You should read the following discussion of our financial condition and results of operations in conjunction with the unaudited historical consolidated financial statements and notes thereto included in Item 1 of this report, as well as Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," and the audited financial statements included under Item 8 in our Annual Report on Form 10-K for the year ended December 31, 2011 (the "2011 10-K").

As generally used in the energy industry and in this report, the following terms have the following meanings:

/d:            Per day
Bbls:          Barrels
Condensate:    Hydrocarbons that are produced from natural gas reservoirs but
               remain liquid at normal temperature and pressure
Lean gas:      Natural gas that is low in NGL content
MMBtu:         One million British thermal units
Mcf:           One thousand cubic feet
MMcf:          One million cubic feet
NGLs:          Natural gas liquids, which consist primarily of ethane, propane,
               isobutane, normal butane, natural gasoline and stabilized
               condensate
Residue gas:   The pipeline quality natural gas remaining after natural gas is
               processed and NGLs removed
Rich gas:      Natural gas that is high in NGL content
Throughput:    The volume of natural gas or NGLs transported or passing through a
               pipeline, plant, terminal or other facility

Forward-Looking Statements

This report contains "forward-looking statements" within the meaning of the federal securities laws. All statements in this report other than statements of historical fact, including those under "- Trends and Uncertainties," "- Our Results of Operations" and "- Liquidity and Capital Resources" are forward-looking statements. Forward-looking statements address activities, events or developments that we expect or anticipate will or may occur in the future, including references to future goals or intentions. These statements can be identified by the use of forward-looking terminology, including "may," "believe," "expect," "anticipate," "estimate," "continue," or similar words. These statements include assertions related to plans for growth of our business, future capital expenditures and competitive strengths and goals. We make these statements based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed or implied in these statements. Any differences could be caused by a number of factors, including, but not limited to:

º •
º the volatility of prices and market demand for natural gas, crude oil, condensate and NGLs, and for products derived from these commodities;

º •
º our ability to continue to connect new sources of natural gas, crude oil and condensate, and the NGL content of new gas supplies;

º •
º the ability of key producers to continue to drill and successfully complete and connect new natural gas and condensate volumes and such producers' performance under their contracts with us;

º •
º our ability to attract and retain key customers and contract with new customers, and such customers' performance under their contracts with us;

º •
º our ability to access or construct new pipeline capacity, gas processing and NGL fractionation and transportation capacity;

º •
º the availability of local, intrastate and interstate transportation systems, trucks and other facilities and services for condensate, natural gas and NGLs;

º •
º our ability (and the ability of our third-party service providers) to meet in-service dates, cost expectations and operating performance standards for construction projects;

º •
º our ability to successfully integrate any acquired asset or operations;

º •
º our ability to access our revolving credit facility and to obtain additional financing on acceptable terms;

º •
º the effectiveness of our hedging program;

º •
º general economic conditions;

º •
º force majeure events such as the loss of a market or facility downtime;

º •
º the effects of government regulations and policies; and

º •
º other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.

This report and our 2011 10-K include cautionary statements identifying important factors that could cause our actual results to differ materially from our expectations expressed or implied in forward-looking statements. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this report and under Item 1A, "Risk Factors" in our 2011 10-K. All forward-looking statements in this report and all subsequent written or oral forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements. Forward-looking statements speak only as of the date made, and we undertake no obligation to publicly update or revise any forward-looking statements, other than as required by law, whether as a result of new information, future events or otherwise.

Overview

Through our subsidiaries and equity investments, we own and operate natural gas gathering and intrastate transportation pipeline assets, natural gas processing and fractionation facilities and NGL pipelines. We operate in Texas, Oklahoma and Wyoming. We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into three operating segments: Texas, Oklahoma and Rocky Mountains.

