|
|
29,108
|
|
|
33,637
|
|
|||
Distributions to noncontrolling interest owners
|
|
(13,127
|
)
|
|
(17,303
|
)
|
|
(17,478
|
)
|
|||
Net contributions from (distributions to) Anadarko
|
|
4,508
|
|
|
171,058
|
|
|
(35,967
|
)
|
|||
Net cash provided by financing activities
|
|
681,092
|
|
|
1,105,338
|
|
|
366,369
|
|
|||
Net increase (decrease) in cash and cash equivalents
|
|
(319,253
|
)
|
|
193,422
|
|
|
199,485
|
|
|||
Cash and cash equivalents at beginning of period
|
|
419,981
|
|
|
226,559
|
|
|
27,074
|
|
|||
Cash and cash equivalents at end of period
|
|
$
|
100,728
|
|
|
$
|
419,981
|
|
|
$
|
226,559
|
|
|
|
|
|
|
|
|
||||||
Supplemental disclosures
|
|
|
|
|
|
|
||||||
Net distributions to (contributions from) Anadarko of other assets
|
|
$
|
5,855
|
|
|
$
|
15,296
|
|
|
$
|
(29
|
)
|
Interest paid, net of capitalized interest
|
|
$
|
47,098
|
|
|
$
|
28,042
|
|
|
$
|
25,828
|
|
Taxes paid
|
|
$
|
552
|
|
|
$
|
495
|
|
|
$
|
190
|
|
|
|
Owned and
Operated
|
|
Operated
Interests
|
|
Non-Operated
Interests
|
|||
Natural gas gathering systems
|
|
13
|
|
|
1
|
|
|
5
|
|
Natural gas treating facilities
|
|
8
|
|
|
—
|
|
|
—
|
|
Natural gas processing facilities
|
|
8
|
|
|
3
|
|
|
—
|
|
NGL pipelines
|
|
3
|
|
|
—
|
|
|
—
|
|
Natural gas pipelines
|
|
3
|
|
|
—
|
|
|
—
|
|
|
Equity Investments
|
||||||||||||||
thousands
|
Fort Union
(1)
|
|
White Cliffs
(2)
|
|
Rendezvous
(3)
|
|
Mont
Belvieu JV
(4)
|
||||||||
Balance at December 31, 2011
|
$
|
22,268
|
|
|
$
|
17,710
|
|
|
$
|
69,839
|
|
|
$
|
—
|
|
Investment earnings, net of amortization
|
6,383
|
|
|
7,871
|
|
|
1,857
|
|
|
—
|
|
||||
Contributions
|
—
|
|
|
862
|
|
|
—
|
|
|
—
|
|
||||
Distributions
|
(5,198
|
)
|
|
(8,876
|
)
|
|
(6,586
|
)
|
|
—
|
|
||||
Balance at December 31, 2012
|
$
|
23,453
|
|
|
$
|
17,567
|
|
|
$
|
65,110
|
|
|
$
|
—
|
|
Initial investment
|
—
|
|
|
—
|
|
|
—
|
|
|
78,129
|
|
||||
Investment earnings, net of amortization
|
6,273
|
|
|
9,681
|
|
|
2,088
|
|
|
5,690
|
|
||||
Contributions
|
16
|
|
|
19,087
|
|
|
—
|
|
|
38,661
|
|
||||
Distributions
|
(4,570
|
)
|
|
(9,266
|
)
|
|
(4,029
|
)
|
|
—
|
|
||||
Distributions in excess of cumulative earnings
|
—
|
|
|
(2,030
|
)
|
|
(2,241
|
)
|
|
—
|
|
||||
Balance at December 31, 2013
|
$
|
25,172
|
|
|
$
|
35,039
|
|
|
$
|
60,928
|
|
|
$
|
122,480
|
|
(1)
|
The Partnership has a 14.81% interest in Fort Union, a joint venture which owns a gathering pipeline and treating facilities in the Powder River Basin. Anadarko is the construction manager and physical operator of the Fort Union facilities. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, require
65%
or unanimous approval of the owners.
|
(2)
|
The Partnership has a 10% interest in White Cliffs, a limited liability company which owns a crude oil pipeline that originates in Platteville, Colorado and terminates in Cushing, Oklahoma. The third-party majority owner is the manager of the White Cliffs operations. Certain business decisions, including, but not limited to, approval of annual budgets and decisions with respect to significant expenditures, contractual commitments, acquisitions, material financings, dispositions of assets or admitting new members, require more than
75%
approval of the members.
|
(3)
|
The Partnership has a 22% interest in Rendezvous, a limited liability company that operates gas gathering facilities in Southwestern Wyoming. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members.
|
(4)
|
The Partnership has a 25% interest in the Mont Belvieu JV, an entity formed to design, construct, and own two fractionation trains located in Mont Belvieu, Texas. A third party is the operator of the Mont Belvieu JV fractionation trains. Certain business decisions, including, but not limited to, decisions with respect to the execution of contracts, settlements, disposition of assets, or the creation, appointment, or removal of officer positions require
50%
or unanimous approval of the owners.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Consolidated Statements of Income
|
|
|
|
|
|
|
||||||
Revenues
|
|
$
|
256,632
|
|
|
$
|
199,764
|
|
|
$
|
153,131
|
|
Operating income
|
|
176,370
|
|
|
135,577
|
|
|
90,549
|
|
|||
Net income
|
|
175,060
|
|
|
134,066
|
|
|
88,521
|
|
|
|
December 31,
|
||||||
thousands
|
|
2013
|
|
2012
|
||||
Consolidated Balance Sheets
|
|
|
|
|
||||
Current assets
|
|
$
|
171,457
|
|
|
$
|
44,474
|
|
Property, plant and equipment, net
|
|
1,174,034
|
|
|
611,441
|
|
||
Other assets
|
|
38,258
|
|
|
45,100
|
|
||
Total assets
|
|
$
|
1,383,749
|
|
|
$
|
701,015
|
|
Current liabilities
|
|
86,606
|
|
|
20,174
|
|
||
Non-current liabilities
|
|
32,704
|
|
|
50,759
|
|
||
Equity
|
|
1,264,439
|
|
|
630,082
|
|
||
Total liabilities and equity
|
|
$
|
1,383,749
|
|
|
$
|
701,015
|
|
thousands except unit and percent amounts
|
|
Acquisition
Date
|
|
Percentage
Acquired
|
|
Borrowings
|
|
Cash
On Hand
|
|
Common
Units Issued
|
|
GP Units
Issued
|
|||||||
Platte Valley
(1)
|
|
02/28/2011
|
|
100
|
%
|
|
$
|
303,000
|
|
|
$
|
602
|
|
|
—
|
|
|
—
|
|
Bison
(2)
|
|
07/08/2011
|
|
100
|
%
|
|
—
|
|
|
25,000
|
|
|
2,950,284
|
|
|
60,210
|
|
||
MGR
(3)
|
|
01/13/2012
|
|
100
|
%
|
|
299,000
|
|
|
159,587
|
|
|
632,783
|
|
|
12,914
|
|
||
Chipeta
(4)
|
|
08/01/2012
|
|
24
|
%
|
|
—
|
|
|
128,250
|
|
|
151,235
|
|
|
3,086
|
|
||
Non-Operated Marcellus Interest
(5)
|
|
03/01/2013
|
|
33.75
|
%
|
|
250,000
|
|
|
215,500
|
|
|
449,129
|
|
|
—
|
|
||
Anadarko-Operated Marcellus Interest
(6)
|
|
03/08/2013
|
|
33.75
|
%
|
|
133,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||
Mont Belvieu JV
(7)
|
|
06/05/2013
|
|
25
|
%
|
|
—
|
|
|
78,129
|
|
|
—
|
|
|
—
|
|
||
OTTCO
(8)
|
|
09/03/2013
|
|
100
|
%
|
|
27,500
|
|
|
—
|
|
|
—
|
|
|
—
|
|
(1)
|
The Partnership acquired (i) a natural gas gathering system and related compression and other ancillary equipment and (ii) cryogenic gas processing facilities from a third party. These assets are located in the Denver-Julesburg Basin. The acquisition is referred to as the “Platte Valley acquisition.”
|
(2)
|
The Bison gas treating facility acquired from Anadarko is located in the Powder River Basin in northeastern Wyoming and includes (i)
three
amine treating units, (ii) compressor units, and (iii) generators. These assets are referred to collectively as the “Bison assets.” The Bison assets are the only treating and delivery point into the third-party-owned Bison pipeline. The Bison assets were placed in service in June 2010.
|
(3)
|
The assets acquired from Anadarko consisted of (i) the Red Desert complex, which is located in the greater Green River Basin in southwestern Wyoming, and includes the Patrick Draw processing plant, the Red Desert processing plant, gathering lines, and related facilities, (ii) a
22%
interest in Rendezvous, which owns a gathering system serving the Jonah and Pinedale Anticline fields in southwestern Wyoming, and (iii) certain additional midstream assets and equipment. These assets are collectively referred to as the “MGR assets” and the acquisition as the “MGR acquisition.”
|
(4)
|
The Partnership acquired Anadarko’s additional Chipeta interest (as described in
Note 1
). The Partnership received distributions related to the additional interest beginning July 1, 2012. This transaction brought the Partnership’s total membership interest in Chipeta to
75%
. The remaining
25%
membership interest in Chipeta held by a third-party member is reflected as noncontrolling interests in the consolidated financial statements for all periods presented.
|
(5)
|
The Partnership acquired Anadarko’s 33.75% interest (non-operated) in the Liberty and Rome gas gathering systems, serving production from the Marcellus shale in north-central Pennsylvania. The interest acquired is referred to as the “Non-Operated Marcellus Interest” and the acquisition as the “Non-Operated Marcellus Interest acquisition.” In connection with the issuance of the common units, the Partnership’s general partner purchased
9,166
general partner units for consideration of
$0.5 million
in order to maintain its
2.0%
general partner interest in the Partnership.
|
(6)
|
The Partnership acquired a 33.75% interest in each of the Larry’s Creek, Seely and Warrensville gas gathering systems, which are operated by Anadarko and serve production from the Marcellus shale in north-central Pennsylvania, from a third party. The interest acquired is referred to as the “Anadarko-Operated Marcellus Interest” and the acquisition as the “Anadarko-Operated Marcellus Interest acquisition.” See
Anadarko-Operated Marcellus Interest acquisition
below for further information, including the final allocation of the purchase price.
|
(7)
|
The Partnership acquired a 25% interest in Enterprise EF78 LLC, an entity formed to design, construct, and own
two
fractionation trains located in Mont Belvieu, Texas, from a third party. The interest acquired is accounted for under the equity method of accounting and is referred to as the “Mont Belvieu JV” and the acquisition as the “Mont Belvieu JV acquisition.” See
Mont Belvieu JV acquisition
below for further information.
|
(8)
|
The Partnership acquired Overland Trail Transmission, LLC (“OTTCO”), a Delaware limited liability company, from a third party. OTTCO owns and operates an intrastate pipeline that connects the Partnership’s Red Desert and Granger complexes in southwestern Wyoming.
|
thousands
|
|
|
||
Property, plant and equipment
|
|
$
|
134,819
|
|
Asset retirement obligations
|
|
(174
|
)
|
|
Total purchase price
|
|
$
|
134,645
|
|
|
|
Year Ended December 31,
|
||||||
thousands except per-unit amounts
|
|
2013
|
|
2012
|
||||
Revenues
|
|
$
|
1,054,749
|
|
|
$
|
915,464
|
|
Net income
|
|
286,100
|
|
|
147,282
|
|
||
Net income attributable to Western Gas Partners, LP
|
|
275,284
|
|
|
132,392
|
|
||
Net income per common unit - basic and diluted
|
|
$
|
1.82
|
|
|
$
|
0.82
|
|
thousands except per-unit amounts
Quarters Ended
|
|
Total Quarterly
Distribution
per Unit
|
|
Total Quarterly
Cash Distribution
|
|
Date of
Distribution
|
|||||
2011
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.390
|
|
|
$
|
33,168
|
|
|
May 2011
|
|
June 30
|
|
$
|
0.405
|
|
|
$
|
36,063
|
|
|
August 2011
|
|
September 30
|
|
$
|
0.420
|
|
|
$
|
40,323
|
|
|
November 2011
|
|
December 31
|
|
$
|
0.440
|
|
|
$
|
43,027
|
|
|
February 2012
|
|
2012
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.460
|
|
|
$
|
46,053
|
|
|
May 2012
|
|
June 30
|
|
$
|
0.480
|
|
|
$
|
52,425
|
|
|
August 2012
|
|
September 30
|
|
$
|
0.500
|
|
|
$
|
56,346
|
|
|
November 2012
|
|
December 31
|
|
$
|
0.520
|
|
|
$
|
65,657
|
|
|
February 2013
|
|
2013
|
|
|
|
|
|
|
|||||
March 31
|
|
$
|
0.540
|
|
|
$
|
70,143
|
|
|
May 2013
|
|
June 30
|
|
$
|
0.560
|
|
|
$
|
79,315
|
|
|
August 2013
|
|
September 30
|
|
$
|
0.580
|
|
|
$
|
83,986
|
|
|
November 2013
|
|
December 31
(1)
|
|
$
|
0.600
|
|
|
$
|
92,609
|
|
|
February 2014
|
(1)
|
On
January 20, 2014
, the board of directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of
$0.60
per unit, or
$92.6 million
in aggregate, including incentive distributions. The cash distribution is payable on
February 12, 2014
, to unitholders of record at the close of business on
January 31, 2014
.
|
|
|
Total Quarterly Distribution
Target Amount
|
|
Marginal Percentage
Interest in Distributions
|
||
|
|
|
Unitholders
|
|
General Partner
|
|
Minimum quarterly distribution
|
|
$0.300
|
|
98.0%
|
|
2.0%
|
First target distribution
|
|
up to $0.345
|
|
98.0%
|
|
2.0%
|
Second target distribution
|
|
above $0.345 up to $0.375
|
|
85.0%
|
|
15.0%
|
Third target distribution
|
|
above $0.375 up to $0.450
|
|
75.0%
|
|
25.0%
|
Thereafter
|
|
above $0.450
|
|
50.0%
|
|
50.0%
|
thousands except unit
and per-unit amounts
|
Common
Units Issued
(1)
|
|
GP Units
Issued
(2)
|
|
Price Per
Unit
|
|
Underwriting
Discount and
Other Offering
Expenses
|
|
Net
Proceeds
|
||||||||
March 2011 equity offering
|
3,852,813
|
|
|
78,629
|
|
|
$
|
35.15
|
|
|
$
|
5,621
|
|
|
$
|
132,569
|
|
September 2011 equity offering
|
5,750,000
|
|
|
117,347
|
|
|
35.86
|
|
|
7,655
|
|
|
202,748
|
|
|||
June 2012 equity offering
|
5,000,000
|
|
|
102,041
|
|
|
43.88
|
|
|
7,468
|
|
|
216,409
|
|
|||
May 2013 equity offering
|
7,015,000
|
|
|
143,163
|
|
|
61.18
|
|
|
13,203
|
|
|
424,733
|
|
|||
December 2013 equity offering
(3)
|
4,500,000
|
|
|
91,837
|
|
|
61.51
|
|
|
8,716
|
|
|
273,728
|
|
(1)
|
Includes the issuance of
302,813
common units,
750,000
common units and
915,000
common units pursuant to the full exercise of th
e underwriters’ over-allotment option granted in connection with the March 2011, September 2011 and May 2013 equity offerings, respectively.
