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WES > SEC Filings for WES > Form 10-K on 28-Feb-2014All Recent SEC Filings

Show all filings for WESTERN GAS PARTNERS LP

Form 10-K for WESTERN GAS PARTNERS LP


28-Feb-2014

Annual Report


Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

Western Gas Partners, LP is a growth-oriented a master limited partnership ("MLP") formed by Anadarko Petroleum Corporation in 2007. For purposes of this report, "we," "us," "our," the "Partnership," or "Western Gas Partners" refers to Western Gas Partners, LP and its subsidiaries. Our general partner, Western Gas Holdings, LLC (the "general partner" or "GP"), is owned by Western Gas Equity Partners, LP ("WGP"), a Delaware master limited partnership formed by Anadarko Petroleum Corporation. Western Gas Equity Holdings, LLC is WGP's general partner and is a wholly owned subsidiary of Anadarko Petroleum Corporation. "Anadarko" refers to Anadarko Petroleum Corporation and its consolidated subsidiaries, excluding the Partnership and our general partner, and "affiliates" refers to wholly owned and partially owned subsidiaries of Anadarko, excluding the Partnership, and includes equity interests in Fort Union Gas Gathering, LLC ("Fort Union"), White Cliffs Pipeline, LLC ("White Cliffs"), Rendezvous Gas Services, LLC ("Rendezvous"), and Enterprise EF78 LLC (the "Mont Belvieu JV"). "Equity investment throughput" refers to our 14.81% share of Fort Union and 22% share of Rendezvous gross volumes.
References to the "Partnership assets" refer collectively to the assets we owned as of December 31, 2013. Because Anadarko controls us through its ownership and control of WGP, which owns our general partner, each of our acquisitions from Anadarko has been considered a transfer of net assets between entities under common control. As such, the Partnership assets we acquired from Anadarko were initially recorded at Anadarko's historic carrying value, which did not correlate to the total acquisition price paid by us. Further, after an acquisition of assets from Anadarko, we may be required to recast our financial statements to include the activities of such assets as of the date of common control (see Note 2-Acquisitions in the Notes to the Consolidated Financial Statements under Item 8 of this Form 10-K). For those periods requiring recast, the consolidated financial statements for periods prior to our acquisition of the Partnership assets from Anadarko have been prepared from Anadarko's historical cost-basis accounts and may not necessarily be indicative of the actual results of operations that would have occurred if we had owned the assets during the periods reported. For ease of reference, we refer to the historical financial results of the Partnership assets prior to our acquisitions from Anadarko as being "our" historical financial results.
The following discussion analyzes our financial condition and results of operations and should be read in conjunction with the consolidated financial statements and notes to consolidated financial statements, which are included in Item 8 of this Form 10-K.

EXECUTIVE SUMMARY

We are an MLP organized by Anadarko to own, operate, acquire and develop midstream energy assets. We currently own assets located in East, West and South Texas, the Rocky Mountains (Colorado, Utah and Wyoming), north-central Pennsylvania, and the Mid-Continent (Kansas and Oklahoma), and are engaged in the business of gathering, processing, compressing, treating and transporting natural gas, condensate, NGLs and crude oil for Anadarko, as well as for third-party producers and customers. As of December 31, 2013, our assets, exclusive of our interests in Fort Union, White Cliffs, Rendezvous and the Mont Belvieu JV accounted for under the equity method, consisted of the following:

                                    Owned and     Operated    Non-Operated
                                     Operated    Interests      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            -               -

See also Note 12-Subsequent Events in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


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Significant financial and operational highlights during the year ended December 31, 2013 included the following:

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.

Significant operational highlights during the year ended December 31, 2013 included the following:

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.


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OUR OPERATIONS

Our results are driven primarily by the volumes of natural gas and NGLs we gather, process, treat or transport through our systems. For the year ended December 31, 2013, 79% of our total revenues and 57% of our throughput (excluding equity investment throughput and revenues) were attributable to transactions with Anadarko.
In our gathering operations, we contract with producers and customers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering lines through which natural gas may be compressed and delivered to a processing plant, treating facility or downstream pipeline, and ultimately to end users. We also treat a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation.
We received significant dedications from our largest customer, Anadarko, solely with respect to our Wattenberg, Dew, Pinnacle, Haley, Helper, Clawson and Hugoton gathering systems. Specifically, pursuant to the terms of our applicable gathering agreements, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to such gathering systems, and (ii) additional wells that are drilled within one mile of wells connected to such gathering systems, as those systems currently exist and as they are expanded to connect additional wells in the future. As a result, this dedication will continue to expand as long as additional wells are connected to these gathering systems.
For the year ended December 31, 2013, 74% of our gross margin was attributable to fee-based contracts, under which a fixed fee is received based on the volume or thermal content of the natural gas we gather, process, treat or transport. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements. Fee-based gross margin includes equity income from our interests in Fort Union, White Cliffs and Rendezvous.
For the year ended December 31, 2013, 26% of our gross margin, including gross margin attributable to condensate sales, was attributable to percent-of-proceeds and keep-whole contracts, pursuant to which we have commodity price exposure. A substantial majority of the commodity price risk associated with our percent-of-proceeds and keep-whole contracts is hedged under commodity price swap agreements with Anadarko. 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. See Note 5-Transactions with Affiliates in the Notes to Consolidated Financial Statements included under Item 8 of this Form 10-K. We also have indirect exposure to commodity price risk in that persistent low natural gas prices have caused and may continue to cause our current or potential customers to delay drilling or shut in production in certain areas, which would reduce the volumes of natural gas available for our systems. We also bear a limited degree of commodity price risk through settlement of natural gas imbalances. Please read Item 7A of this Form 10-K.
As a result of our initial public offering ("IPO") and subsequent acquisitions from Anadarko and third parties, our results of operations, financial position and cash flows may vary significantly for 2013, 2012 and 2011 as compared to future periods. Please see the caption Items Affecting the Comparability of Our Financial Results, set forth below in this Item 7.