Texas. Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and transportation of natural gas, and related services such as compression, dehydration, treating, processing and marketing. Our Texas segment also provides NGL fractionation and transportation services, and through August 2012, included a processing plant located in southwest Louisiana. In addition to our 100%-owned operations, this segment includes:

º •
º our 50% interest in Eagle Ford Gathering LLC ("Eagle Ford Gathering"), which provides midstream natural gas services to Eagle Ford Shale producers;

º •
º our 50% interest in Liberty Pipeline Group, LLC ("Liberty Pipeline Group"), which transports mixed NGLs from our Houston Central complex to the Texas Gulf Coast;

º •
º our 62.5% interest in Webb/Duval Gatherers ("Webb Duval"), which provides natural gas gathering in south Texas; and

º •
º our 50% interest in Double Eagle Pipeline LLC ("Double Eagle Pipeline"), which is constructing a condensate and crude oil gathering system that will serve Eagle Ford Shale producers.

Oklahoma. Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including primarily low-pressure gathering of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our majority interest in Southern Dome, LLC ("Southern Dome"), which provides gathering and processing services within the Southern Dome prospect in the southern portion of Oklahoma County.

Rocky Mountains. Our Rocky Mountains segment provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas. In addition to our 100%-owned producer services business, this segment includes:

º •
º our 51% interest in Bighorn Gas Gathering, L.L.C. ("Bighorn"), which provides gathering services to Powder River Basin producers; and

º •
º our 37.04% interest in Fort Union Gas Gathering, L.L.C. ("Fort Union"), which provides gathering and treating services to Powder River Basin producers.

Corporate and Other. Items reported as "Corporate and other" relate to our risk management activities, intersegment eliminations and other activities we perform or assets we hold that have not been allocated to any of our operating segments.

Recent Developments

Public Equity Offering. In October 2012, we completed a registered underwritten offering of 6,526,078 common units, including units issued upon the underwriters' exercise of their option to purchase additional units, at $32.13 per unit, for net proceeds of approximately $201 million, after deducting underwriting discounts and offering expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under our revolving credit facility.

Sale of Operating Assets. In August 2012, we sold our Lake Charles natural gas processing plant, located in southwest Louisiana, and realized a gain on the sale of approximately $9.7 million. We acquired the Lake Charles plant as part of our Cantera Natural Gas acquisition in 2007, and had operated the plant only intermittently since its acquisition. The plant was our only Louisiana asset.

Declaration of Common Unit Distribution. On October 10, 2012, our Board of Directors declared a cash distribution of $0.575 per common unit for the third quarter of 2012. This distribution will be paid on November 8, 2012 to all common unitholders of record at the close of business on October 31, 2012, including holders of the additional 6,526,078 common units we issued in the public equity offering described above.

Trends and Uncertainties

This section, which describes recent changes in factors affecting our business, should be read in conjunction with "- How We Evaluate Our Operations" and "- How We Manage Our Operations" below and under Item 7 in our 2011 10-K. Many of the factors affecting our business are beyond our control and are difficult to predict.

Our gross margins and total distributable cash flow are affected by commodity prices and by the volumes of natural gas, NGLs and condensate that flow through our assets. Generally, commodity prices

affect the cash flow and profitability of our Texas and Oklahoma segments directly because some of our contracts in those segments have commodity-sensitive pricing terms. In addition, commodity prices affect all of our segments indirectly because they influence exploration and production activity, which underlies the demand for our services and the long-term growth and sustainability of our business.

Commodity prices are influenced by various factors that affect supply and demand. These factors include regional drilling activity and completion technology, natural gas, NGL and crude oil storage levels, competing supplies (such as crude oil or liquefied natural gas imports or exports), and the availability, proximity and capacity of downstream infrastructure and markets for natural gas, condensate and NGLs. Many of the factors affecting demand are in turn dependent on overall economic activity. For example, demand for ethane, a primary feedstock for petrochemical and manufacturing industries, varies depending on overall economic activity. Factors that can cause volatility in crude oil prices, such as international political and economic events, can also affect NGL and condensate prices because the two have historically been correlated. Also, demand for natural gas used in power generation varies depending on the relative prices for natural gas and coal.