|
(2)
|
Represents general partner units issued to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its
2.0%
general partner interest.
|
(3)
|
Excludes the issuance of
300,000
common units on January 3, 2014, pursuant to the partial exercise of the underwriters’ over-allotment option, and the corresponding issuance of
6,122
general partner units to the general partner in exchange for the general partner’s proportionate capital contribution to maintain its 2.0% general partner interest. Total net proceeds for the partial exercise of the underwriters’ over-allotment option (including the general partner’s proportionate capital contribution) were
$18.3 million
.
|
|
|
Common
Units
|
|
General
Partner Units
|
|
Total
|
|||
Balance at December 31, 2011
|
|
90,140,999
|
|
|
1,839,613
|
|
|
91,980,612
|
|
MGR acquisition
|
|
632,783
|
|
|
12,914
|
|
|
645,697
|
|
Long-Term Incentive Plan awards
|
|
12,570
|
|
|
257
|
|
|
12,827
|
|
June 2012 equity offering
|
|
5,000,000
|
|
|
102,041
|
|
|
5,102,041
|
|
Chipeta acquisition
|
|
151,235
|
|
|
3,086
|
|
|
154,321
|
|
WGP unit purchase agreement
|
|
8,722,966
|
|
|
178,019
|
|
|
8,900,985
|
|
Balance at December 31, 2012
|
|
104,660,553
|
|
|
2,135,930
|
|
|
106,796,483
|
|
Non-Operated Marcellus Interest acquisition
|
|
449,129
|
|
|
9,166
|
|
|
458,295
|
|
Long-Term Incentive Plan awards
|
|
12,395
|
|
|
253
|
|
|
12,648
|
|
May 2013 equity offering
|
|
7,015,000
|
|
|
143,163
|
|
|
7,158,163
|
|
Continuous Offering Program
|
|
685,735
|
|
|
13,996
|
|
|
699,731
|
|
December 2013 equity offering
|
|
4,500,000
|
|
|
91,837
|
|
|
4,591,837
|
|
Balance at December 31, 2013
|
|
117,322,812
|
|
|
2,394,345
|
|
|
119,717,157
|
|
|
Year Ended December 31,
|
||||||||||
thousands except per-unit amounts
|
2013
|
|
2012
|
|
2011
|
||||||
Net income attributable to Western Gas Partners, LP
|
$
|
275,136
|
|
|
$
|
134,421
|
|
|
$
|
192,758
|
|
Pre-acquisition net (income) loss allocated to Anadarko
|
(4,637
|
)
|
|
(27,435
|
)
|
|
(52,599
|
)
|
|||
General partner interest in net (income) loss
|
(69,633
|
)
|
|
(28,089
|
)
|
|
(8,599
|
)
|
|||
Limited partners’ interest in net income
|
$
|
200,866
|
|
|
$
|
78,897
|
|
|
$
|
131,560
|
|
Net income allocable to common units
|
$
|
200,866
|
|
|
$
|
78,897
|
|
|
$
|
110,542
|
|
Net income allocable to subordinated units
|
—
|
|
|
—
|
|
|
21,018
|
|
|||
Limited partners’ interest in net income
|
$
|
200,866
|
|
|
$
|
78,897
|
|
|
$
|
131,560
|
|
Net income per unit – basic and diluted
|
|
|
|
|
|
||||||
Common units
|
$
|
1.83
|
|
|
$
|
0.84
|
|
|
$
|
1.64
|
|
Subordinated units
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1.28
|
|
Weighted average units outstanding – basic and diluted
|
|
|
|
|
|
||||||
Common units
|
109,872
|
|
|
93,936
|
|
|
67,333
|
|
|||
Subordinated units
|
—
|
|
|
—
|
|
|
16,431
|
|
per barrel except natural gas
|
|
2014
|
|
2015
|
|
2016
|
||||||||||||||
Ethane
|
|
$
|
18.36
|
|
−
|
$
|
30.53
|
|
|
$
|
18.41
|
|
−
|
$
|
23.41
|
|
|
$
|
23.11
|
|
Propane
|
|
$
|
46.47
|
|
−
|
$
|
53.78
|
|
|
$
|
47.08
|
|
−
|
$
|
52.99
|
|
|
$
|
52.90
|
|
Isobutane
|
|
$
|
61.24
|
|
−
|
$
|
75.13
|
|
|
$
|
62.09
|
|
−
|
$
|
74.02
|
|
|
$
|
73.89
|
|
Normal butane
|
|
$
|
53.89
|
|
−
|
$
|
66.01
|
|
|
$
|
54.62
|
|
−
|
$
|
65.04
|
|
|
$
|
64.93
|
|
Natural gasoline
|
|
$
|
71.85
|
|
−
|
$
|
83.04
|
|
|
$
|
72.88
|
|
−
|
$
|
81.82
|
|
|
$
|
81.68
|
|
Condensate
|
|
$
|
75.22
|
|
−
|
$
|
83.04
|
|
|
$
|
76.47
|
|
−
|
$
|
81.82
|
|
|
$
|
81.68
|
|
Natural gas (per MMBtu)
|
|
$
|
4.45
|
|
−
|
$
|
6.20
|
|
|
$
|
4.66
|
|
−
|
$
|
5.96
|
|
|
$
|
4.87
|
|
per barrel except natural gas
|
|
2014
|
||||||
Propane
|
|
|
|
$
|
40.38
|
|
||
Normal butane
|
|
$
|
64.73
|
|
−
|
$
|
66.83
|
|
Natural gasoline
|
|
|
|
$
|
90.89
|
|
||
Condensate
|
|
|
|
$
|
87.30
|
|
||
Natural gas (per MMBtu)
|
|
|
|
$
|
3.45
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Gains (losses) on commodity price swap agreements related to sales:
(1)
|
|
|
|
|
|
|
||||||
Natural gas sales
|
|
$
|
21,382
|
|
|
$
|
37,665
|
|
|
$
|
33,845
|
|
Natural gas liquids sales
|
|
102,076
|
|
|
66,260
|
|
|
(36,802
|
)
|
|||
Total
|
|
123,458
|
|
|
103,925
|
|
|
(2,957
|
)
|
|||
Losses on commodity price swap agreements related to purchases
(2)
|
|
(85,294
|
)
|
|
(89,710
|
)
|
|
(27,234
|
)
|
|||
Net gains (losses) on commodity price swap agreements
|
|
$
|
38,164
|
|
|
$
|
14,215
|
|
|
$
|
(30,191
|
)
|
(1)
|
Reported in affiliate natural gas, NGLs and condensate sales in the consolidated statements of income in the period in which the related sale is recorded.
|
(2)
|
Reported in cost of product in the consolidated statements of income in the period in which the related purchase is recorded.
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
General and administrative expenses
|
|
$
|
16,882
|
|
|
$
|
14,904
|
|
|
$
|
11,754
|
|
Public company expenses
|
|
7,152
|
|
|
6,830
|
|
|
7,735
|
|
|||
Total reimbursement
|
|
$
|
24,034
|
|
|
$
|
21,734
|
|
|
$
|
19,489
|
|
|
2013
|
|
2012
|
|
2011
|
|||||||||||||||
|
Weighted-Average Grant-Date Fair Value
|
|
Units
|
|
Weighted-Average Grant-Date Fair Value
|
|
Units
|
|
Weighted-Average Grant-Date Fair Value
|
|
Units
|
|||||||||
Phantom units outstanding at beginning of year
|
$
|
41.77
|
|
|
25,619
|
|
|
$
|
33.92
|
|
|
23,978
|
|
|
$
|
20.19
|
|
|
17,503
|
|
Vested
|
$
|
41.28
|
|
|
(14,695
|
)
|
|
$
|
33.20
|
|
|
(14,260
|
)
|
|
$
|
20.51
|
|
|
(15,119
|
)
|
Granted
|
$
|
62.49
|
|
|
5,920
|
|
|
$
|
45.91
|
|
|
15,901
|
|
|
$
|
35.66
|
|
|
21,594
|
|
Phantom units outstanding at end of year
|
$
|
49.47
|
|
|
16,844
|
|
|
$
|
41.77
|
|
|
25,619
|
|
|
$
|
33.92
|
|
|
23,978
|
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2013
|
|
2012
|
|
2011
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
11,211
|
|
|
$
|
24,705
|
|
|
$
|
3,837
|
|
|
$
|
85
|
|
|
$
|
760
|
|
|
$
|
382
|
|
Net carrying value
|
|
5,309
|
|
|
8,009
|
|
|
1,998
|
|
|
38
|
|
|
393
|
|
|
316
|
|
||||||
Partners’ capital adjustment
|
|
$
|
5,902
|
|
|
$
|
16,696
|
|
|
$
|
1,839
|
|
|
$
|
47
|
|
|
$
|
367
|
|
|
$
|
66
|
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Revenues
(1)
|
|
$
|
829,258
|
|
|
$
|
704,137
|
|
|
$
|
658,680
|
|
Cost of product
(1)
|
|
129,045
|
|
|
145,250
|
|
|
83,722
|
|
|||
Operation and maintenance
(2)
|
|
56,435
|
|
|
51,237
|
|
|
51,339
|
|
|||
General and administrative
(3)
|
|
23,354
|
|
|
92,847
|
|
|
33,305
|
|
|||
Operating expenses
|
|
208,834
|
|
|
289,334
|
|
|
168,366
|
|
|||
Interest income, net
(4)
|
|
16,900
|
|
|
16,900
|
|
|
24,106
|
|
|||
Interest expense
(5)
|
|
—
|
|
|
2,766
|
|
|
4,935
|
|
|||
Distributions to unitholders
(6)
|
|
169,150
|
|
|
98,280
|
|
|
68,039
|
|
|||
Contributions from noncontrolling interest owners
(7)
|
|
—
|
|
|
12,588
|
|
|
16,476
|
|
|||
Distributions to noncontrolling interest owners
(7)
|
|
—
|
|
|
6,528
|
|
|
9,437
|
|
(1)
|
Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.
|
(2)
|
Represents expenses incurred on and subsequent to the date of the acquisition of the Partnership assets, as well as expenses incurred by Anadarko on a historical basis related to the Partnership assets prior to the acquisition of such assets by the Partnership.
|
(3)
|
Represents general and administrative expense incurred on and subsequent to the date of the Partnership’s acquisition of the Partnership assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of the Partnership assets by the Partnership. These amounts include equity-based compensation expense allocated to the Partnership by Anadarko (see
The Incentive Plan
and
WGP LTIP and Anadarko Incentive Plans
within this
Note 5
).
|
(4)
|
Represents interest income recognized on the note receivable from Anadarko. For the year ended December 31, 2011, this line item also includes interest income, net on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets and the Bison assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on the aforementioned assets prior to their acquisition were entirely settled through an adjustment to net investment by Anadarko.
|
(5)
|
For the
year ended December 31, 2012
, includes interest expense recognized on the note payable to Anadarko (see
Note 10
) and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. The Partnership repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012.
|
(6)
|
Represents distributions paid under the partnership agreement.
|
(7)
|
As described in
Note 2
, the Partnership acquired the additional Chipeta interest on August 1, 2012, and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.
|
|
Year Ended December 31,
|
||||||||||
thousands
|
2013
|
|
2012
|
|
2011
|
||||||
Current income tax expense (benefit)
|
|
|
|
|
|
||||||
Federal income tax expense (benefit)
|
$
|
2,304
|
|
|
$
|
(7,555
|
)
|
|
$
|
15,248
|
|
State income tax expense (benefit)
|
640
|
|
|
(1,843
|
)
|
|
322
|
|
|||
Total current income tax expense (benefit)
|
2,944
|
|
|
(9,398
|
)
|
|
15,570
|
|
|||
Deferred income tax expense (benefit)
|
|
|
|
|
|
||||||
Federal income tax expense
|
725
|
|
|
22,328
|
|
|
13,075
|
|
|||
State income tax expense (benefit)
|
(1,039
|
)
|
|
7,785
|
|
|
3,505
|
|
|||
Total deferred income tax expense (benefit)
|
(314
|
)
|
|
30,113
|
|
|
16,580
|
|
|||
Total income tax expense
|
$
|
2,630
|
|
|
$
|
20,715
|
|
|
$
|
32,150
|
|
|
Year Ended December 31,
|
||||||||||
thousands except percentages
|
2013
|
|
2012
|
|
2011
|
||||||
Income before income taxes
|
$
|
288,582
|
|
|
$
|
170,026
|
|
|
$
|
239,011
|
|
Statutory tax rate
|
—
|
%
|
|
—
|
%
|
|
—
|
%
|
|||
Tax computed at statutory rate
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Adjustments resulting from:
|
|
|
|
|
|
||||||
Federal taxes on income attributable to Partnership assets pre-acquisition
|
3,365
|
|
|
17,251
|
|
|
29,502
|
|
|||
State taxes on income attributable to Partnership assets pre-acquisition (net of federal benefit)
|
624
|
|
|
2,206
|
|
|
1,984
|
|
|||
Texas margin tax expense (benefit)
|
(1,359
|
)
|
|
1,258
|
|
|
664
|
|
|||
Income tax expense
|
$
|
2,630
|
|
|
$
|
20,715
|
|
|
$
|
32,150
|
|
Effective tax rate
|
1
|
%
|
|
12
|
%
|
|
13
|
%
|
|
December 31,
|
||||||
thousands
|
2013
|
|
2012
|
||||
Credit carryforwards
|
$
|
14
|
|
|
$
|
14
|
|
Net current deferred income tax assets
|
14
|
|
|
14
|
|
||
Depreciable property
|
(839
|
)
|
|
(47,558
|
)
|
||
Credit carryforwards
|
527
|
|
|
541
|
|
||
Other
|
3
|
|
|
(136
|
)
|
||
Net long-term deferred income tax liabilities
|
(309
|
)
|
|
(47,153
|
)
|
||
Total net deferred income tax liabilities
|
$
|
(295
|
)
|
|
$
|
(47,139
|
)
|
|
|
|
|
December 31,
|
||||||
thousands
|
|
Estimated
Useful Life |
|
2013
|
|
2012
|
||||
Land
|
|
n/a
|
|
$
|
2,584
|
|
|
$
|
501
|
|
Gathering systems
|
|
3 to 47 years
|
|
3,673,008
|
|
|
2,911,572
|
|
||
Pipelines and equipment
|
|
15 to 45 years
|
|
146,008
|
|
|
91,126
|
|
||
Assets under construction
|
|
n/a
|
|
405,633
|
|
|
422,002
|
|
||
Other
|
|
3 to 40 years
|
|
11,867
|
|
|
7,191
|
|
||
Total property, plant and equipment
|
|
|
|
4,239,100
|
|
|
3,432,392
|
|
||
Accumulated depreciation
|
|
|
|
855,845
|
|
|
714,436
|
|
||
Net property, plant and equipment
|
|
|
|
$
|
3,383,255
|
|
|
$
|
2,717,956
|
|
|
|
December 31,
|
||||||
thousands
|
|
2013
|
|
2012
|
||||
Natural gas liquids inventory
|
|
$
|
2,584
|
|
|
$
|
1,678
|
|
Natural gas imbalance receivables
|
|
3,605
|
|
|
1,663
|
|
||
Prepaid insurance
|
|
2,123
|
|
|
1,897
|
|
||
Other
|
|
1,710
|
|
|
1,760
|
|
||
Total other current assets
|
|
$
|
10,022
|
|
|
$
|
6,998
|
|
|
|
December 31,
|
||||||
thousands
|
|
2013
|
|
2012
|
||||
Accrued capital expenditures
|
|
$
|
94,750
|
|
|
$
|
112,311
|
|
Accrued plant purchases
|
|
21,396
|
|
|
16,350
|
|
||
Accrued interest expense
|
|
18,119
|
|
|
15,868
|
|
||
Short-term asset retirement obligations
|
|
1,966
|
|
|
1,711
|
|
||
Short-term remediation and reclamation obligations
|
|
562
|
|
|
799
|
|
||
Other
|
|
218
|
|
|
612
|
|
||
Total accrued liabilities
|
|
$
|
137,011
|
|
|
$
|
147,651
|
|
|
|
Year Ended December 31,
|
||||||
thousands
|
|
2013
|
|
2012
|
||||
Carrying amount of asset retirement obligations at beginning of year
|
|
$
|
66,723
|
|
|
$
|
64,345
|
|
Liabilities incurred
|
|
14,143
|
|
|
9,414
|
|
||
Liabilities settled
|
|
(1,943
|
)
|
|
(786
|
)
|
||
Accretion expense
|
|
4,326
|
|
|
4,270
|
|
||
Revisions in estimated liabilities
|
|
(5,214
|
)
|
|
(10,520
|
)
|
||
Carrying amount of asset retirement obligations at end of year
|
|
$
|
78,035
|
|
|
$
|
66,723
|
|
|
|
December 31, 2013
|
|
December 31, 2012
|
||||||||||||||||||||
thousands
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
|
Principal
|
|
Carrying
Value
|
|
Fair
Value
(1)
|
||||||||||||
4.000% Senior Notes due 2022
|
|
$
|
670,000
|
|
|
$
|
673,278
|
|
|
$
|
641,237
|
|
|
$
|
670,000
|
|
|
$
|
673,617
|
|
|
$
|
669,928
|
|
5.375% Senior Notes due 2021
|
|
500,000
|
|
|
495,173
|
|
|
533,615
|
|
|
500,000
|
|
|
494,661
|
|
|
499,946
|
|
||||||
2.600% Senior Notes due 2018
|
|
250,000
|
|
|
249,718
|
|
|
247,988
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total debt outstanding
|
|
$
|
1,420,000
|
|
|
$
|
1,418,169
|
|
|
$
|
1,422,840
|
|
|
$
|
1,170,000
|
|
|
$
|
1,168,278
|
|
|
$
|
1,169,874
|
|
(1)
|
Fair value is measured using Level 2 inputs.
