You should read the following discussion of the financial condition and results of operations of Summit Midstream Partners, LP and its subsidiaries in conjunction with the unaudited condensed consolidated financial statements and related notes of Summit Midstream Partners, LLC (the "Predecessor") that are included herein as well as the historical consolidated financial statements and related notes of the Predecessor in our Rule 424(b)(4) Prospectus filed with the U.S. Securities and Exchange Commission (the "SEC") on September 28, 2012 (the "Rule 424(b)(4) Prospectus"). Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information.

We are a growth-oriented limited partnership focused on owning and operating midstream energy infrastructure that is strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. We currently provide fee-based natural gas gathering and compression services in two unconventional resource basins (i) the Piceance Basin, which includes the Mesaverde, Mancos and Niobrara Shale formations in western Colorado; and (ii) the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas.

We generate a substantial majority of our revenue under long-term, fee-based natural gas gathering agreements ("GGAs"). The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure. During the nine months ended September 30, 2012, our systems gathered an average of approximately 928 MMcf/d of natural gas, of which approximately 63% contained natural gas liquids, or NGLs, that were extracted by a third party processor.

We manage our business and analyze our results of operations as a single business segment. Our management uses a variety of financial and operational metrics to analyze our performance. We view these metrics as important factors in evaluating our profitability and review these measurements on a regular basis for consistency and trend analysis. These metrics include:

†          throughput volume;

†          operations and maintenance expenses;

†          Adjusted EBITDA; and

†          distributable cash flow.

Throughput Volume

The volume of natural gas that we gather depends on the level of production from natural gas wells connected to the Grand River and DFW Midstream systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity, as production must be maintained or increased by new drilling or other activity, because the production rate of a natural gas well declines over time.

As a result, we must continually obtain new supplies of natural gas to maintain or increase the throughput volume on our systems. Our ability to maintain or increase existing throughput volumes and obtain new supplies of natural gas is impacted by:

†          successful drilling activity within our areas of mutual interest, or
AMIs;

†          the level of work-overs and recompletions of wells on existing pad
sites to which our gathering systems are connected;

†          the number of new pad sites in our AMIs awaiting connections;

†          our ability to compete for volumes from successful new wells in the
areas in which we operate outside of our existing AMIs; and

†          our ability to gather natural gas that has been released from
commitments with our competitors.

Operations and Maintenance Expenses

Direct labor costs, compression costs, insurance costs, ad valorem and property taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operations and maintenance expense. Other than utilities expense, these expenses are relatively stable and largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period. The majority of our compressors in the Barnett Shale are electric driven and power costs are directly correlated to the run-time of these compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our Barnett Shale customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. In addition, we pass along the fees associated with costs we incur on behalf of certain Barnett Shale customers to deliver pipeline quality natural gas to third-party pipelines. In the Piceance Basin, we either
(i) consume physical gas on the system to operate our gas-fired compressors or
(ii) charge our customers for the power costs we incur to operate our electric-drive compression assets.

EBITDA, Adjusted EBITDA and Distributable Cash Flow

We define EBITDA as net income, plus interest expense, income tax expense, and depreciation and amortization expense, less interest income and income tax benefit. We define Adjusted EBITDA as EBITDA plus non-cash compensation expense and adjustments related to MVC shortfall payments. We define distributable cash flow as Adjusted EBITDA plus cash interest income, less cash paid for interest expense and income taxes and maintenance capital expenditures.

EBITDA, Adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others. We also use distributable cash flow to analyze our performance and liquidity. Distributable cash flow will not reflect changes in working capital balances.

EBITDA and Adjusted EBITDA are used to assess:

† the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

† the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;

† our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

† the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

In addition, Adjusted EBITDA is used to assess:

† the financial performance of our assets without regard to the impact of the timing of minimum volume commitments, or MVC, shortfall payments under our GGAs or the impact of non-cash compensation expense.

Distributable Cash Flow is used to assess:

† the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and

† the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

Note Regarding Non-GAAP Financial Measures

EBITDA, Adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.

Net income and net cash flows provided by operating activities are the GAAP measures most directly comparable to EBITDA, Adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Furthermore, each of these non-GAAP financial

measures has important limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. EBITDA, Adjusted EBITDA or distributable cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA, Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

Items Affecting the Comparability of Our Financial Results

The historical results of operations of the Predecessor may not be comparable to SMLP's future results of operations for the reasons described below:

† The historical consolidated financial statements of the Predecessor do not include any results from the acquisition of the Grand River system prior to November 2011.

† The historical results of operations of the Predecessor may not be comparable to our future results of operations largely due to our IPO, which closed on October 3, 2012. We anticipate incurring approximately $2.5 million of G&A expense attributable to operating as a publicly traded partnership. Incremental public entity costs include:

(i) expenses associated with annual and quarterly reporting;
(ii) tax return and Schedule K-1 preparation and distribution expenses;
(iii) Sarbanes-Oxley compliance expenses;
(iv) expenses associated with listing on the NYSE;
(v) independent auditor fees;
(vi) legal fees;
(vii) investor relations expenses;
(viii) registrar and transfer agent fees;
(ix) director and officer liability insurance costs; and
(x) director compensation.