Producers typically increase drilling and well completions when prices are sufficient to make these activities economic, and they may reduce or suspend these activities when they have become uneconomic. The point at which producer activity becomes economic depends on a combination of factors in addition to commodity prices. In many cases, producers of rich gas can benefit from NGL prices under their contracts; for these producers, strong NGL prices may offset the potential disincentive of weak natural gas prices. Strong crude oil prices may also support increased production of casinghead natural gas associated with crude oil production.

Other factors that affect a producer's ability and incentives to drill include the producer's operating costs and financial resources (both access to capital and cost of capital), the availability of labor and necessary equipment and services, the expected composition of wellhead production and the availability, proximity and capacity of downstream infrastructure, services and market outlets. Also, some producers rely on commodity price hedging to support drilling activity when prices are less favorable, and some may drill only to the extent necessary to maintain their leasehold interests or capital commitments, either of which may require drilling within a specified period of time.

The impact of changes in drilling and well completion activity on our throughput volumes may be gradual because of the time required to complete and connect new wells (or at times when drilling is declining, because of continuing production from existing wells). Delays can range from a few days, in areas with minimal time required to complete and connect wells, to as long as 18 months, if extensive dewatering or completion of downstream facilities is required.

Some of our producer contracts entitle us to deficiency fees, which help to mitigate the impact of lower drilling and production activity. However, we may be subject to increased credit risk over periods when a producer is making payments to us that are not supported by physical volumes. In addition, our cash flow will be affected because deficiency fees are not paid monthly; rather, they become payable after the end of a longer commitment period, such as annually. Furthermore, deficiency fees may be less than the amount we would receive if the producer had delivered physical volumes. In the case of deficiency fees payable to one of our unconsolidated affiliates, the payment is reflected in our cash flow only after the unconsolidated affiliate has made a cash distribution to us, which may occur in a subsequent quarter or year.

Third-Quarter 2012 Commodity Prices Overall. Natural gas prices improved in the third quarter of 2012 after reaching 10-year-lows in the second quarter. Gas prices have continued to improve in October and November. Average NYMEX crude oil prices decreased from the second quarter of 2012 to $92.22 per Bbl in the third quarter and declined to $89.57 per Bbl for October. Weighted-average NGL prices at Mont Belvieu and Conway for the third quarter of 2012 were $36.78 and $31.44 per Bbl, respectively, down from second quarter prices of $38.71 and $30.23 per Bbl. Third-quarter average ethane prices at Conway increased to $6.07 per Bbl, compared to $4.66 per Bbl for the second quarter, while Mont Belvieu ethane

prices declined, averaging $14.22 per Bbl compared to $16.96 per Bbl for the second quarter. The weighted-average spread between Mont Belvieu and Conway narrowed to $7.15 per Bbl over the third quarter, down from $11.34 per Bbl for the second quarter, due to a larger decline in Mont Belvieu prices. The spread narrowed to $4.03 per Bbl for October 2012.

Pricing Trends in Texas. The following graph and table summarize prices for natural gas and NGLs on the primary indices we use for Texas pricing and for crude oil on NYMEX.