|
thousands
|
|
Carrying Value
|
||
Balance as of December 31, 2011
|
|
$
|
669,178
|
|
Revolving credit facility borrowings
|
|
374,000
|
|
|
Issuance of 4.000% Senior Notes due 2022
|
|
670,000
|
|
|
Repayment of revolving credit facility
|
|
(374,000
|
)
|
|
Repayment of note payable to Anadarko
|
|
(175,000
|
)
|
|
Revolving credit facility borrowings - Swingline
|
|
20,000
|
|
|
Repayment of revolving credit facility - Swingline
|
|
(20,000
|
)
|
|
Other
|
|
4,100
|
|
|
Balance as of December 31, 2012
|
|
$
|
1,168,278
|
|
Revolving credit facility borrowings
|
|
710,000
|
|
|
Repayments of revolving credit facility
|
|
(710,000
|
)
|
|
Issuance of 2.600% Senior Notes due 2018
|
|
250,000
|
|
|
Other
|
|
(109
|
)
|
|
Balance as of December 31, 2013
|
|
$
|
1,418,169
|
|
|
|
Year Ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Third parties
|
|
|
|
|
|
|
||||||
Interest expense on long-term debt
|
|
$
|
59,293
|
|
|
$
|
41,171
|
|
|
$
|
20,533
|
|
Amortization of debt issuance costs and commitment fees
(1)
|
|
4,449
|
|
|
4,319
|
|
|
5,297
|
|
|||
Capitalized interest
|
|
(11,945
|
)
|
|
(6,196
|
)
|
|
(420
|
)
|
|||
Total interest expense – third parties
|
|
51,797
|
|
|
39,294
|
|
|
25,410
|
|
|||
Affiliates
|
|
|
|
|
|
|
||||||
Interest expense on note payable to Anadarko
(2)
|
|
—
|
|
|
2,440
|
|
|
4,935
|
|
|||
Interest expense on affiliate balances
(3)
|
|
—
|
|
|
326
|
|
|
—
|
|
|||
Total interest expense – affiliates
|
|
—
|
|
|
2,766
|
|
|
4,935
|
|
|||
Interest expense
|
|
$
|
51,797
|
|
|
$
|
42,060
|
|
|
$
|
30,345
|
|
(1)
|
For the
years ended December 31, 2013
and
2012
, includes
$1.0 million
and
$1.1 million
, respectively, of amortization of (i) the original issue discount for the June 2012 offering of the 2022 Notes, partially offset by the original issue premium for the October 2012 offering of the 2022 Notes, (ii) original issue discount for the 2021 Notes and (iii) underwriters’ fees. In addition, for the
year ended December 31, 2013
, includes the amortization of the original issue discount and underwriters’ fees for the 2018 Notes of
$0.2 million
. For the year ended December 31, 2011, includes
$0.5 million
of amortization of the original issue discount and underwriters’ fees for the 2021 Notes.
|
(2)
|
In June 2012, the note payable to Anadarko was repaid in full. See
Note payable to Anadarko
within this
Note 10
.
|
(3)
|
Imputed interest expense on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. In the fourth quarter of 2012, the Partnership repaid the reimbursement payable to Anadarko associated with the construction of the Brasada facility and Lancaster plant.
|
thousands
|
Operating Leases
|
||
2014
|
$
|
309
|
|
2015
|
245
|
|
|
2016
|
233
|
|
|
2017
|
157
|
|
|
2018
|
34
|
|
|
Thereafter
|
—
|
|
|
Total
|
$
|
978
|
|
thousands except per-unit amounts
|
First
Quarter
|
|
Second
Quarter
|
|
Third
Quarter
|
|
Fourth
Quarter
|
||||||||
2013
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
229,747
|
|
|
$
|
255,126
|
|
|
$
|
278,001
|
|
|
$
|
290,621
|
|
Operating income
|
$
|
64,036
|
|
|
$
|
70,127
|
|
|
$
|
90,188
|
|
|
$
|
97,291
|
|
Net income
|
$
|
52,888
|
|
|
$
|
62,060
|
|
|
$
|
81,776
|
|
|
$
|
89,228
|
|
Net income attributable to Western Gas Partners, LP
|
$
|
50,657
|
|
|
$
|
60,200
|
|
|
$
|
78,400
|
|
|
$
|
85,879
|
|
Net income per common unit – basic and diluted
(1)
|
$
|
0.31
|
|
|
$
|
0.41
|
|
|
$
|
0.53
|
|
|
$
|
0.56
|
|
2012
|
|
|
|
|
|
|
|
||||||||
Revenues
|
$
|
224,676
|
|
|
$
|
220,310
|
|
|
$
|
234,734
|
|
|
$
|
230,867
|
|
Operating income
(2)
|
$
|
67,221
|
|
|
$
|
59,280
|
|
|
$
|
61,312
|
|
|
$
|
7,081
|
|
Net income (loss)
(2)
|
$
|
57,894
|
|
|
$
|
47,599
|
|
|
$
|
50,002
|
|
|
$
|
(6,184
|
)
|
Net income (loss) attributable to Western Gas Partners, LP
(2)
|
$
|
53,651
|
|
|
$
|
43,309
|
|
|
$
|
46,579
|
|
|
$
|
(9,118
|
)
|
Net income (loss) per common unit – basic and diluted
(1) (2)
|
$
|
0.48
|
|
|
$
|
0.33
|
|
|
$
|
0.33
|
|
|
$
|
(0.27
|
)
|
(1)
|
Represents net income earned on and subsequent to the acquisition of the Partnership assets (as defined in
Note 1—Summary of Significant Accounting Policies
).
|
(2)
|
During the fourth quarter of 2012, the Partnership was allocated
$54.9 million
of general and administrative expenses from Anadarko associated with the Incentive Plan (as defined and described in
Note 1—Summary of Significant Accounting Policies
and
Note 5—Transactions with Affiliates
).
|
Name
|
|
Age
|
|
Position with Western Gas Holdings, LLC
|
|
Robert G. Gwin
|
|
50
|
|
|
Chairman of the Board
|
Donald R. Sinclair
|
|
56
|
|
|
President, Chief Executive Officer and Director
|
Benjamin M. Fink
|
|
43
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Danny J. Rea
|
|
55
|
|
|
Senior Vice President and Chief Operating Officer (retired effective December 31, 2013)
|
Philip H. Peacock
|
|
42
|
|
|
Vice President, General Counsel and Corporate Secretary
|
Steven D. Arnold
|
|
53
|
|
|
Director
|
Milton Carroll
|
|
63
|
|
|
Director
|
James R. Crane
|
|
60
|
|
|
Director
|
Charles A. Meloy
|
|
53
|
|
|
Director
|
Robert K. Reeves
|
|
56
|
|
|
Director
|
David J. Tudor
|
|
54
|
|
|
Director
|
Robert G. Gwin
Age: 50
Houston, Texas
Director since:
August 2007
Not Independent
Officer From:
August 2007 to
January 2010
|
Biography/Qualifications
Robert G. Gwin has served as a director of our general partner since August 2007 and has served as non-executive Chairman of the Board of our general partner since October 2009. He also served as Chief Executive Officer of our general partner from August 2007 to January 2010 and as President from August 2007 to September 2009. Mr. Gwin has served as Chairman of the Board of WGP GP since September 2012. He was named Executive Vice President, Finance and Chief Financial Officer of Anadarko in May 2013 and previously served as Senior Vice President, Finance and Chief Financial Officer since March 2009, prior to which, he served as Senior Vice President of Anadarko beginning in March 2008, and as Vice President, Finance and Treasurer beginning in January 2006. Mr. Gwin is Chairman of the Board of LyondellBasell Industries N.V. and he also serves on the boards of The Greater Houston Partnership, Theatre Under the Stars and Communities in Schools. Mr. Gwin holds a Bachelor of Science degree from the University of Southern California and a Master of Business Administration degree from the Fuqua School of Business at Duke University, and he is a Chartered Financial Analyst.
|
|
|
Donald R. Sinclair
Age: 56
Houston, Texas
Director since:
October 2009
Not Independent
Officer Since:
October 2009
|
Biography/Qualifications
Donald R. Sinclair has served as President and a director of our general partner since October 2009 and as Chief Executive Officer since January 2010. Mr. Sinclair has served as the President and Chief Executive Officer and as a director of WGP GP since September 2012. Prior to becoming President and a director of our general partner, Mr. Sinclair was a founding partner and served as President of Ceritas Energy, LLC, a midstream energy company headquartered in Houston with operations in Texas, Wyoming and Utah from February 2003 to September 2009. Mr. Sinclair has worked in the oil and gas industry for over 33 years, with a focus on marketing and trading and the midstream sector. He is a member of the Advisory Council for the Rawls College of Business at Texas Tech University. He earned a Bachelor of Business Administration in Management from Texas Tech University.
|
|
|
Benjamin M. Fink
Age: 43
Houston, Texas
Officer since:
May 2009
|
Biography/Qualifications
Benjamin M. Fink has served as the Senior Vice President and Chief Financial Officer of our general partner since May 2009, and as Senior Vice President, Chief Financial Officer and Treasurer of our general partner since November 2010. Mr. Fink has served as Senior Vice President, Chief Financial Officer and Treasurer of WGP GP since September 2012. He was Director, Finance of Anadarko from April 2007 to May 2009, during which time he was responsible for principal oversight of the finance operations of an Anadarko subsidiary, Anadarko Algeria Company, LLC. From August 2006 to April 2007, he served as an independent financial consultant to Anadarko in its Beijing, China and Rio de Janeiro, Brazil offices. From April 2001 until June 2006, he held executive management positions at Prosoft Learning Corporation, including serving as its President and Chief Executive Officer from November 2004 until that company’s sale in June 2006. From 2000 to 2001 he co-founded and served as Chief Operating Officer and Chief Financial Officer of Meta4 Group Limited, an online direct marketer based in Hong Kong and Tokyo. Previously, he held positions of increasing responsibility at Prudential Capital Group and Prudential Asset Management Asia, where he focused on the negotiation, structuring and execution of private debt and equity investments. He holds a Bachelor of Science degree in Economics from the Wharton School of the University of Pennsylvania, and he is a Chartered Financial Analyst.
|
Danny J. Rea
Age: 55
Houston, Texas
Officer since:
August 2007
|
Biography/Qualifications
Prior to his retirement on December 31, 2013, Danny J. Rea had served as Senior Vice President and Chief Operating Officer of our general partner since August 2007 and as Vice President, Midstream of Anadarko since May 2007. He also served as a director of our general partner from August 2007 to September 2009. Mr. Rea served as Senior Vice President and Chief Operating Officer of WGP GP from September 2012 to December 2013. Previously, Mr. Rea served as Manager, Midstream Services of Anadarko from May 2004 to May 2007 and Manager, Gas Field Services from August 2000 to May 2004. Mr. Rea joined Anadarko as an engineer in 1981 and held positions of increasing responsibility over his 32 years at Anadarko. He holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University, and a Master of Business Administration degree from the University of Houston. He served on the board of directors for the Wyoming Pipeline Authority from March 2006 until March 2010, currently serves on the board of directors of the Texas Pipeline Association, and is a member of the Gas Processors Association and the Society of Petroleum Engineers.
|
|
|
Steven D. Arnold
Age: 53
Houston, Texas
Director since:
February 2014
Independent
|
Biography/Qualifications
Steven D. Arnold was appointed as a director of our general partner and as a member of the special and audit committees of the board of directors in February 2014. Mr. Arnold served on the board of directors of the general partner of Spectra Energy Partners, LP from 2007 to December 2013, during which time he served on that board’s audit committee and its conflicts committee. He served as Chairman of each of those committees at separate times during his board membership. Mr. Arnold is engaged in private investment management and consulting services in Houston, Texas through 3 Lights Management Co., serving as its President since inception in 2000. Mr. Arnold has over 10 years of institutional investment management experience with Prudential Financial, Inc. He is a board director of Houston Methodist Research Institute, Curing Children’s Cancer Fund, and chairs the Advisory Board of Texas Children’s Hospital Cancer Center. Mr. Arnold holds a Bachelor of Science degree in Petroleum Engineering from The University of Texas at Austin and a Masters of Business Administration from Rice University. Mr. Arnold brings a strong risk assessment and strategic expertise to the board.
|
|
|
Philip H. Peacock
Age: 42
Houston, Texas
Officer since:
August 2012
|
Biography/Qualifications
Philip H. Peacock has served as Vice President, General Counsel and Corporate Secretary of our general partner since August 2012. Mr. Peacock has served as Vice President, General Counsel and Corporate Secretary of WGP GP since September 2012. Prior to joining our general partner, Mr. Peacock was a partner practicing corporate and securities law at the law firm of Andrews Kurth LLP, which he joined in August 2003. Mr. Peacock holds a Bachelor of Arts degree from Princeton University, a Master of Arts degree from the University of Houston, and a Juris Doctor degree from the University of Virginia. He is licensed to practice law in the state of Texas and serves on the Board of Directors of The Children’s Fund, Inc.