These incremental G&A expenses are not reflected in the historical consolidated financial statements of the Predecessor.

The following table presents certain consolidated and other financial data of the Predecessor for the periods indicated.

                                              Three months ended          Nine months ended
                                                September 30,               September 30,
                                              2012          2011          2012         2011
                                                             (In thousands)
Statement of Operations Data:
Revenue:
Gathering services and other fees          $    37,903    $  18,734    $  106,550    $  55,776
Natural gas and condensate sales                 3,232        3,489        10,290        8,513
Amortization of favorable and
unfavorable contracts (1)                         (160 )        (63 )          25         (261 )
Total revenue                                   40,975       22,160       116,865       64,028
Costs and expenses:
Operations and maintenance                      14,460        5,992        37,177       18,787
General and administrative                       5,179        3,747        15,977       11,122
Transaction costs                                1,739            -         1,972            -
Depreciation and amortization                    9,156        2,109        26,135        5,471
Total costs and expenses                        30,534       11,848        81,261       35,380
Other income                                         2            2             8           10
Interest expense                                (2,827 )       (350 )      (5,573 )       (388 )
Affiliated interest expense                        (13 )          -        (5,426 )          -
Income before income taxes                       7,603        9,964        24,613       28,270
Income tax expense                                (207 )       (157 )        (501 )       (524 )
Net income                                 $     7,396    $   9,807    $   24,112    $  27,746

Other Financial Data:
EBITDA(2)                                  $    19,757    $  12,484    $   61,714    $  34,380
Adjusted EBITDA(2)                              23,124       13,210        74,668       37,047
Capital expenditures(3)                         36,284       34,767        60,647       61,242
Distributable cash flow                         18,579       12,017        63,832       33,907

(2) EBITDA and Adjusted EBITDA for the three months ended September 30, 2012 included $1.7 million in transaction costs related to the Predecessor's acquisition of ETC Canyon Pipeline, LLC ("Canyon") and an adjustment of approximately $1.0 million to the Predecessor's estimate for ad valorem taxes associated with Grand River Gathering for 2012. Canyon is not an asset of SMLP. EBITDA and Adjusted EBITDA for the nine months ended September 30, 2012 included $1.9 million in transaction costs, of which $1.7 million related to the acquisition of Canyon and $0.2 million related to the acquisition of the Grand River system. These unusual and non-recurring expenses were or will be settled in cash.

(3) Capital expenditures do not include acquisition capital expenditures, of which there were none in the periods presented for 2012 and 2011. In addition, we historically did not make a distinction between maintenance and expansion capital expenditures; however, to calculate distributable cash flow, we have estimated the portion of these expenditures that were maintenance capital expenditures.

The following table presents a reconciliation of the Predecessor's net income to EBITDA, Adjusted EBITDA and distributable cash flow.

                                             Three months ended         Nine months ended
                                                September 30,             September 30,
                                              2012          2011         2012         2011
                                                            (In thousands)
Reconciliation of Net Income to EBITDA,
Adjusted EBITDA and Distributable Cash
Flow:
Net income                                 $     7,396    $  9,807    $   24,112    $ 27,746
Add:
Interest expense                                 2,840         350        10,999         388
Income tax expense                                 207         157           501         524
Depreciation and amortization expense            9,156       2,109        26,135       5,471
Amortization of favorable and
unfavorable contracts                              160          63           (25 )       261
Less:
Interest income                                      2           2             8          10
EBITDA (1)                                 $    19,757    $ 12,484    $   61,714    $ 34,380
Add:
Non-cash compensation expense                      381         726         1,793       2,667
Adjustments related to MVC shortfall
payments (2)                                     2,986           -        11,161           -
Adjusted EBITDA (1)                        $    23,124    $ 13,210    $   74,668    $ 37,047
Add:
Interest income                                      2           2             8          10
Less:
Cash interest paid                               2,683         501         6,274         982
Cash taxes paid                                    650           -           650         223
Maintenance capital expenditures (3)             1,214         694         3,920       1,945
Distributable cash flow                    $    18,579    $ 12,017    $   63,832    $ 33,907

(2) For a discussion of adjustments related to MVC shortfall payments, see "Our Cash Distribution Policy and Restrictions on Distributions-Unaudited Historical As Adjusted Cash Available for Distribution for the Year Ended December 31, 2011 and the twelve months ended June 20, 2012" included in the Rule 424(b)(4) Prospectus.

(3) We historically did not make a distinction between maintenance and expansion capital expenditures; however, to calculate distributable cash flow, we have estimated the portion of these expenditures that were maintenance capital expenditures.

The following table presents a reconciliation of the Predecessor's net cash flows provided by operating activities to EBITDA and Adjusted EBITDA.