                                              Quarterly Data for Texas
                 Q1 2011     Q2 2011     Q3 2011     Q4 2011         Q1 2012     Q2 2012     Q3 2012
Houston Ship
Channel
($/MMBtu)       $    4.06   $    4.29   $    4.23   $    3.49       $    2.65   $    2.17   $    2.84
Mont Belvieu
($/Bbl)         $   51.22   $   58.57   $   59.43   $   57.76       $   52.64   $   38.71   $   36.78
NYMEX crude
oil ($/Bbl)     $   94.10   $  102.56   $   89.76   $   94.06       $  102.93   $   93.49   $   92.22
100%-Owned
Service
throughput
(MMBtu/d)         654,996     665,040     765,744     844,469         944,033     924,465     897,601
Plant inlet
(MMBtu/d)         560,903     588,533     686,398     803,282         833,163     834,846     824,196
NGLs produced
(Bbls/d)           23,228      26,913      30,904      33,951          35,344      50,146      54,142
Segment gross
margin (in
thousands)      $  45,011   $  46,134   $  44,540   $  48,752       $  45,341   $  49,101   $  55,236
Joint
Ventures(1)
Pipeline
throughput
(MMBtu/d)          49,450      48,045      87,386     206,962         269,433     316,111     373,402
NGLs produced
(Bbls/d)(2)             -           -           -       6,735           9,912      10,169      12,526
Gross margin
(in
thousands)      $     422         720       6,706      23,347       $   9,815   $  26,964   $  25,945


--------------------------------------------------------------------------------
   º (1)

º (2)
º Net of NGLs produced at our Houston Central complex.

The first-of-the-month price for natural gas on the Houston Ship Channel index for October 2012 was $2.97 per MMBtu, and the spot price on October 31, 2012 was $3.39 per MMBtu. The weighted-average daily price for NGLs at Mont Belvieu for October 2012, based on our third-quarter 2012 product mix, was $40.78 per Bbl.

Pricing Trends in Oklahoma. The following graph and table summarize prices for natural gas and NGLs on the primary indices we use for Oklahoma pricing and for crude oil on the NYMEX.

                                             Quarterly Data for Oklahoma
                 Q1 2011     Q2 2011     Q3 2011     Q4 2011         Q1 2012     Q2 2012     Q3 2012
CenterPoint
East
($/MMBtu)       $    3.93   $    4.14   $    4.05   $    3.38       $    2.60   $    2.11   $    2.72
Conway
($/Bbl)         $   46.36   $   50.17   $   49.21   $   43.49       $   39.18   $   30.23   $   31.44
NYMEX crude
oil ($/Bbl)     $   94.10   $  102.56   $   89.76   $   94.06       $  102.93   $   93.49   $   92.22
100%-Owned
Service
throughput
(MMBtu/d)         269,550     283,870     288,440     307,346         318,285     324,915     313,414
Plant inlet
(MMBtu/d)         147,710     157,424     158,070     159,344         157,052     158,106     157,775
NGLs produced
(Bbls/d)           16,037      17,331      17,453      17,471          16,961      17,028      16,207
Segment gross
margin (in
thousands)      $  23,082   $  28,665   $  27,876   $  25,457       $  24,199   $  20,171   $  22,948
Joint
Ventures(1)
Plant inlet
(MMBtu/d)          11,182      11,730      11,970      10,287          10,017       7,352      10,354
NGLs produced
(Bbls/d)              393         432         429         358             363         249         375
Gross margin
(in
thousands)      $   1,421   $   1,364   $   1,331   $     980       $   1,003   $     491   $     848


--------------------------------------------------------------------------------
   º (1)

The first-of-the-month price for natural gas on the CenterPoint East index for October 2012 was $2.82 per MMBtu, and the spot price on October 31, 2012 was $3.38 per MMBtu. The weighted-average daily price for NGLs at Conway for October 2012, based on our third-quarter 2012 product mix, was $37.84 per Bbl.

Basis Trends. Basis risk continues to affect our hedges relating to Oklahoma NGL volumes, but we benefited from a narrowing of the Mont Belvieu-Conway basis spread in the third quarter of 2012. We use Mont Belvieu-priced hedge instruments for our Oklahoma NGL volumes because the forward market for Conway-based hedge instruments is limited.

The monthly average basis differential between Mont Belvieu and Conway reached $10.75 per Bbl in July 2012 before narrowing in August and September, averaging $4.82 per Bbl for September. The basis differential for October 2012 averaged $4.03 per Bbl. The average basis differential between Houston Ship Channel and CenterPoint East natural gas index prices for the third quarter of 2012 was $0.12/MMBtu.