|
|
|
Milton Carroll
Age: 63
Houston, Texas
Director since:
April 2008
Independent
|
Biography/Qualifications
Milton Carroll has served as a director of our general partner and as Chairman of the special committee of the board of directors since April 2008. Mr. Carroll currently serves as Chairman of Houston-based CenterPoint Energy, Inc., where he has been a director since 1992. He also serves as Chairman of Health Care Services Corporation (a Chicago-based company operating through its Blue Cross and Blue Shield divisions in Illinois, Texas, Oklahoma, New Mexico, and Montana), as a director of Halliburton Company, where he serves as a member of the compensation committee and the nominating and corporate governance committee, and as a director of LyondellBasell Industries N.V., where he serves as a member of the nominating and governance committee and the compensation committee. Mr. Carroll served as director of the general partner of LRR Energy, LP from November 2011 to January 2014. Mr. Carroll also served as a director of EGL, Inc. from May 2003 until August 2007 and as a director of the general partner of DCP Midstream Partners, LP from December 2005 to December 2006. Mr. Carroll holds a Bachelor of Science degree in Industrial Technology from Texas Southern University.
|
James R. Crane
Age: 60
Houston, Texas
Director since:
April 2008
Independent
|
Biography/Qualifications
James R. Crane has served as a director of our general partner and as a member of the special and audit committees of the board of directors since April 2008. In November 2011, Mr. Crane became the principal owner and Chairman of the Houston Astros Baseball Club. Mr. Crane is also the Chairman and Chief Executive Officer of Crane Capital Group Inc., an investment management company he founded. Crane Capital Group currently invests in transportation, power distribution, real estate and asset management. Its holdings include Crane Worldwide Logistics, a premier global provider of customized transportation and logistics services with 54 offices in 20 countries, and Champion Energy Services, a retail electric provider. Prior to founding Crane Capital Group Inc., he was founder, Chairman and Chief Executive Officer of EGL, Inc., a global transportation, supply chain management and information services company, from 1984 until its sale in August 2007. Mr. Crane currently serves as a director of Nabors Industries Ltd., an international drilling contractor and well-services provider. From February 2010 to February 2012, he served as a director of Fort Dearborn Life Insurance Company, a subsidiary of Health Care Service Corporation, and from 1999 to November 2007 he served as a director of HCC Insurance Holdings, Inc. Mr. Crane holds a Bachelor of Science degree in Industrial Safety from the University of Central Missouri.
|
|
|
Charles A. Meloy
Age: 53
Houston, Texas
Director since:
February 2009
Not Independent
|
Biography/Qualifications
Charles A. Meloy has served as a director of our general partner since February 2009 and as a director of WGP GP since September 2012. Mr. Meloy was named Executive Vice President, U.S. Onshore Exploration and Production of Anadarko in May 2013, and previously served as Senior Vice President, U.S. Onshore Exploration and Production since July 2012, prior to which he serviced as Senior Vice President, Worldwide Operations since December 2006. Before joining Anadarko, he served as Vice President of Exploration and Production at Kerr-McGee Corporation, prior to its acquisition by Anadarko. At Kerr-McGee, Mr. Meloy was Vice President of Gulf of Mexico exploration, production and development from 2004 to 2005, was Vice President and Managing Director of North Sea operations from 2002 to 2004, and held several other deepwater Gulf of Mexico management positions beginning in 1999. Earlier in his career, Mr. Meloy held various planning, operations, deepwater and reservoir engineering positions with Oryx Energy Company and its predecessor, Sun Oil Company. He earned a Bachelor’s degree in Chemical Engineering from Texas A&M University and is a member of the Society of Petroleum Engineers and Texas Professional Engineers. Mr. Meloy is also a member of the Board of Directors of the Independent Producers of America Association.
|
|
|
Robert K. Reeves
Age: 56
Houston, Texas
Director since:
August 2007
Not Independent
|
Biography/Qualifications
Robert K. Reeves has served as a director of our general partner since August 2007 and as a director of WGP GP since September 2012. Mr. Reeves was named Executive Vice President, General Counsel and Chief Administrative Officer of Anadarko in May 2013 and previously served as Senior Vice President, General Counsel and Chief Administrative Officer since February 2007, prior to which he served as Senior Vice President, Corporate Affairs & Law and Chief Governance Officer of Anadarko beginning in 2004. He has also served as a director of Key Energy Services, Inc., a publicly traded oil field services company, since October 2007. Prior to joining Anadarko, he served as Executive Vice President, Administration and General Counsel of North Sea New Ventures from 2003 to 2004 and as Executive Vice President, General Counsel and Secretary of Ocean Energy, Inc. and its predecessor companies from 1997 to 2003. Mr. Reeves holds a Bachelor of Science degree in Business Administration and a Juris Doctor degree from Louisiana State University.
|
David J. Tudor
Age: 54
Houston, Texas
Director since:
April 2008
Independent
|
Biography/Qualifications
David J. Tudor has served as a director of our general partner and as Chairman of the audit committee of the board of directors since April 2008 and served as a member of the special committee from April 2008 to December 2012. Mr. Tudor has served as a director of WGP GP and as Chairman of its audit committee since December 2012. Since May 2013, Mr. Tudor has served as President and Chief Executive Officer of Champion Energy Services, a retail electric provider serving residential, governmental, commercial and industrial customers in a growing number of deregulated electric energy markets throughout the United States. From 1999 through May 2013, Mr. Tudor was the President and Chief Executive Officer of ACES, an Indianapolis-based commodity risk management company owned by 20 generation and transmission cooperatives throughout the U.S. Prior to joining ACES, Mr. Tudor was the Executive Vice President & Chief Operating Officer of PG&E Energy Trading, where he managed commercial operations in the U.S. and Canada. He also currently serves as a director of Wabash Valley Power Association’s Board Risk Oversight Committee and as an external member of the Risk Oversight Committee of the East Kentucky Power Cooperative. Mr. Tudor holds a Bachelor of Science degree in Accounting from David Lipscomb University.
|
Officers of Our General Partner
|
|
Time
Allocated
|
|
Anadarko Corporate Officer
|
Donald R. Sinclair
|
|
75.0%
|
|
Yes
|
Benjamin M. Fink
|
|
90.0%
|
|
Yes
|
Danny J. Rea
|
|
40.0%
|
|
Yes
|
Philip H. Peacock
|
|
50.0%
|
|
No
|
•
|
base salary;
|
•
|
annual cash incentives;
|
•
|
equity-based compensation, which includes equity-based compensation under Anadarko’s 2012 Omnibus Incentive Compensation Plan (the “Omnibus Plan”) and the WGP LTIP; and
|
•
|
Anadarko’s other benefits, including welfare and retirement benefits, severance benefits and change of control benefits, plus other benefits on the same basis as other eligible Anadarko employees.
|
•
|
retirement benefits to match competitive practices in Anadarko’s industry, including participation in Anadarko’s employee savings plan, savings restoration plan, retirement plan and retirement restoration plan;
|
•
|
severance benefits under the Anadarko Officer Severance Plan;
|
•
|
certain change of control benefits under key employee change of control contracts;
|
•
|
director and officer indemnification agreements;
|
•
|
a limited number of perquisites, including financial counseling, tax preparation and estate planning, an executive physical program, management life insurance, and personal excess liability insurance; and
|
•
|
benefits, including medical, dental, vision, flexible spending accounts, paid time off, life insurance and disability coverage, which are also provided to all other eligible U.S.-based Anadarko employees.
|
Name and Principal Position
|
|
Year
|
|
Salary
($)
(1)
|
|
Bonus
($)
|
|
Stock
Awards
($)
(2)
|
|
Option
Awards
($)
(3)
|
|
Non-Equity
Incentive Plan Compensation
($)
(4)
|
|
All Other
Compensation
($)
(5)
|
|
Total
($)
|
|||||||
Donald R. Sinclair
|
|
2013
|
|
283,414
|
|
|
—
|
|
|
843,813
|
|
|
280,588
|
|
|
243,736
|
|
|
123,110
|
|
|
1,774,661
|
|
President and
|
|
2012
|
|
271,298
|
|
|
—
|
|
|
506,296
|
|
|
168,623
|
|
|
—
|
|
|
113,250
|
|
|
1,059,467
|
|
Chief Executive Officer
|
2011
|
|
246,779
|
|
|
—
|
|
|
534,435
|
|
|
181,899
|
|
|
177,681
|
|
|
106,296
|
|
|
1,247,090
|
|
|
Benjamin M. Fink
|
|
2013
|
|
280,904
|
|
|
—
|
|
|
760,623
|
|
|
202,020
|
|
|
191,015
|
|
|
121,704
|
|
|
1,556,266
|
|
Senior Vice President, Chief
|
|
2012
|
|
263,062
|
|
|
—
|
|
|
261,073
|
|
|
—
|
|
|
—
|
|
|
109,813
|
|
|
633,948
|
|
Financial Officer and Treasurer
|
2011
|
|
253,506
|
|
|
—
|
|
|
160,420
|
|
|
45,860
|
|
|
136,893
|
|
|
109,220
|
|
|
705,899
|
|
|
Danny J. Rea
(6)
|
|
2013
|
|
130,692
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
56,909
|
|
|
187,601
|
|
Senior Vice President and
|
|
2012
|
|
124,692
|
|
|
—
|
|
|
192,787
|
|
|
127,905
|
|
|
—
|
|
|
52,051
|
|
|
497,435
|
|
Chief Operating Officer
|
2011
|
|
115,154
|
|
|
—
|
|
|
191,658
|
|
|
130,336
|
|
|
82,911
|
|
|
49,603
|
|
|
569,662
|
|
|
Philip H. Peacock
|
|
2013
|
|
121,154
|
|
|
—
|
|
|
70,016
|
|
|
—
|
|
|
58,154
|
|
|
52,482
|
|
|
301,806
|
|
Vice President, General Counsel
|
|
2012
|
|
43,269
|
|
|
—
|
|
|
75,006
|
|
|
—
|
|
|
18,173
|
|
|
17,960
|
|
|
154,408
|
|
and Corporate Secretary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The amounts in this column reflect the base salary compensation allocated to us by Anadarko for the fiscal years ended
December 31, 2013
,
2012
and
2011
.
|
(2)
|
The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for non-option stock awards granted pursuant to the WES LTIP, the WGP LTIP and the 2008 and 2012 Anadarko Omnibus Incentive Compensation Plans. For awards of phantom units granted under the WES LTIP and WGP LTIP, the grant date value is determined by multiplying the number of phantom units awarded by the per-unit closing price of the underlying common units on the date of grant. For a discussion of valuation assumptions for the awards under the 2008 and 2012 Anadarko Omnibus Incentive Compensation Plans, see
Note 15—Share-Based Compensation
in the
Notes to Consolidated Financial Statements
included under Item 8 of Anadarko’s Form 10-K for the year ended
December 31, 2013
(which is not, and shall not be deemed to be, incorporated by reference herein). For information regarding the non-option stock awards granted to the named executives in
2013
, please see the Grants of Plan-Based Awards Table.
|
(3)
|
The amounts in this column reflect the expected allocation to us of the grant date fair value, computed in accordance with FASB ASC Topic 718 (without respect to the risk of forfeitures), for option awards granted pursuant to the 2008 and 2012 Anadarko Omnibus Incentive Compensation Plans. See note (2) above for valuation assumptions. For information regarding the option awards granted to the named executives in
2013
, please see the Grants of Plan-Based Awards Table.
|
(4)
|
The amounts in this column reflect the compensation under the Anadarko annual incentive program expected to be allocated to us for the fiscal years ended
December 31, 2013
, and allocated to us for the fiscal years ended December 31,
2012
and
2011
. The
2013
amounts represent payments which were earned in
2013
and are expected to be paid in early
2014
, the
2012
amounts represent payments which were earned in
2012
and paid in early
2013
and the
2011
amounts represent the payments which were earned in
2011
and paid in early
2012
. For an explanation of the
2013
annual incentive plan awards, please read
Compensation Discussion and Analysis – Analysis of 2013 Compensation Actions – Performance-Based Annual Cash Incentives (Bonuses)
.
|
(5)
|
The amounts in this column reflect the compensation expenses related to Anadarko’s retirement and savings plans that were allocated to us for the fiscal years ended
December 31, 2013
,
2012
and
2011
. The
2013
allocated expenses are detailed in the table below:
|
Name
|
|
Retirement Plan Expense
|
|
Savings Plan Expense
|
||||
Donald R. Sinclair
|
|
$
|
92,849
|
|
|
$
|
30,261
|
|
Benjamin M. Fink
|
|
$
|
91,777
|
|
|
$
|
29,927
|
|
Danny J. Rea
|
|
$
|
42,920
|
|
|
$
|
13,989
|
|
Philip H. Peacock
|
|
$
|
39,577
|
|
|
$
|
12,905
|
|
(6)
|
Mr. Rea retired from Anadarko and his position as Senior Vice President and Chief Operating Officer of our general partner on December 31, 2013. As a result of his retirement prior to annual incentive program payments, he did not receive a 2013 annual incentive plan award.
|
|
|
|
|
|
|
|
|
|
|
All
Other
Stock
Awards:
Number of
Shares of
Stock or
Units
(#)
(3)
|
|
All Other
Option
Awards:
Number of
Securities
Underlying
Options
(#)
(4)
|
|
Exercise
or
Base Price
of Option
Awards
($/Sh)
|
|
Grant
Date
Fair Value
of Stock
and
Option
Awards
($)
(5)
|
||||||||||||||
|
|
Estimated Future Payouts
Under Non-Equity
Incentive Plan Awards
(1)
|
|
Estimated Future Payouts Under
Equity Incentive Plan Awards
(2)
|
|
|
|
|
||||||||||||||||||||||
Name and Grant Date
|
|
Threshold
($)
|
|
Target
($)
|
|
Maximum
($)
|
|
Threshold
(#)
|
|
Target
(#)
|
|
Maximum
(#)
|
|
|
|
|
||||||||||||||
Donald R. Sinclair
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
203,113
|
|
|
243,736
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
11/06/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,057
|
|
|
|
|
|
|
281,305
|
|
||||||||
11/06/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,818
|
|
|
92.02
|
|
|
280,588
|
|
|||||||
11/20/13
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,683
|
|
|
|
|
|
|
562,508
|
|
||||||||
Benjamin M. Fink
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
159,179
|
|
|
191,015
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
03/07/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,935
|
|
|
|
|
|
|
243,039
|
|
||||||||
06/07/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
512
|
|
|
|
|
|
|
45,055
|
|
||||||||
06/07/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,453
|
|
|
87.98
|
|
|
44,896
|
|
|||||||
11/06/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,712
|
|
|
|
|
|
|
157,520
|
|
||||||||
11/06/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,058
|
|
|
92.02
|
|
|
157,124
|
|
|||||||
11/20/13
(6)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,663
|
|
|
|
|
|
|
315,009
|
|
||||||||
Danny J. Rea
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
82,227
|
|
|
98,673
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
11/06/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,442
|
|
|
92.02
|
|
|
—
|
|
|||||||
11/06/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
897
|
|
|
|
|
|
|
—
|
|
||||||||
11/06/13
|
|
|
|
|
|
|
|
356
|
|
|
1,318
|
|
|
2,636
|
|
|
|
|
|
|
|
|
—
|
|
||||||
Philip H. Peacock
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
—
|
|
—
|
|
|
48,462
|
|
|
58,154
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||
03/07/13
|
|
|
|
|
|
|
|
|
|
|
|
|
|
846
|
|
|
|
|
|
|
70,016
|
|
(1)
|
Reflects the estimated
2013
cash payouts allocable to us under Anadarko’s annual incentive plan. If threshold levels of performance are not met, then the payout can be zero. The maximum value reflects the maximum amount allocable to us consistent with the methodologies set forth in the services and secondment agreement. The expense expected to be allocated to us for the actual bonus payouts under the annual incentive program for 2013 is reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. For additional discussion of Anadarko’s annual incentive plan please read
Compensation Discussion and Analysis — Analysis of
2013
Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses)
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
April 3, 2014
.
