OUR OPERATIONS
Our results are driven primarily by the volumes of natural gas we gather, compress, treat or transport through our systems. For the quarter ended March 31, 2008, approximately 68% of our revenues were derived from gathering, compression and treating activities, approximately 13% of our revenues were derived from transportation activities, approximately 14% of our revenues were derived from condensate sales and 5% of our revenues were derived from natural gas sales from settlement of imbalances and other revenues. For the quarter ended March 31, 2008, approximately 72% and 14% of our total revenues were attributable to transactions entered into with Anadarko and National Cooperative Refinery Association, respectively.
In our gathering operations, we contract with producers 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. Effective January 1, 2008, we received a significant dedication from our largest customer, Anadarko, in order to maintain or increase our existing throughput levels and to offset the natural production declines of the wells currently connected to our gathering systems. Specifically, Anadarko has dedicated to us all of the natural gas production it owns or controls from (i) wells that are currently connected to our gathering systems, and (ii) additional wells that are drilled within one mile of connected wells or our gathering systems, as the 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 additional wells are connected to our gathering systems. Volumes associated with this dedication averaged approximately 671,000 MMBtu/d for the quarter ended March 31, 2008 and 771,000 MMBtu/d for the quarter ended March 31, 2007, based on throughput from the wells ultimately subject to the dedication. We generally do not take title to the natural gas that we gather, compress, treat or transport. We currently provide all of our gathering and treating services pursuant to fee-based contracts. Under these arrangements, we are paid a fixed fee based on the volume and thermal content of the natural gas we gather, compress, 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 we retain and sell condensate that is recovered during the gathering of natural gas from the wellhead. Pursuant to the terms of the new gathering contracts we entered into with Anadarko and described in more detail under "Items Affecting the Comparability of our Financial Results" below, we will receive higher gathering fees than we have historically received. We have indirect exposure to commodity price risk in that persistent low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the volumes of natural gas available for gathering, compressing, treating and transporting by our systems. Please read "Quantitative and Qualitative Disclosures about Market Risk" below for a discussion of our exposure to commodity price risk through our condensate recovery and sales.
We provide a significant portion of our transportation services on our MIGC system through firm contracts that obligate our customers to pay a monthly reservation or demand charge, which is a fixed charge applied to firm contract capacity and owed by a customer regardless of the actual pipeline capacity used by that customer. When a customer uses the capacity it has reserved under these contracts, we are entitled to collect an additional commodity usage charge based on the actual volume of natural gas transported. These usage charges are typically a small percentage of the total revenues received from our firm capacity contracts. We also provide transportation services through interruptible contracts, pursuant to which a fee is charged to our customers based upon actual volumes transported through the pipeline.
As a result of the completion of the Offering on May 14, 2008, the results of operations, financial condition and cash flows are expected to vary significantly in 2008 and future periods when compared to the quarter ended March 31, 2008 and prior periods. Please see "Items Affecting the Comparability of our Financial Results," set forth below in this Item.
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 volumes,
(2) operating expenses and (3) Adjusted EBITDA.

Throughput volumes
In order to maintain or increase throughput volumes on our gathering systems, we must connect additional wells to our systems. Our success in connecting additional wells is impacted by successful drilling of new wells which will be dedicated 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 or treated by our competitors.
To maintain and increase throughput volumes on our MIGC system, we must continue to contract our capacity to shippers, including producers and marketers, for transportation of their natural gas. We monitor producer and marketing activities in the area served by our transportation system to identify new opportunities.
Operating expenses
We analyze operating expenses to evaluate our performance. The primary components of our operating expenses that we evaluate include operation and maintenance expenses, cost of product expenses, general and administrative expenses and direct operating expenses. Certain of our operating expenses are classified based on whether the expenses are accrued for or paid to our affiliates or third-party vendors. Neither affiliate expenses nor third-party expenses bear a direct relationship to affiliate revenues or third-party revenues. For example, our third-party expenses are not those expenses necessary for generating our third-party revenues. Third-party expenses include all amounts accrued for or paid to third parties for the operation of our systems, whether in providing services to Anadarko or third parties, including utilities, field labor, measurement and analysis and other third-party disbursements. Operation and maintenance expenses include, among other things, direct labor, insurance, repair and maintenance, contract services, utility costs and services provided to us or on our behalf. For future periods, including a portion of the period in which the Offering was completed, these expenses are governed by our services and secondment agreement with Anadarko.
Cost of product expenses include (i) costs associated with the purchase of natural gas pursuant to the gas imbalance provisions contained in our contracts,
(ii) 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 (iii) our fuel tracking mechanism, which tracks the difference between actual fuel usage and loss and amounts recovered for estimated fuel usage and loss under our contracts. These expenses are subject to variability. However, for the quarters ended March 31, 2008 and 2007, cost of product expenses comprised 17.4% and 15.8% of total operating expenses, respectively. We do not expect the variability in our cost of product expenses to have a material impact on our overall results. General and administrative expenses include reimbursements of costs incurred by Anadarko on our behalf and allocations from Anadarko in the form of a management service fee in lieu of direct reimbursements for various corporate services. Subsequent to the Offering, Anadarko will not receive a management services fee and we expect general and administrative expenses to be comprised primarily of amounts reimbursed by us to Anadarko pursuant to our omnibus agreement with Anadarko and expenses attributable to our status as a publicly traded partnership, such as:
• expenses associated with annual and quarterly reporting;