HOW WE EVALUATE OUR OPERATIONS

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (1) throughput, (2) gross margin, (3) operating and maintenance expenses, (4) general and administrative expenses, (5) Adjusted EBITDA (as defined below) and (6) Distributable cash flow (as defined below).


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Throughput. Throughput is an essential operating variable we use in assessing our ability to generate revenues. In order to maintain or increase throughput on our gathering and processing systems, we must connect additional wells to our systems. Our success in maintaining or increasing throughput is impacted by successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage and our ability to attract natural gas volumes currently gathered, processed or treated by our competitors. During the year ended December 31, 2013, we added 273 receipt points to our systems.

Gross margin. We define gross margin as total revenues less cost of product. We consider gross margin to provide information useful in assessing our results of operations and our ability to internally fund capital expenditures and to service or incur additional debt. Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent-of-proceeds and keep-whole processing contracts, (ii) costs associated with the valuation of our gas imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties, and (iv) costs associated with our fuel-tracking mechanism, which tracks the difference between actual fuel usage and loss, and amounts recovered for estimated fuel usage and loss pursuant to our contracts. These expenses are subject to variability, although our exposure to commodity price risk attributable to purchases and sales of natural gas, condensate and NGLs is mitigated through our commodity price swap agreements with Anadarko.

Operating and maintenance expenses. We monitor operating and maintenance expenses to assess the impact of such costs on the profitability of our assets and to evaluate the overall efficiency of our operations. Operating and maintenance expenses include, among other things, field labor, insurance, repair and maintenance, equipment rentals, contract services, utility costs and services provided to us or on our behalf. For periods commencing on the date of and subsequent to our acquisition of the Partnership assets, certain of these expenses are incurred under and governed by our services and secondment agreement with Anadarko.

General and administrative expenses. To help ensure the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses through comparison to prior periods, to the annual budget approved by our general partner's board of directors, as well as to general and administrative expenses incurred by similar midstream companies. General and administrative expenses for periods prior to our acquisition of the Partnership assets include amounts attributable to costs incurred on our behalf and allocations of general and administrative costs by Anadarko and the general partner to us. For periods subsequent to our acquisition of the Partnership assets, Anadarko is no longer compensated for corporate services through a management services fee. Instead, allocations and reimbursements of general and administrative expenses are determined by Anadarko in its reasonable discretion, in accordance with our partnership agreement and omnibus agreement. Amounts required to be reimbursed to Anadarko under the omnibus agreement also include those expenses attributable to our status as a publicly traded partnership, such as the following:

expenses associated with annual and quarterly reporting;

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

expenses associated with listing on the New York Stock Exchange; and

independent auditor fees, legal expenses, investor relations expenses, director fees, and registrar and transfer agent fees.

See further detail under Items Affecting the Comparability of Our Financial Results - General and administrative expenses below and Note 5-Transactions with Affiliates in the Notes to Consolidated Financial Statements under Item 8 of this Form 10-K.


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Non-GAAP financial measures

Adjusted EBITDA. We define "Adjusted EBITDA" as net income attributable to Western Gas Partners, LP, plus distributions from equity investees, non-cash equity-based compensation expense, interest expense, income tax expense, depreciation, amortization and impairments, and other expense, less income from equity investments, interest income, income tax benefit, and other income. We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our financial condition and results of operations and that Adjusted EBITDA is a widely accepted financial indicator of a company's ability to incur and service debt, fund capital expenditures and make distributions. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following, among other measures:

our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis;

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

the viability of acquisitions and capital expenditure projects and the returns on investment of various investment opportunities.

Distributable cash flow. We define "Distributable cash flow" as Adjusted EBITDA, plus interest income, less net cash paid for interest expense (including amortization of deferred debt issuance costs originally paid in cash, offset by non-cash capitalized interest), maintenance capital expenditures, and income taxes. We compare Distributable cash flow to the cash distributions we expect to pay our unitholders. Using this measure, management can quickly compute the Coverage ratio of estimated cash flows to planned cash distributions. We believe Distributable cash flow is useful to investors because this measurement is used by many companies, analysts and others in the industry as a performance measurement tool to evaluate our operating and financial performance and compare it with the performance of other publicly traded partnerships.
While Distributable cash flow is a measure we use to assess our ability to make distributions to our unitholders, it should not be viewed as indicative of the actual amount of cash that we have available for distributions or that we plan to distribute for a given period.

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


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The following tables present (a) a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income attributable to Western Gas Partners, LP and net cash provided by operating activities, and (b) a reconciliation of the non-GAAP financial measure of Distributable cash flow to the GAAP financial measure of net income attributable to Western Gas Partners, LP:

                                                                 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.


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                                                             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 . . .

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