|
(2)
|
Reflects the estimated future payout allocable to us under Anadarko’s performance units awarded in
2013
. Under the performance unit program, participants may earn from 0% to 200% of the targeted award based on Anadarko’s relative total shareholder return performance over a specified performance period. Fifty percent of this award is tied to a two-year performance period and the remaining fifty percent is tied to a three-year performance period. If earned, the awards are to be paid in cash rather than equity. The threshold value represents the minimum payment (other than zero) that may be earned. For additional discussion of Anadarko’s performance unit awards please read
Compensation Discussion and Analysis — Analysis of
2013
Compensation Actions — Equity Compensation
contained within Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
April 3, 2014
.
|
(3)
|
Reflects the allocable number of phantom units under the WGP LTIP and restricted stock shares and restricted stock units awarded in
2013
under the Omnibus Plan. These awards vest equally over three years, beginning with the first anniversary of the grant date. Executive officers receive distribution equivalent rights on the phantom units and dividends on the restricted stock shares. For restricted stock units, dividend equivalents are reinvested in shares of Anadarko common stock and paid upon the applicable vesting of the underlying award.
|
(4)
|
Reflects the allocable number of Anadarko stock options each named executive officer was awarded in
2013
. These awards vest equally over three years, beginning with the first anniversary of the date of grant and have a term of seven years.
|
(5)
|
The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the expected allocation to us of the grant date fair value of the awards made to named executives in
2013
computed in accordance with FASB ASC Topic 718. The value ultimately realized by the executive upon the actual vesting of the award(s) or the exercise of the stock option(s) may or may not be equal to the determined value. For awards of phantom units granted under the WGP LTIP, the grant date value is determined by multiplying the number of phantom units awarded by the per-unit closing price of the underlying common units on the date of grant. For a discussion of valuation assumptions for the awards under the Omnibus Plan, see
Note 15—Share-Based Compensation
in the
Notes to Consolidated Financial Statements
under Item 8 of Anadarko’s Form 10-K for the year ended
December 31, 2013
(which is not, and shall not be deemed to be, incorporated by reference herein).
|
(6)
|
Reflects an award of phantom units granted under the WGP LTIP.
|
(1)
|
The table below shows the vesting dates for the respective unexercisable stock options listed in the above Outstanding Equity Awards Table:
|
Vesting Date
|
|
Donald R. Sinclair
|
|
Benjamin M. Fink
|
|
Danny J. Rea
|
|
Philip H. Peacock
|
||||
03/04/2014
|
|
—
|
|
|
524
|
|
|
—
|
|
|
—
|
|
06/07/2014
|
|
—
|
|
|
484
|
|
|
—
|
|
|
—
|
|
11/05/2014
|
|
2,168
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/06/2014
|
|
3,606
|
|
|
2,020
|
|
|
—
|
|
|
—
|
|
11/16/2014
|
|
2,114
|
|
|
—
|
|
|
—
|
|
|
—
|
|
06/07/2015
|
|
—
|
|
|
484
|
|
|
—
|
|
|
—
|
|
11/05/2015
|
|
2,169
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/06/2015
|
|
3,606
|
|
|
2,019
|
|
|
—
|
|
|
—
|
|
06/07/2016
|
|
—
|
|
|
485
|
|
|
—
|
|
|
—
|
|
11/06/2016
|
|
3,606
|
|
|
2,019
|
|
|
—
|
|
|
—
|
|
(2)
|
The table below shows the vesting dates for the respective phantom units, restricted stock shares and restricted stock units listed in the above Outstanding Equity Awards Table:
|
Vesting Date
|
|
Donald R. Sinclair
|
|
Benjamin M. Fink
|
|
Danny J. Rea
|
|
Philip H. Peacock
|
||||
03/03/2014
|
|
—
|
|
|
1,054
|
|
|
—
|
|
|
—
|
|
03/04/2014
|
|
—
|
|
|
660
|
|
|
—
|
|
|
—
|
|
03/07/2014
|
|
—
|
|
|
978
|
|
|
—
|
|
|
282
|
|
06/07/2014
|
|
—
|
|
|
172
|
|
|
—
|
|
|
|
|
09/04/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
362
|
|
11/05/2014
|
|
802
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/06/2014
|
|
1,022
|
|
|
572
|
|
|
—
|
|
|
—
|
|
11/08/2014
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/14/2014
|
|
2,394
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/16/2014
|
|
4,051
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/20/2014
|
|
4,562
|
|
|
2,554
|
|
|
—
|
|
|
—
|
|
03/03/2015
|
|
—
|
|
|
1,054
|
|
|
—
|
|
|
—
|
|
03/07/2015
|
|
—
|
|
|
979
|
|
|
—
|
|
|
282
|
|
06/07/2015
|
|
—
|
|
|
171
|
|
|
—
|
|
|
—
|
|
09/04/2015
|
|
—
|
|
|
—
|
|
|
—
|
|
|
361
|
|
11/05/2015
|
|
802
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/06/2015
|
|
1,021
|
|
|
571
|
|
|
—
|
|
|
—
|
|
11/14/2015
|
|
2,394
|
|
|
—
|
|
|
—
|
|
|
—
|
|
11/20/2015
|
|
4,561
|
|
|
2,554
|
|
|
—
|
|
|
—
|
|
03/07/2016
|
|
—
|
|
|
978
|
|
|
—
|
|
|
282
|
|
06/07/2016
|
|
—
|
|
|
171
|
|
|
—
|
|
|
—
|
|
11/06/2016
|
|
1,021
|
|
|
572
|
|
|
—
|
|
|
—
|
|
11/20/2016
|
|
4,560
|
|
|
2,555
|
|
|
—
|
|
|
—
|
|
(3)
|
The table below shows the performance periods for the respective performance units listed in the above Outstanding Equity Awards Table. As a result of Mr. Rea’s retirement, his outstanding performance units were pro-rated based on the number of months he worked during the applicable performance periods. Except for the awards with performance periods beginning January 1, 2013, the number of outstanding units disclosed is calculated based on Anadarko’s performance to date for each award. As of December 31, 2013, the performance to date calculation for the awards with performance periods beginning January 1, 2013 was 0%, however, in accordance with the rules, we have disclosed the threshold performance payout of 54%. The estimated payout percentages reflect our relative performance ranking as of
December 31, 2013
, and are not necessarily indicative of what the payout percentage earned will be at the end of the performance period.
|
Performance Period
|
|
APC Performance to Date Payout %
|
|
Danny J. Rea Performance Units
|
1/1/2011 to 12/31/2013
|
|
92%
|
|
581
|
1/1/2012 to 12/31/2013
|
|
54%
|
|
217
|
1/1/2012 to 12/31/2014
|
|
54%
|
|
145
|
1/1/2013 to 12/31/2014
|
|
54%
|
|
135
|
1/1/2013 to 12/31/2015
|
|
54%
|
|
90
|
(4)
|
These awards represent grants of phantom units under the WES LTIP. The market values for these awards are based on the closing common unit price for the Partnership on
December 31, 2013
, of
$61.69
.
|
(5)
|
These awards represent grants of phantom units under the WGP LTIP. The market values for these awards are based on the closing common unit price for WGP on
December 31, 2013
of $39.51.
|
|
|
Option Awards
|
|
Stock Awards
|
||||||||
Name
|
|
Number of Shares Acquired on Exercise (#)
(1)
|
|
Value Realized on Exercise ($)
(1)
|
|
Number of Shares Acquired on Vesting (#)
(2)
|
|
Value Realized on Vesting ($)
(2)
|
||||
Donald R. Sinclair
|
|
—
|
|
|
—
|
|
|
8,126
|
|
|
573,841
|
|
Benjamin M. Fink
|
|
—
|
|
|
—
|
|
|
2,111
|
|
|
169,956
|
|
Danny J. Rea
|
|
—
|
|
|
—
|
|
|
2,524
|
|
|
219,601
|
|
Philip H. Peacock
|
|
—
|
|
|
—
|
|
|
362
|
|
|
33,362
|
|
(1)
|
Shares acquired and values realized on exercise include options exercised in 2013. The actual value ultimately realized by the named executive officer may be more or less than the realized value calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise.
|
(2)
|
Shares acquired and values realized on vesting reflect the taxable value to the named executive officer as of the date of the vesting in 2013 of restricted stock shares or units, performance units, or phantom units. For restricted stock shares or units and phantom units, the actual value ultimately realized by the named executive officer may be more or less than the value realized calculated in the above table depending on the timing in which the named executive officer held or sold the stock associated with the exercise or vesting occurrence.
|
Name
|
|
Accelerated WES/WGP LTIP Awards
(1)
|
||
Donald R. Sinclair
|
|
$
|
1,039,472
|
|
Benjamin M. Fink
|
|
$
|
302,749
|
|
Philip H. Peacock
|
|
$
|
—
|
|
(1)
|
WES LTIP phantom units are valued based on the closing WES common unit price of
$61.69
on
December 31, 2013
; WGP LTIP phantom units are valued based on the closing WGP common unit price of $39.51 on December 31, 2013.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Mr. Peacock
|
||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Total
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Mr. Peacock
|
||||||
Cash Severance
(1)
|
$
|
840,000
|
|
|
$
|
787,050
|
|
|
$
|
—
|
|
Pro-rata Bonus for 2013
(2)
|
243,736
|
|
|
191,015
|
|
|
—
|
|
|||
Accelerated Anadarko Equity Compensation
(3)
|
468,038
|
|
|
629,142
|
|
|
124,413
|
|
|||
Health and Welfare Benefits
(4)
|
61,026
|
|
|
47,552
|
|
|
—
|
|
|||
Total
|
$
|
1,612,800
|
|
|
$
|
1,654,759
|
|
|
$
|
124,413
|
|
(1)
|
Messrs. Sinclair’s and Fink’s values assume two times base salary plus one times target bonus multiplied by their allocation percentages in effect as of
December 31, 2013
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(2)
|
Payment, if provided, will be paid at the end of the performance period based on actual performance. The values for Messrs. Sinclair and Fink reflect the allocated portion of their actual bonuses awarded under the AIP. For additional discussion of this program please see section
Compensation Discussion and Analysis — Analysis of 2013 Compensation Actions — Performance-Based Annual Cash Incentives (Bonuses)
of Anadarko’s proxy statement for its annual meeting of stockholders, which is expected to be filed no later than
April 3, 2014
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(3)
|
Reflects the in-the-money value of unvested stock options and the value of unvested restricted stock shares and restricted stock units, under Anadarko equity plans, all as of
December 31, 2013
.
|
(4)
|
Messrs. Sinclair’s and Fink’s values represent 24 months of health and welfare benefit coverage. These amounts are present values determined in accordance with GAAP. These values reflect their allocation percentage in effect as of
December 31, 2013
. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Mr. Peacock
|
||||||
Cash Severance
(1)
|
$
|
1,489,875
|
|
|
$
|
1,027,496
|
|
|
$
|
—
|
|
Pro-rata Bonus for 2013
(2)
|
243,736
|
|
|
191,015
|
|
|
—
|
|
|||
Accelerated Anadarko Equity Compensation
(3)
|
468,038
|
|
|
629,142
|
|
|
124,413
|
|
|||
Accelerated WES/WGP Equity Compensation
(4)
|
1,039,472
|
|
|
302,749
|
|
|
—
|
|
|||
Supplemental Pension Benefits
(5)
|
—
|
|
|
—
|
|
|
—
|
|
|||
Nonqualified Deferred Compensation
(6)
|
90,000
|
|
|
59,400
|
|
|
—
|
|
|||
Health and Welfare Benefits
(7)
|
91,650
|
|
|
47,552
|
|
|
—
|
|
|||
Total
|
$
|
3,422,771
|
|
|
$
|
2,257,354
|
|
|
$
|
124,413
|
|
(1)
|
Messrs. Sinclair’s and Fink’s values assume 2.9 times and two times, respectively, the sum of base salary plus the highest bonus paid in the past three years and reflect their allocation percentages in effect as of December 31, 2013, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(2)
|
Messrs. Sinclair’s and Fink’s values assume the full-year equivalent of their highest annual bonus allocated to us over the past three years. No value has been disclosed for Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
(3)
|
Reflects the in-the-money value of unvested stock options, the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2013. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2013.
|
(4)
|
Reflects the value of unvested WES and WGP LTIP phantom units based on the applicable closing common unit price of $61.69 and $39.51, respectively, on December 31, 2013. All values reflect each named executive officer’s allocation percentage in effect as of December 31, 2013.
|
(5)
|
Under the terms of their change of control agreements, Messrs. Sinclair and Fink would receive a special retirement benefit enhancement that is equivalent to the additional supplemental pension benefits that would have accrued under Anadarko’s retirement plan assuming they were eligible for subsidized early retirement benefits and include additional special pension credits. The value of this benefit has not been included in this table as Anadarko does not allocate expense to the partnership for distribution of these benefits. If Anadarko were to allocate this expense to the Partnership, assuming their allocation percentages in effect as of December 31, 2013, the expense would be as follows: Mr. Sinclair—$139,739 and Mr. Fink—$69,627.
|
(6)
|
Messrs. Sinclair’s and Fink’s values reflect an additional three years and two years, respectively, of employer contributions into the savings restoration plan at their current contribution rate to the Plan and are based on their allocation percentages in effect as of December 31, 2013, per the terms of their key employee change of control agreements with Anadarko. No value has been disclosed for Mr. Peacock as he is not eligible for this additional benefit.
|
(7)
|
Messrs. Sinclair’s and Fink’s values represent 36 months and 24 months, respectively, of health and welfare benefit coverage. All amounts are present values determined in accordance with GAAP and reflect their allocation percentages in effect as of December 31, 2013. No value has been disclosed for the Mr. Peacock as he receives the same benefits as generally provided to all salaried employees.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Mr. Peacock
|
||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Compensation
(1)
|
468,038
|
|
|
629,142
|
|
|
124,413
|
|
|||
Health and Welfare Benefits
(2)
|
152,934
|
|
|
186,945
|
|
|
77,743
|
|
|||
Total
|
$
|
620,972
|
|
|
$
|
816,087
|
|
|
$
|
202,156
|
|
(1)
|
Reflects the in-the-money value of unvested stock options and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of December 31, 2013. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2013
.
|
(2)
|
Values reflect the continuation of additional death benefit coverage provided to certain employees of Anadarko until age 65. All amounts are present values determined in accordance with GAAP and reflect each named executive officer’s allocation percentage in effect as of
December 31, 2013
.