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

• Sarbanes-Oxley compliance expenses;

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

• independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees.

Pursuant to the omnibus agreement with Anadarko, we will reimburse Anadarko for allocated general and administrative expenses. The amount required to be reimbursed by us to Anadarko for certain allocated general and administrative expenses pursuant to the omnibus agreement will be capped at $6.0 million annually through December 31, 2009, subject to adjustment to reflect changes in the Consumer Price Index and, with the concurrence of the special committee of our general partner's board of directors, to reflect expansions of our operations through the acquisition or construction of new assets or businesses. Thereafter, our general partner will

determine the general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. The cap contained in the omnibus agreement does not apply to incremental general and administrative expenses we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.5 million per year.
Adjusted EBITDA
We define Adjusted EBITDA as net income (loss), plus interest expense, income tax expense and depreciation, less interest income, income tax benefit and other income (expense).
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 combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:
• our operating performance as compared to 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.

The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to the GAAP measures of net income or net cash provided by operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.
Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between Adjusted EBITDA and net income and net cash provided by operating activities, and incorporating this knowledge into its decision-making processes. We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our operating results.

The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities on an historical as adjusted basis:

                                                                     Quarter Ended March 31,
                                                                      2008               2007
                                                                          (in thousands)
Reconciliation of Adjusted EBITDA to Net Income

Net Income                                                        $      9,219         $   6,350
Add:
Interest expense - affiliates                                            2,126             2,139
Income tax expense                                                       5,288             3,535
Depreciation                                                             6,456             5,372
Less:
Other income                                                                 4                 -

Adjusted EBITDA                                                   $     23,085         $  17,396


Reconciliation of Adjusted EBITDA to Net Cash Provided by
Operating Activities

Net cash provided by operating activities                         $     19,749         $  11,012
Interest expense                                                         2,126             2,139
Current income tax expense                                               1,990                85
Less other income                                                            4                 -
Changes in operating working capital:
Accounts receivable and natural gas imbalances                             (19 )              98
Accounts payable and accrued expenses                                     (758 )           4,131
Other, including changes in non-current assets and
liabilities                                                                  1               (69 )

Adjusted EBITDA                                                   $     23,085         $  17,396

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS
Our historical results of operations for the periods presented may not be comparable to future or historic results of operations for the reasons described below:
• We anticipate incurring approximately $2.5 million of general and administrative expenses annually attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; and registrar and transfer agent fees. These incremental general and administrative expenses are not reflected in our historical combined financial statements.

• We anticipate incurring up to $6.0 million in general and administrative expenses annually to be charged to us by Anadarko pursuant to the omnibus agreement. This amount is expected to be greater than the amount allocated to us by Anadarko for the management services fee reflected in our historical combined financial statements.

• Historically, the impact of all affiliated transactions has been net settled within our combined financial statements because these transactions related to Anadarko and were funded by Anadarko's working capital. Third-party transactions were funded by our working capital. In the future, all affiliate and third-party transactions will be funded by our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.

• Prior to the Offering, we incurred interest expense on intercompany notes payable to Anadarko. These intercompany balances were extinguished through non-cash transactions in connection with the Offering; therefore, interest expense attributable to these balances and reflected in our historical combined financial statements will not be incurred in future periods.