The following graph summarizes the basis differential between Mont Belvieu and Conway prices.

Pricing Trends in the Rocky Mountains. The following graph and table summarize prices for natural gas on Colorado Interstate Gas, the primary index we use for the Rocky Mountains.

                     Rocky Mountains Natural Gas Prices(1)

                           [[Image Removed: GRAPHIC]]

--------------------------------------------------------------------------------
   º (1)
   º Natural gas prices are first-of-the-month index prices.

                                         Quarterly Data for Rocky Mountains
                 Q1 2011     Q2 2011     Q3 2011     Q4 2011         Q1 2012     Q2 2012     Q3 2012
Colorado
Interstate
Gas ($/MMBtu)   $    3.83   $    3.98   $    3.91   $    3.43       $    2.62   $    1.95   $    2.55
100%-Owned
Segment gross
margin (in
thousands)      $   1,042   $     771   $     432   $     396       $     358   $     187   $     624
Joint
Ventures(1)
Pipeline
throughput
(MMBtu/d)         581,051     533,329     670,543     630,843         787,366     747,009     694,961
Gross margin
(in
thousands)      $  21,524   $  19,407   $  20,488   $  24,332       $  21,462   $  18,741   $  18,035


--------------------------------------------------------------------------------
   º (1)

The first-of-the-month price for natural gas on the Colorado Interstate Gas index for October 2012 was $2.72 per MMBtu, and the spot price on October 31, 2012 was $3.48 per MMBtu.

Other Industry Trends. Volume growth from rich gas shale plays such as the Eagle Ford Shale continues to stress existing processing and liquids-handling infrastructure. NGL transportation and fractionation facilities remain subject to capacity constraints and older processing facilities are subject to reduced operating performance due to the very high NGL content of gas from these plays.

Transportation costs for crude oil, condensate and heavier NGL products in Texas remain higher due to limited pipeline infrastructure and available trucking capacity. In addition, we believe that limited fractionation capacity at Mont Belvieu and a lack of available NGL pipeline capacity in the Mid-Continent are contributing to the wide basis spread between Mont Belvieu and Conway. We anticipate that new pipeline infrastructure linking the Mid-Continent and Gulf Coast regions, which is scheduled to come online beginning in 2013, will help to moderate this basis spread.

Generally, processing and NGL capacity constraints result in higher processing fees and NGL transportation and fractionation costs for parties that do not have contractually fixed costs. Midstream companies experiencing capacity constraints or related outages may curtail volumes, experience reduced operating performance or, where possible, reject ethane, each of which can have an immediate impact on cash flow and operating results for both the midstream company and its producers and other customers. While these effects could limit the benefits producers receive from rich gas production and therefore affect the level of producer activity, we anticipate that the impact of processing and fractionation capacity constraints may begin to improve as new facilities come online in 2014.

º •
º Drilling. Drilling activity remained steady in the Eagle Ford Shale and north Barnett Shale Combo plays in Texas and the Hunton de-watering play in Oklahoma. Drilling activity in the leaner areas of the Woodford Shale behind our Mountains system in Oklahoma has been suspended due to low natural gas prices, while activity in the richer areas of the Woodford Shale continues. Drilling activity in the rich Mississippi Lime area in northern Oklahoma and southern Kansas has increased as producers further explore the play. In the Rocky Mountains and in other areas of Texas and Oklahoma, drilling activity has remained low.

º •
º Volumes. Our overall service throughput volumes for the third quarter of 2012 were down slightly compared to the second quarter of 2012 and increased 17% compared to the third quarter of 2011. Texas volumes decreased from the second to the third quarter of 2012 because we sold our Lake Charles processing plant in August. Excluding the impact of the sale of the Lake Charles plant, Texas volumes increased 8% compared to the second quarter of 2012 and 7% compared to the third quarter of 2011. The increase in third-quarter volumes compared to the same period in 2011 reflects (i) a 24% increase in volumes on our . . .