|
|
Mr. Sinclair
|
|
Mr. Fink
|
|
Mr. Peacock
|
||||||
Cash Severance
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Accelerated Anadarko Equity Compensation
(1)
|
468,038
|
|
|
629,142
|
|
|
124,413
|
|
|||
Life Insurance Proceeds
(2)
|
1,033,592
|
|
|
1,023,256
|
|
|
426,357
|
|
|||
Total
|
$
|
1,501,630
|
|
|
$
|
1,652,398
|
|
|
$
|
550,770
|
|
(1)
|
Reflects the in-the-money value of unvested stock options and the value of unvested restricted stock shares and restricted stock units granted under Anadarko equity plans, all as of
December 31, 2013
. All values reflect each named executive officer’s allocation percentage in effect as of
December 31, 2013
.
|
(2)
|
Values include amounts payable under additional death benefits provided to certain employees of Anadarko. These liabilities are not insured, but are self-funded by Anadarko. Proceeds are not exempt from federal taxes. Values shown include an additional tax gross-up amount to equate benefits with non-taxable life insurance proceeds. Values are based on each named executive officer’s allocation percentage in effect as of
December 31, 2013
, and exclude death benefit proceeds from programs available to all employees.
|
•
|
an annual retainer of $70,000 for each board member;
|
•
|
an annual retainer of $2,000 for each member of the audit committee, or $22,000 for the committee chair;
|
•
|
an annual retainer of $2,000 for each member of the special committee, or $22,000 for the committee chair;
|
•
|
a fee of $2,000 for each board meeting attended;
|
•
|
a fee of $2,000 for each committee meeting attended; and
|
•
|
annual grants of phantom units with a value of approximately $80,000 on the date of grant, all of which vest 100% on the first anniversary of the date of grant (with vesting to be accelerated upon a change of control of our general partner or Anadarko). The non-employee directors received such a grant of phantom units on May 9,
2013
.
|
Name
|
|
Fees Earned or Paid in Cash
|
|
Stock Awards
(1)
|
|
Option Awards
|
|
Non-Equity Incentive Plan Compensation
|
|
All Other Compensation
|
|
Total
|
||||||||||||
Milton Carroll
|
|
$
|
101,500
|
|
|
$
|
79,987
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
181,487
|
|
Anthony R. Chase
|
|
93,500
|
|
|
79,987
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
173,487
|
|
||||||
James R. Crane
|
|
93,500
|
|
|
79,987
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
173,487
|
|
||||||
David J. Tudor
|
|
107,500
|
|
|
79,987
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
187,487
|
|
(1)
|
The amounts included in the Stock Awards column represent the grant date fair value of non-option awards made to directors in
2013
, computed in accordance with FASB ASC Topic 718. For a discussion of valuation assumptions, see
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K. As of
December 31, 2013
, each of the non-employee directors had 1,280 outstanding phantom units. Mr. Chase’s outstanding phantom unit grant was vested as of the date of his resignation from the board of directors on February 12, 2014.
|
Name
|
|
Grant Date
|
|
Phantom Units (#)
|
|
Grant Date Fair Value of Stock and Option Awards ($)
(1)
|
||
Milton Carroll
|
|
May 9
|
|
1,280
|
|
|
79,987
|
|
Anthony R. Chase
|
|
May 9
|
|
1,280
|
|
|
79,987
|
|
James R. Crane
|
|
May 9
|
|
1,280
|
|
|
79,987
|
|
David J. Tudor
|
|
May 9
|
|
1,280
|
|
|
79,987
|
|
(1)
|
The amounts included in the Grant Date Fair Value of Stock and Option Awards column represent the grant date fair value of the awards made to non-employee directors in
2013
computed in accordance with FASB ASC Topic 718. The value ultimately realized by a director upon the actual vesting of the award(s) may or may not be equal to the determined value.
|
•
|
each member of the board of directors of our general partner;
|
•
|
each named executive officer of our general partner;
|
•
|
all directors and officers of our general partner as a group; and
|
•
|
Anadarko and its affiliates.
|
|
|
WES
|
|
WGP
|
||||||
Name and Address of Beneficial Owner
(1)
|
|
Common
Units
Beneficially Owned
|
|
Percentage of
Common Units
Beneficially
Owned
|
|
Common
Units
Beneficially
Owned
|
|
Percentage of
Common Units
Beneficially
Owned
|
||
Anadarko Petroleum Corporation
(2)
|
|
49,745,334
|
|
|
42.29%
|
|
199,137,365
|
|
|
90.97%
|
Robert G. Gwin
|
|
10,000
|
|
|
*
|
|
200,000
|
|
|
*
|
Donald R. Sinclair
(3)
|
|
107,972
|
|
|
*
|
|
300,000
|
|
|
*
|
Benjamin M. Fink
|
|
2,213
|
|
|
*
|
|
12,500
|
|
|
*
|
Danny J. Rea
|
|
18,247
|
|
|
*
|
|
40,000
|
|
|
*
|
Philip H. Peacock
|
|
—
|
|
|
*
|
|
7,500
|
|
|
*
|
Steven D. Arnold
|
|
31,000
|
|
|
*
|
|
7,500
|
|
|
*
|
Milton Carroll
(3) (4)
|
|
4,157
|
|
|
*
|
|
4,000
|
|
|
*
|
James R. Crane
(3) (4)
|
|
802,518
|
|
|
*
|
|
135,000
|
|
|
*
|
Charles A. Meloy
|
|
3,000
|
|
|
*
|
|
5,000
|
|
|
*
|
Robert K. Reeves
|
|
9,000
|
|
|
*
|
|
9,000
|
|
|
*
|
David J. Tudor
(3)
|
|
11,153
|
|
|
*
|
|
4,074
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
(3)
|
|
999,260
|
|
|
*
|
|
724,574
|
|
|
*
|
*
|
Less than 1%
|
(1)
|
The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
|
(2)
|
Anadarko Petroleum Corporation is the ultimate parent company of Western Gas Resources, Inc. and Anadarko Marcellus Midstream, L.L.C. and the general partner of WGP and may, therefore, be deemed to beneficially own the units held by Western Gas Resources, Inc., Anadarko Marcellus Midstream, L.L.C. and WGP.
|
(3)
|
Does not include (a) 1,280 phantom units that were granted to each of Messrs. Carroll, Crane and Tudor and 10,782 phantom units granted to Mr. Sinclair under the WES LTIP, and (b) an aggregate of 26,758 phantom units that were granted to Messrs. Sinclair and Fink under the WGP LTIP. WES phantom units granted to the independent directors of WES vest 100% on the first anniversary of the date of the grant, and Mr. Sinclair’s WES phantom unit awards vest pro-rata over three years. Each vested phantom unit entitles the holder to receive a common unit or, in the discretion of our general partner’s board of directors, cash equal to the fair market value of a common unit. Holders of phantom units are entitled to distribution equivalents on a current basis. Holders of phantom units have no voting rights until such time as the phantom units become vested and common units are issued to such holders.
|
(4)
|
Includes (a) 2,000 and 670,600 WES units held by Messrs. Carroll and Crane, respectively, and (b) 4,000 WGP units held by Mr. Carroll, in margin accounts.
|
Name and Address of Beneficial Owner
(1)
|
|
Shares of
Common Stock
Owned Directly
or Indirectly
(
2)
|
|
Shares
Underlying
Options
Exercisable
Within 60 Days
(2)
|
|
Total Shares of
Common Stock
Beneficially
Owned
(2)
|
|
Percentage of
Total Shares of
Common Stock
Beneficially
Owned
(2)
|
|||
Robert G. Gwin
(3)
|
|
61,258
|
|
|
345,202
|
|
|
406,460
|
|
|
*
|
Donald R. Sinclair
(3)
|
|
7,115
|
|
|
15,816
|
|
|
22,931
|
|
|
*
|
Benjamin M. Fink
(4)
|
|
6,336
|
|
|
12,220
|
|
|
18,556
|
|
|
*
|
Danny J. Rea
(3)
|
|
11,214
|
|
|
59,104
|
|
|
70,318
|
|
|
*
|
Philip H. Peacock
(4)
|
|
3,137
|
|
|
—
|
|
|
3,137
|
|
|
*
|
Steven D. Arnold
|
|
13,600
|
|
|
—
|
|
|
13,600
|
|
|
*
|
Milton Carroll
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
James R. Crane
|
|
—
|
|
|
—
|
|
|
—
|
|
|
|
Charles A. Meloy
(3)
|
|
107,802
|
|
|
198,594
|
|
|
306,396
|
|
|
*
|
Robert K. Reeves
(3)
|
|
156,240
|
|
|
288,378
|
|
|
444,618
|
|
|
*
|
David J. Tudor
|
|
—
|
|
|
—
|
|
|
—
|
|
|
*
|
All directors and executive officers
as a group (11 persons)
|
|
366,702
|
|
|
919,314
|
|
|
1,286,016
|
|
|
*
|
*
|
Less than 1%
|
(1)
|
The address for all beneficial owners in this table is 1201 Lake Robbins Drive, The Woodlands, Texas 77380.
|
(2)
|
As of January 31, 2014, there were 503.8 million shares of Anadarko Petroleum Corporation common stock issued and outstanding.
|
(3)
|
Does not include unvested restricted stock units of Anadarko Petroleum Corporation held by the following individuals in the amounts indicated: Robert G. Gwin—30,432; Donald R. Sinclair—7,226; Benjamin M. Fink—2,477; Charles A. Meloy—31,195; Robert K. Reeves—27,792; and a total of 99,122 unvested restricted stock units are held by the directors and executive officers as a group. Restricted stock units typically vest equally over three years beginning on the first anniversary of the date of grant, and upon vesting are payable in Anadarko common stock, subject to applicable tax withholding. Holders of restricted stock units receive dividend equivalents on the units, but do not have voting rights. Generally, a holder will forfeit any unvested restricted units if he or she terminates voluntarily or is terminated for cause prior to the vesting date. Holders of restricted stock units have the ability to defer such awards.
|
(4)
|
Includes unvested shares of restricted common stock of Anadarko Petroleum Corporation held by the following individuals in the amounts indicated: Benjamin M. Fink—6,336; Philip H. Peacock—3,137; and a total of 9,473 unvested shares of restricted common stock are held by the directors and executive officers as a group. Restricted stock awards typically vest equally over three years beginning on the first anniversary of the date of grant. Holders of restricted stock receive dividends on the shares and also have voting rights. Generally, a holder of restricted stock will forfeit any unvested restricted shares if he or she terminates voluntarily or is terminated for cause prior to the vesting date.
|
Title of Class
|
|
Name and Address of Beneficial Owner
|
|
Amount and
Nature
of Beneficial
Ownership
|
|
Percent of Class
|
Common Units
|
|
Tortoise Capital Advisors, L.L.C.
11550 Ash Street
Suite 300
Leawood, KS 66211
|
|
7,226,800
(1)
|
|
6.14%
|
Common Units
|
|
Kayne Anderson Capital Advisors, L.P.
1800 Avenue of the Stars Third Floor Los Angeles, CA 90067 |
|
6,002,546
(2)
|
|
5.10%
|
(1)
|
Based upon its Schedule 13G filed February 11, 2014, with the SEC with respect to Partnership securities held as of
December 31, 2013
, Tortoise Capital Advisors, L.L.C. has shared voting power as to 6,657,722 common units and shared dispositive power as to 7,226,800 common units.
|
(2)
|
Based upon its Schedule 13G filed February 4, 2014, with the SEC with respect to Partnership securities held as of December 31, 2013, Kayne Anderson Capital Advisors, L.P. has shared voting and dispositive power as to 6,002,546 common units.
|
Plan Category
|
|
(a)
Number of
Securities
to be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights
|
|
(b)
Weighted-Average
Exercise Price of
Outstanding
Options, Warrants
and Rights
|
|
(c)
Number of Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in Column(a))
|
|||
Equity compensation plans approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
Equity compensation plans not approved by security holders
(1)
|
|
16,844
|
|
|
—
|
|
(2)
|
2,139,027
|
|
Total
|
|
16,844
|
|
|
—
|
|
|
2,139,027
|
|
(1)
|
The board of directors of our general partner adopted the WES LTIP in connection with the initial public offering of our common units.
|
(2)
|
Phantom units constitute the only rights outstanding under the WES LTIP. Each phantom unit that may be settled in common units entitles the holder to receive, upon vesting, one common unit with respect to each phantom unit, without payment of any cash. Accordingly, there is no reportable weighted-average exercise price.
|
Formation stage
|
|
|
|
|
|
The consideration received by Anadarko and its subsidiaries for the contribution of the assets and liabilities to us
|
|
5,725,431 common units; 26,536,306 subordinated units; 1,083,115 general partner units, and our IDRs.
|
|
|
|
Operational stage
|
|
|
|
|
|
Distributions of available cash to our general partner, WGP and AMM
|
|
We will generally make cash distributions of 98.0% to our unitholders pro rata, including WGP and AMM as the holders of 49,296,205 common units and 449,129 common units, respectively, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level.
|
|
|
|
Payments to our general partner and its affiliates
|
|
Our general partner and its affiliates are entitled to reimbursement for expenses incurred on our behalf, including salaries and employee benefit costs for employees who provide services to us, and all other necessary or appropriate expenses allocable to us or reasonably incurred by our general partner and its affiliates in connection with operating our business. The partnership agreement provides that our general partner determines in good faith the amount of such expenses that are allocable to us.
|
|
|
|
Withdrawal or removal of our general partner
|
|
If our general partner withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
|
|
|
|
Liquidation stage
|
|
|
|
|
|
Liquidation
|
|
Upon our liquidation, our partners, including our general partner, WGP and AMM, will be entitled to receive liquidating distributions according to their respective capital account balances.
|
•
|
Anadarko’s obligation to indemnify us for certain liabilities and our obligation to indemnify Anadarko for certain liabilities;
|
•
|
our obligation to reimburse Anadarko for expenses incurred or payments made on our behalf in conjunction with Anadarko’s provision of general and administrative services to us, including salary and benefits of Anadarko personnel, our public company expenses, general and administrative expenses and salaries and benefits of our executive management who are employees of Anadarko (see
Administrative services and reimbursement
below for details regarding certain agreements for amounts reimbursed in
2013
); and
|
•
|
our obligation to reimburse Anadarko for all insurance coverage expenses it incurs or payments it makes with respect to our assets.
|
thousands
|
Year Ended
December 31, 2013 |
||
Reimbursement of general and administrative expenses
|
$
|
16,882
|
|
Reimbursement of public company expenses
|
7,152
|
|
|
Total reimbursement
|
$
|
24,034
|
|
•
|
Chipeta’s members will be required from time to time to make capital contributions to Chipeta to the extent approved by the members in connection with Chipeta’s annual budget;
|
•
|
Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, if any, to its members quarterly in accordance with those members’ membership interests; and
|
•
|
Chipeta’s membership interests are subject to significant restrictions on transfer.