• For periods ending prior to January 1, 2008, our combined financial statements reflect the gathering fees we historically charged Anadarko under our affiliate cost-of-service-based arrangements. Under these arrangements, we recovered, on an annual basis, our operation and maintenance, general and administrative and depreciation expenses in addition to earning a return on our invested capital. Effective January 1, 2008, we entered into new 10-year gas gathering agreements with Anadarko. As discussed above, our fees for gathering and treating services rendered to Anadarko pursuant to the terms of the new gas gathering agreements increased. In part, this increase is attributable to our operation and maintenance expense increasing as a result of us bearing all of the cost of employee benefits specifically identified and related to operational personnel working on our assets, as compared to bearing only those employee benefit costs reasonably allocated by Anadarko to us for the periods ending prior to January 1, 2008. Since our new gas gathering agreements are designed to fully recover these costs, our revenues increased by an amount equal to the employee-benefit related increase in operation and maintenance expense. Although this change in methodology for computing affiliate gathering rates does not impact our net cash flows or net income, this methodology change impacts the components thereof as compared to periods ending prior to January 1, 2008. If we applied the methodology employed under our new gas gathering agreements with Anadarko for the quarter ended March 31, 2007, we estimate our gathering revenues and operation and maintenance expense would have increased by $1.1 million and our cash flow from operations would have remained unchanged.

• The gas gathering agreements with Anadarko effective January 1, 2008 include new fees for gathering and treating. The new fees are based on recent capital improvements and changes in our cost-of-service analysis and are higher than those fees reflected in our historical financial results prior to January 1, 2008.

• Concurrent with the closing of the Offering, we loaned $260.0 million to Anadarko in exchange for a 30-year note bearing interest at a fixed annual rate of 6.50%. Interest income attributable to the note is not reflected in our historical combined financial statements, but will be included in our combined financial statements in the future.

• Pursuant to the omnibus agreement, as a co-borrower under Anadarko's credit facility, we are required to reimburse Anadarko for our allocable portion of commitment fees (0.11% of our committed and available borrowing capacity) that Anadarko incurs under its credit facility, or up to $110,000. Please read "Certain relationships and related party transactions - Agreements governing the transactions - Omnibus agreement" in the Partnership's Registration Statement on Form S-1, as amended, filed with the SEC on April 25, 2008. In addition, Anadarko entered into a working capital facility with us, under which we expect to incur an annual commitment fee of 0.11% of the unused portion of our committed borrowing capacity of $30 million, or up to $33,000.

• Our historical combined financial statements include U.S. federal and state income tax expense incurred by us. Due to our status as a partnership, we will not be subject to U.S. federal income tax and certain state income taxes in the future. However, we will make payments to Anadarko pursuant to a tax sharing agreement for our share of state and local income and other taxes that are included in combined or consolidated tax returns filed by Anadarko.

• After the Offering date, we intend to make cash distributions to our unitholders and our general partner at an initial distribution rate of $0.30 per unit per full quarter ($1.20 per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including commercial bank borrowings and debt and equity issuances, to fund our acquisition and expansion capital expenditures. Historically, we largely relied on internally generated cash flows and capital contributions from Anadarko to satisfy our capital expenditure requirements.

• In connection with the closing of the Offering, our general partner adopted two new compensation plans, the Western Gas Partners, LP 2008 Long-Term Incentive Plan ("LTIP") and the Western Gas Holdings, LLC Equity Incentive Plan ("Incentive Plan"). Phantom unit grants have been made to each of our independent directors under the LTIP, and incentive unit grants have been made to each of our executive officers pursuant to the Incentive Plan. Pursuant to Financial Accounting Standards Board ("FASB") Statement No. 123 (revised 2004), "Shared-Based Payment" ("SFAS 123R"), grants made under

equity-based compensation plans result in share-based compensation expense which is determined, in part, by reference to the fair value of equity compensation as of the date of grant. Share-based compensation expense is not reflected in our historical combined financial statements as there were no outstanding equity grants under either plan for the periods presented. Share-based compensation expense for grants made pursuant to the LTIP and Incentive Plan will be reflected in our future statements of operations. Share-based compensation expense attributable to grants made pursuant to the LTIP will impact our cash flow from operating activities only to the extent our board of directors, at its discretion, elects to make a cash payment to . . .