|
|
|
Year Ended December 31,
|
||||||||||||||||||||||
|
|
2013
|
|
2012
|
|
2011
|
|
2013
|
|
2012
|
|
2011
|
||||||||||||
thousands
|
|
Purchases
|
|
Sales
|
||||||||||||||||||||
Cash consideration
|
|
$
|
11,211
|
|
|
$
|
24,705
|
|
|
$
|
3,837
|
|
|
$
|
85
|
|
|
$
|
760
|
|
|
$
|
382
|
|
Net carrying value
|
|
5,309
|
|
|
8,009
|
|
|
1,998
|
|
|
38
|
|
|
393
|
|
|
316
|
|
||||||
Partners’ capital adjustment
|
|
$
|
5,902
|
|
|
$
|
16,696
|
|
|
$
|
1,839
|
|
|
$
|
47
|
|
|
$
|
367
|
|
|
$
|
66
|
|
|
|
Year ended December 31,
|
||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
||||||
Revenues
(1)
|
|
$
|
829,258
|
|
|
$
|
704,137
|
|
|
$
|
658,680
|
|
Cost of product
(1)
|
|
129,045
|
|
|
145,250
|
|
|
83,722
|
|
|||
Operation and maintenance
(2)
|
|
56,435
|
|
|
51,237
|
|
|
51,339
|
|
|||
General and administrative
(3)
|
|
23,354
|
|
|
92,847
|
|
|
33,305
|
|
|||
Operating expenses
|
|
208,834
|
|
|
289,334
|
|
|
168,366
|
|
|||
Interest income, net
(4)
|
|
16,900
|
|
|
16,900
|
|
|
24,106
|
|
|||
Interest expense
(5)
|
|
—
|
|
|
2,766
|
|
|
4,935
|
|
|||
Distributions to unitholders
(6)
|
|
169,150
|
|
|
98,280
|
|
|
68,039
|
|
|||
Contributions from noncontrolling interest owners
(7)
|
|
—
|
|
|
12,588
|
|
|
16,476
|
|
|||
Distributions to noncontrolling interest owners
(7)
|
|
—
|
|
|
6,528
|
|
|
9,437
|
|
(1)
|
Represents amounts recognized under gathering, treating or processing agreements, and purchase and sale agreements.
|
(2)
|
Represents expenses incurred on and subsequent to the date of the acquisition of our assets, as well as expenses incurred by Anadarko on a historical basis related to our assets prior to the acquisition of such assets by us.
|
(3)
|
Represents general and administrative expense incurred on and subsequent to the date of the acquisition of our assets, as well as a management services fee for reimbursement of expenses incurred by Anadarko for periods prior to the acquisition of our assets by us. These amounts include equity-based compensation expense allocated to us by Anadarko. See
Note 5—Transactions with Affiliates
in the
Notes to Consolida
ted Financial Statements under Item 8 of this Form 10-K.
|
(4)
|
Represents interest income recognized on the note receivable from Anadarko. For the year ended December 31, 2011, this line item also includes interest income, net on affiliate balances related to the Non-Operated Marcellus Interest, the MGR assets and the Bison assets for periods prior to the acquisition of such assets. Beginning December 7, 2011, Anadarko discontinued charging interest on intercompany balances. The outstanding affiliate balances on our assets prior to acquisition were entirely settled through an adjustment to net investment by Anadarko. See
Note 10—Debt and Interest Expense
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(5)
|
For the
year ended December 31, 2012
, includes interest expense recognized on the note payable to Anadarko and interest imputed on the reimbursement payable to Anadarko for certain expenditures Anadarko incurred in 2011 related to the construction of the Brasada facility and Lancaster plant. We repaid the note payable to Anadarko in June 2012, and repaid the reimbursement payable to Anadarko related to the construction of the Brasada facility and Lancaster plant in the fourth quarter of 2012. See
Note 5—Transactions with Affiliates
in the
Notes to Consolidated Financial Statements
under Item 8 of this Form 10-K.
|
(6)
|
Represents distributions paid under the partnership agreement.
|
(7)
|
As described
i
n the caption
Chipeta LLC Agreement
within this Item 13, we acquired Anadarko’s then-remaining 24% membership interest in Chipeta on August 1, 2012, and accounted for the acquisition on a prospective basis. As such, contributions from noncontrolling interest owners and distributions to noncontrolling interest owners subsequent to the acquisition date no longer reflect contributions from or distributions to Anadarko.
|
•
|
approved by the special committee of our general partner, although our general partner is not obligated to seek such approval;
|
•
|
approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;
|
•
|
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
|
•
|
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
|
thousands
|
2013
|
|
2012
|
||||
Audit fees
|
$
|
1,031
|
|
|
$
|
948
|
|
Audit-related fees
|
758
|
|
|
665
|
|
||
Total
|
$
|
1,789
|
|
|
$
|
1,613
|
|
Exhibit
Number
|
|
Description
|
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, LP’s 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, LP’s 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, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
|
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, LP’s Current Report on Form 8-K filed on February 3, 2010 File No. 001-34046).
|
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, LP’s 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, LP’s Current Report on Form 8-K filed on January 18, 2011 File No. 001-34046).
|
2.7#
|
|
Contribution Agreement, dated as of December 15, 2011, 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, LP’s Current Report on Form 8-K filed on December 15, 2011, File No. 001-34046).
|
2.8#
|
|
Contribution Agreement, dated as of February 27, 2013, by and among Anadarko Marcellus Midstream, L.L.C., Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP, Anadarko Petroleum Corporation and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 2.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
2.9*#
|
|
Contribution Agreement, dated as of February 27, 2014, by and among WGR Asset Holding Company, LLC, APC Midstream Holdings, LLC, Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP, and Anadarko Petroleum Corporation.
|
3.1
|
|
Certificate of Limited Partnership of Western Gas Partners, LP (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s 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, LP’s 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, LP’s 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, LP’s Current Report on Form 8-K filed on April 20, 2009, File No. 001-34046).
|
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, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
|
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, LP’s 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, LP’s 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, LP’s Current Report on Form 8-K filed on July 8, 2011, File No. 001-34046).
|
3.9
|
|
Amendment No. 7 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated January 13, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 17, 2012, File No. 001-34046).
|
3.10
|
|
Amendment No. 8 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 1, 2012 (incorporated by reference to Exhibit 3.10 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 2, 2012, File No. 001-34046).
|
3.11
|
|
Amendment No. 9 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated December 12, 2012 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
|
3.12
|
|
Amendment No. 10 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 1, 2013 (incorporated by reference to Exhibit 3.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
3.13
|
|
Certificate of Formation of Western Gas Holdings, LLC (incorporated by reference to Exhibit 3.3 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on October 15, 2007, File No. 333-146700).
|
3.14
|
|
Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012 (incorporated by reference to Exhibit 3.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 12, 2012, File No. 001-34046).
|
4.1
|
|
Specimen Unit Certificate for the Common Units (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s 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, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
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, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.4
|
|
Form of 5.375% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 18, 2011, File No. 001-34046).
|
4.5
|
|
Fifth Supplemental Indenture, dated as of August 14, 2013, among Western Gas Partners, LP, as Issuer, and Wells Fargo Bank, National Association, as Trustee (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
|
4.6
|
|
Form of 4.000% Senior Notes due 2022 (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on June 28, 2012, File No. 001-34046).
|
4.7
|
|
Form of 2.600% Senior Notes due 2018 (incorporated by reference to Exhibit 4.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 14, 2013, File No. 001-34046).
|
10.1
|
|
Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.3 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.2
|
|
Amendment No. 1 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 19, 2008 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on December 24, 2008, File No. 001-34046).
|
10.3
|
|
Amendment No. 2 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of July 22, 2009 (incorporated by reference to Exhibit 10.2 to Western Gas Partners, LP’s Current Report on Form 8-K filed on July 23, 2009, File No. 001-34046).
|
10.4
|
|
Amendment No. 3 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 31, 2009 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on January 7, 2010, File No. 001-34046).
|
10.5
|
|
Amendment No. 4 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of January 29, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on February 3, 2010, File No. 001-34046).
|
10.6
|
|
Amendment No. 5 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of August 2, 2010 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on August 5, 2010, File No. 001-34046).
|
10.7
|
|
Services And Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated May 14, 2008 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.8
|
|
Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008 (incorporated by reference to Exhibit 10.5 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.9
|
|
Anadarko Petroleum Corporation Fixed Rate Note due 2038 (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.10
|
|
Form of Commodity Price Swap Agreement (filed as Exhibit 10.3 to the Partnership’s Form 10-Q for the quarter ended March 31, 2010).
|
10.11‡
|
|
Form of Indemnification Agreement by and between Western Gas Holdings, LLC, its Officers and Directors (incorporated by reference to Exhibit 10.10 to Amendment No. 2 to Western Gas Partners, LP’s Registration Statement on Form S-1 filed on January 23, 2008, File No. 333-146700).
|
10.12‡
|
|
Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.13 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on June 13, 2008, File No. 001-34046).
|
Exhibit
Number
|
|
Description
|
10.13‡
|
|
Form of Award Agreement under the Western Gas Partners, LP 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.9 to Western Gas Partners, LP’s Current Report on Form 8-K filed on May 14, 2008, File No. 001-34046).
|
10.14†
|
|
Amended and Restated Limited Liability Company Agreement of Chipeta Processing LLC effective July 23, 2009 (incorporated by reference to Exhibit 10.4 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on November 12, 2009, File No. 001-34046).
|
10.15*
|
|
Second Amended and Restated Revolving Credit Agreement, dated as of February 26, 2014, among Western Gas Partners, LP, Wells Fargo Bank National Association, as the administrative agent and the lenders party thereto.
|
10.16
|
|
Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
10.17
|
|
Third Amended and Restated Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Western Gas Resources, Inc. (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Current Report on Form 8-K filed on March 5, 2013, File No. 001-34046).
|
10.18
|
|
Assignment of Indemnification Agreement, dated April 1, 2013, between Anadarko USH2 LLC and Anadarko E&P Onshore LLC (incorporated by reference to Exhibit 10.1 to Western Gas Partners, LP’s Quarterly Report on Form 10-Q filed on August 1, 2013, File No. 001-34046).
|
12.1*
|
|
Ratio of Earnings to Fixed Charges.
|
21.1*
|
|
List of Subsidiaries of Western Gas Partners, LP.
|
23.1*
|
|
Consent of KPMG LLP.
|
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.DEF*
|
|
XBRL Definition Linkbase Document
|
101.LAB*
|
|
XBRL Label Linkbase Document
|
101.PRE*
|
|
XBRL Presentation Linkbase Document
|
*
|
Filed herewith
|
**
|
Furnished herewith
|
#
|
Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the Securities and Exchange Commission upon request.
|
†
|
Portions of this exhibit, which was previously filed with the Securities and Exchange Commission, were omitted pursuant to a request for confidential treatment. The omitted portions were filed separately with the Securities and Exchange Commission.
|
‡
|
Management contracts or compensatory plans or arrangements required to be filed pursuant to Item 15.
|
|
WESTERN GAS PARTNERS, LP
|
|
|
February 28, 2014
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
Signature
|
Title (Position with Western Gas Holdings, LLC)
|
|
|
/s/ Robert G. Gwin
|
Chairman and Director
|
Robert G. Gwin
|
|
|
|
/s/ Donald R. Sinclair
|
President, Chief Executive Officer and Director
|
Donald R. Sinclair
|
|
|
|
/s/ Benjamin M Fink
|
Senior Vice President, Chief Financial Officer and Treasurer
|
Benjamin M Fink
|
|
|
|
/s/ Charles A. Meloy
|
Director
|
Charles A. Meloy
|
|
|
|
/s/ Robert K. Reeves
|
Director
|
Robert K. Reeves
|
|
|
|
/s/ Steven D. Arnold
|
Director
|
Steven D. Arnold
|
|
|
|
/s/ Milton Carroll
|
Director
|
Milton Carroll
|
|
|
|
/s/ James R. Crane
|
Director
|
James R. Crane
|
|
|
|
/s/ David J. Tudor
|
Director
|
David J. Tudor
|
|
ARTICLE I
|
|
|
|
|
||
|
DEFINITIONS AND RULES OF CONSTRUCTION
|
2
|
|
|||
|
Section 1.1
|
|
Definitions
|
|
2
|
|
|
Section 1.2
|
|
Rules of Construction
|
|
11
|
|
|
|
|
|
|
|
|
ARTICLE II
|
|
|
|
|
||
|
CONTRIBUTION
|
12
|
|
|||
|
Section 2.1
|
|
Contribution of the Interests
|
12
|
|
|
|
Section 2.2
|
|
Consideration
|
12
|
|
|
|
Section 2.3
|
|
Borrowing by the Partnership; Tax Treatment of Cash Consideration
|
12
|
|
|
|
Section 2.4
|
|
Contemplated Legal Steps
|
12
|
|
|
|
|
|
|
|
|
|
ARTICLE III
|
|
|
|
|
||
|
CLOSING
|
13
|
|
|||
|
Section 3.1
|
|
The Closing
|
13
|
|
|
|
Section 3.2
|
|
Deliveries by the Contributing Parties
|
13
|
|
|
|
Section 3.3
|
|
Deliveries by the Recipient Parties
|
13
|
|
|
|
Section 3.4
|
|
Closing Costs; Transfer Taxes and Fees
|
14
|
|
|
|
Section 3.5
|
|
Receipts and Credits
|
14
|
|
|
|
|
|
|
|
|
|
ARTICLE IV
|
|
|
|
|
||
|
REPRESENTATIONS AND WARRANTIES OF ANADARKO AND THE CONTRIBUTING PARTIES
|
14
|
|
|||
|
Section 4.1
|
|
Organization
|
14
|
|
|
|
Section 4.2
|
|
Authorization; Enforceability
|
15
|
|
|
|
Section 4.3
|
|
No Conflicts
|
15
|
|
|
|
Section 4.4
|
|
Preference Rights and Transfer Requirements
|
15
|
|
|
|
Section 4.5
|
|
Litigation
|
16
|
|
|
|
Section 4.6
|
|
Title
|
16
|
|
|
|
Section 4.7
|
|
Taxes and Assessments
|
17
|
|
|
|
Section 4.8
|
|
Compliance With Laws
|
18
|
|
|
|
Section 4.9
|
|
Environmental Matters
|
18
|
|
|
|
Section 4.10
|
|
Brokers and Finders
|
18
|
|
|
|
Section 4.11
|
|
Permits
|
19
|
|
|
|
Section 4.12
|
|
Contracts
|
19
|
|
|
|
Section 4.13
|
|
Condition of Assets
|
20
|
|
|
|
Section 4.14
|
|
No Undisclosed Liabilities; Accuracy of Data
|
20
|
|
|
|
Section 4.15
|
|
Absence of Certain Changes
|
20
|
|
|
|
Section 4.16
|
|
Sufficiency of the Assets
|
20
|
|
|
|
Section 4.17
|
|
Regulatory Matters
|
20
|
|
|
|
Section 4.18
|
|
Budgets; Outstanding Capital Commitments
|
21
|
|
|
|
Section 4.19
|
|
Systems
|
21
|
|
|
|
Section 4.20
|
|
Insurance
|
21
|
|
|
|
Section 4.21
|
|
Employees
|
21
|
|
|
Section 4.22
|
|
Management Projections and Budgets
|
21
|
|
|
|
Section 4.23
|
|
Investment
|
22
|
|
|
|
|
|
|
|
|
|
ARTICLE V
|
|
|
|
|
||
|
REPRESENTATIONS AND WARRANTIES OF THE RECIPIENT PARTIES
|
22
|
|
|||
|
Section 5.1
|
|
Organization
|
22
|
|
|
|
Section 5.2
|
|
Authorization; Enforceability
|
23
|
|
|
|
Section 5.3
|
|
No Conflicts
|
23
|
|
|
|
Section 5.4
|
|
Litigation
|
23
|
|
|
|
Section 5.5
|
|
Brokers' Fees
|
23
|
|
|
|
|
|
|
|
|
|
ARTICLE VI
|
|
|
|
|
||
|
COVENANTS
|
24
|
|
|||
|
Section 6.1
|
|
Conducts of Business
|
24
|
|
|
|
Section 6.2
|
|
Access
|
25
|
|
|
|
Section 6.3
|
|
Additional Agreements
|
25
|
|
|
|
Section 6.4
|
|
Interest Matters
|
25
|
|
|
|
|
|
|
|
|
|
ARTICLE VII
|
|
|
|
|
||
|
CONDITIONS TO CLOSING
|
26
|
|
|||
|
Section 7.1
|
|
Conditions to Each Party's Obligations to Close
|
26
|
|
|
|
Section 7.2
|
|
Conditions to the Recipient Parties' Obligation to Close
|
26
|
|
|
|
Section 7.3
|
|
Conditions to the Contributing Parties' Obligation to Close
|
27
|
|
|
|
|
|
|
|
|
|
ARTICLE VIII
|
|
|
|
|
||
|
TERMINATION
|
28
|
|
|||
|
Section 8.1
|
|
Termination
|
28
|
|
|
|
Section 8.2
|
|
Effect of Termination
|
28
|
|
|
|
|
|
|
|
|
|
ARTICLE IX
|
|
|
|
|
||
|
INDEMNIFICATION
|
29
|
|
|||
|
Section 9.1
|
|
Survival
|
29
|
|
|
|
Section 9.2
|
|
Indemnification of the Anadarko Indemnified Parties
|
29
|
|
|
|
Section 9.3
|
|
Indemnification of the Partnership Indemnified Parties
|
30
|
|
|
|
Section 9.4
|
|
Demands
|
30
|
|
|
|
Section 9.5
|
|
Rights to Contest and Defend
|
31
|
|
|
|
Section 9.6
|
|
Cooperation
|
32
|
|
|
|
Section 9.7
|
|
Payment of Losses
|
32
|
|
|
|
Section 9.8
|
|
Limitations on Indemnification
|
32
|
|
|
|
Section 9.9
|
|
Sole Remedy
|
33
|
|
|
|
Section 9.10
|
|
Express Negligence Rule
|
33
|
|
|
|
|
|
|
|
|
|
ARTICLE X
|
|
|
|
|
||
|
ADDITIONAL AGREEMENTS
|
34
|
|
|||
|
Section 10.1
|
|
Further Assurances
|
34
|
|
|
|
|
|
|
|
|
|
ARTICLE XI
|
|
|
|
|
||
|
MISCELLANEOUS
|
31
|
|
|||
|
Section 11.1
|
|
Expenses
|
34
|
|
|
Section 11.2
|
|
Notices
|
35
|
|
|
|
Section 11.3
|
|
Severability
|
37
|
|
|
|
Section 11.4
|
|
Governing Law; Consent to Jurisdiction
|
37
|
|
|
|
Section 11.5
|
|
Parties in Interest
|
37
|
|
|
|
Section 11.6
|
|
Assignment
|
37
|
|
|
|
Section 11.7
|
|
No Amendment or Waiver
|
37
|
|
|
|
Section 11.8
|
|
Counterparts
|
37
|
|
|
|
Section 11.9
|
|
Integration
|
38
|
|
|
|
Section 11.10
|
|
Determinations by the Partnership
|
38
|
|
|
|
Section 11.11
|
|
Public Statements
|
38
|
|
Schedule 4.3
|
-
|
Preference Rights and Transfer Requirements
|
|
Schedule 4.5
|
-
|
Contributing Party Litigation
|
|
Schedule 4.6
|
-
|
Title to Interests
|
|
Schedule 4.7
|
-
|
Taxes
|
|
Schedule 4.8
|
-
|
Compliance With Laws
|
|
Schedule 4.9
|
-
|
Environmental Matters
|
|
Schedule 4.11
|
-
|
Permits
|
|
Schedule 4.12
|
-
|
Contracts
|
|
Schedule 4.18
|
-
|
Budgets; Outstanding Capital Commitments
|
|
Schedule 4.20
|
-
|
Insurance
|
|
Schedule 5.4
|
-
|
Recipient Party Litigation
|
|
Exhibit A
|
JV Systems
|
|
Exhibit B
|
Form of Interest Conveyance Agreement
|
|
Exhibit C
|
Form of Partnership Agreement Amendment
|
|
Lenders
|
Initial Amount of
Commitment |
Percentage of
Commitment |
|||
Wells Fargo Bank, National Association
|
|
$90,000,000
|
|
7.50000
|
%
|
DNB Capital LLC
|
|
$90,000,000
|
|
7.50000
|
%
|
The Bank of Tokyo-Mitsubishi UFJ, Ltd.
|
|
$90,000,000
|
|
7.50000
|
%
|
Citibank N.A.
|
|
$90,000,000
|
|
7.50000
|
%
|
The Royal Bank of Scotland plc
|
|
$90,000,000
|
|
7.50000
|
%
|
U.S. Bank National Association
|
|
$90,000,000
|
|
7.50000
|
%
|
Barclays Bank PLC
|
|
$70,000,000
|
|
5.83333
|
%
|
Deutsche Bank AG New York Branch
|
|
$70,000,000
|
|
5.83333
|
%
|
Morgan Stanley Bank, N.A.
|
|
$70,000,000
|
|
5.83333
|
%
|
Royal Bank of Canada
|
|
$70,000,000
|
|
5.83333
|
%
|
UBS AG, Stamford Branch
|
|
$70,000,000
|
|
5.83333
|
%
|
Bank of Montreal
|
|
$47,500,000
|
|
3.95833
|
%
|
Comerica Bank
|
|
$47,500,000
|
|
3.95833
|
%
|
Societe Generale
|
|
$47,500,000
|
|
3.95833
|
%
|
The Bank of Nova Scotia
|
|
$47,500,000
|
|
3.95833
|
%
|
Amegy Bank National Association
|
|
$30,000,000
|
|
2.50000
|
%
|
Branch Banking and Trust Company
|
|
$30,000,000
|
|
2.50000
|
%
|
PNC Bank, National Association
|
|
$30,000,000
|
|
2.50000
|
%
|
Capital One, National Association
|
|
$15,000,000
|
|
1.25000
|
%
|
Stifel Bank & Trust
|
|
$15,000,000
|
|
1.25000
|
%
|
Totals
|
|
$1,200,000,000
|
|
100.00000
|
%
|
Issuing Banks
|
Maximum LC Issuance Amount
|
||
Wells Fargo Bank, National Association
|
|
$50,000,000
|
|
DNB Bank ASA, New York Branch
|
|
$25,000,000
|
|
Total
|
|
$75,000,000
|
|
Senior Unsecured
Debt Rating |
Facility Fee
|
Eurodollar Margin
|
Base Rate Margin
|
Drawn Pricing (LIBOR)
|
>
BBB+ / Baa1
|
0.150%
|
0.975%
|
0.000%
|
1.125%
|
BBB / Baa2
|
0.175%
|
1.075%
|
0.075%
|
1.250%
|
BBB- / Baa3
|
0.200%
|
1.300%
|
0.300%
|
1.500%
|
< BBB- / Baa3
|
0.300%
|
1.450%
|
0.450%
|
1.750%
|
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.
|
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.
|
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.
|
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.
|
5.
|
Purchase and Sale Agreement, dated as of May 27, 2010, between WGR Asset Holding Company LLC and WGR Operating, LP.
|
6.
|
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.
|
7.
|
Contribution Agreement, dated as of December 15, 2011, 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.
|
8.
|
Contribution Agreement, dated as of February 27, 2013, by and among Anadarko Marcellus Midstream, L.L.C., Western Gas Partners, LP, Western Gas Operating, LLC, WGR Operating, LP, Anadarko Petroleum Corporation and Anadarko E&P Onshore LLC.
|
9.
|
First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated May 14, 2008.
|
10.
|
Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of December 19, 2008.
|
11.
|
Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated as of April 15, 2009.
|
12.
|
Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated July 22, 2009.
|
13.
|
Amendment No. 4 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP dated January 29, 2010.
|
14.
|
Amendment No. 5 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 2, 2010.
|
15.
|
Amendment No. 6 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated July 8, 2011.
|
16.
|
Amendment No. 7 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated January 13, 2012.
|
17.
|
Amendment No. 8 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated August 1, 2012.
|
18.
|
Amendment No. 9 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated December 12, 2012.
|
19.
|
Amendment No. 10 to First Amended and Restated Agreement of Limited Partnership of Western Gas Partners, LP, dated March 1, 2013.
|
20.
|
Second Amended and Restated Limited Liability Company Agreement of Western Gas Holdings, LLC, dated December 12, 2012.
|
21.
|
Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC and Anadarko Petroleum Corporation, dated as of May 14, 2008.
|
22.
|
Amendment No. 1 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 19, 2008.
|
23.
|
Amendment No. 2 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of July 22, 2009.
|
24.
|
Amendment No. 3 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of December 31, 2009.
|
25.
|
Amendment No. 4 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of January 29, 2010.
|
26.
|
Amendment No. 5 to Omnibus Agreement by and among Western Gas Partners, LP, Western Gas Holdings, LLC, and Anadarko Petroleum Corporation, dated as of August 2, 2010.
|
27.
|
Services And Secondment Agreement between Western Gas Holdings, LLC and Anadarko Petroleum Corporation dated May 14, 2008.
|
28.
|
Tax Sharing Agreement by and among Anadarko Petroleum Corporation and Western Gas Partners, LP, dated as of May 14, 2008.
|
29.
|
Anadarko Petroleum Corporation Fixed Rate Note due 2038.
|
30.
|
Gas Gathering and/or Processing Agreements between Western Gas Partners, LP or one of its subsidiaries, on the one hand, and Anadarko Petroleum Corporation or one of its affiliates, on the other hand.
|
31.
|
Amended and Restated Limited Liability Company Agreement of Chipeta Processing LLC.
|
32.
|
Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Anadarko E&P Onshore LLC.
|
33.
|
Third Amended and Restated Indemnification Agreement, dated March 1, 2013, between Western Gas Holdings, LLC and Western Gas Resources, Inc.
|
34.
|
Assignment of Indemnification Agreement, dated April 1, 2013, between Anadarko USH2 LLC and Anadarko E&P Onshore LLC.
|
35.
|
Indemnification Agreements (the form of which is on file with the Securities and Exchange Commission) by and between Western Gas Holdings, LLC, its Officers and Directors.
|
36.
|
Western Gas Partners, LP 2008 Long-Term Incentive Plan.
|
37.
|
Commodity Price Swap Agreements (the form of which is on file with the Securities and Exchange Commission) between the Partnership and Anadarko.
|
Amount of Loan
|
Type of Loan
|
Interest Rate
|
Amount of Principal Repair
|
Notation Made by
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1.
|
Assignor[s]: _______________________________
|
2.
|
Assignee[s]: _______________________________
|
3.
|
Borrower: Western Gas Partners, LP
|
4.
|
Administrative Agent:
|
5.
|
Credit Agreement: Second Amended and Restated Revolving Credit Agreement, dated as of February 26, 2014, among Western Gas Partners, LP, the Lenders named therein, Wells Fargo Bank, National Association, as Administrative Agent, the Documentation Agents named therein, and the Syndication Agent named therein.
|
6.
|
Assigned Interest[s]:
|
Assignor[s]
5
|
Assignee[s]
6
|
Facility Assigned
7
|
Aggregate Amount of Commitment / Loans for all Lenders
8
|
Amount of Commitment / Loans Assigned
8
|
Percentage Assigned of Commitment /
Loans 9 |
CUSIP Number
|
|
|
|
$
|
$
|
%
|
|
|
|
|
$
|
$
|
%
|
|
|
|
|
$
|
$
|
%
|
|
By:
|
Western Gas Holdings, LLC,
its general partner |
By:
|
Western Gas Holdings, LLC,
its general partner |
|
|
Year Ended December 31,
|
||||||||||||||||||
thousands
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
||||||||||
Earnings:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Income before income taxes
|
|
$
|
288,582
|
|
|
$
|
170,026
|
|
|
$
|
239,011
|
|
|
$
|
178,450
|
|
|
$
|
148,520
|
|
Add:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges
|
|
63,903
|
|
|
48,422
|
|
|
30,993
|
|
|
19,292
|
|
|
10,992
|
|
|||||
Distributions from equity investees
|
|
22,136
|
|
|
20,660
|
|
|
15,999
|
|
|
10,973
|
|
|
11,206
|
|
|||||
Amortization of capitalized interest
|
|
814
|
|
|
479
|
|
|
294
|
|
|
256
|
|
|
182
|
|
|||||
Less:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Equity income
|
|
23,732
|
|
|
16,111
|
|
|
11,261
|
|
|
7,628
|
|
|
7,923
|
|
|||||
Capitalized interest
|
|
11,945
|
|
|
6,196
|
|
|
420
|
|
|
—
|
|
|
—
|
|
|||||
Net income before taxes attributable to noncontrolling interests
|
|
10,816
|
|
|
14,890
|
|
|
14,103
|
|
|
11,005
|
|
|
10,260
|
|
|||||
Earnings
|
|
$
|
328,942
|
|
|
$
|
202,390
|
|
|
$
|
260,513
|
|
|
$
|
190,338
|
|
|
$
|
152,717
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Fixed charges:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest expense, including capitalized interest
|
|
$
|
63,742
|
|
|
$
|
48,256
|
|
|
$
|
30,765
|
|
|
$
|
18,794
|
|
|
$
|
9,955
|
|
Interest component of rent expense
|
|
161
|
|
|
166
|
|
|
228
|
|
|
498
|
|
|
1,037
|
|
|||||
Fixed charges
|
|
$
|
63,903
|
|
|
$
|
48,422
|
|
|
$
|
30,993
|
|
|
$
|
19,292
|
|
|
$
|
10,992
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ratio of earnings to fixed charges
|
|
5.1x
|
|
|
4.2x
|
|
|
8.4x
|
|
|
9.9x
|
|
|
13.9x
|
|
1.
|
I have reviewed this annual report on Form 10-K of Western Gas Partners, LP (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ Donald R. Sinclair
|
|
Donald R. Sinclair
President and Chief Executive Officer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
1.
|
I have reviewed this annual report on Form 10-K of Western Gas Partners, LP (the “registrant”);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a)
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b)
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c)
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d)
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a)
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b)
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ Benjamin M. Fink
|
|
Benjamin M. Fink
Senior Vice President, Chief Financial Officer and Treasurer
Western Gas Holdings, LLC
(as general partner of Western Gas Partners, LP)
|
(1)
|
the annual report on Form 10-K of the Partnership for the period ending
December 31, 2013
, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
|
February 28, 2014
|
|
|
|
|
|
|
|
/s/ Donald R. Sinclair
|
|
|
Donald R. Sinclair
|
|
|
President and Chief Executive Officer
|
|
|
Western Gas Holdings, LLC
|
|
|
(as general partner of Western Gas Partners, LP)
|
|
|
|
February 28, 2014
|
|
|
|
|
|
|
|
/s/ Benjamin M. Fink
|
|
|
Benjamin M. Fink
|
|
|
Senior Vice President, Chief Financial Officer and Treasurer
|
|
|
Western Gas Holdings, LLC
|
|
|
(as general partner of Western Gas Partners, LP)
|