The following discussion and analysis should be read in conjunction with our "Description of the Business" in Item 1, Business, and our audited Consolidated Financial Statements and the Notes to Consolidated Financial Statements in this Annual Report.

RECENT DEVELOPMENTS

The following discussion highlights some of our planned activities, recent achievements and significant issues affecting us. Please refer to the "Financial Results and Operating Information" and "Liquidity and Capital Resources" sections of Management's Discussion and Analysis of Financial Condition and Results of Operation, our Consolidated Financial Statements and Notes to Consolidated Financial Statements for additional information.

Growth Projects - Crude-oil and natural gas producers continue to drill aggressively in crude-oil and NGL-rich areas, and related development activities continue to progress in many regions where we have operations. We expect continued development of the crude-oil and natural gas reserves in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale, Woodford Shale, Granite Wash and Mississippian Lime areas in the Mid-Continent region. In response to this increased production of crude oil, natural gas and NGLs, and higher demand for NGL products from the petrochemical industry, we are investing approximately $4.7 billion to $5.3 billion in new capital projects between 2011 and 2015 to meet the needs of natural gas producers and processors in the Bakken Shale, the Cana-Woodford Shale, Woodford Shale and the Granite Wash and Mississippian Lime areas. In addition, we are investing in NGL infrastructure projects in the Rocky Mountain, Mid-Continent and Gulf Coast regions. These assets will enhance our distribution of NGL products to meet the increasing petrochemical industry and NGL export demand. The execution of these capital investments aligns with our focus to grow fee-based earnings. Our acreage dedications and supply commitments from natural gas producers and processors in regions associated with our growth projects are expected to provide incremental and long-term fee-based earnings and cash flows.

See discussion of these growth projects in the "Financial Results and Operating Information" section in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

Bakken Crude Express Pipeline - In April 2012, we announced plans to build a 1,300-mile crude-oil pipeline, the Bakken Crude Express Pipeline, with the capacity to transport 200 MBbl/d. We held an open season process that provided potential shippers with the opportunity to execute long-term transportation contracts with us in exchange for priority transportation service. In November 2012, we elected not to proceed with plans to construct the Bakken Crude Express Pipeline due to insufficient long-term transportation commitments during the open season.

Cash Distributions - During 2012, we paid cash distributions totaling $2.59 per unit, an increase of approximately 11 percent over the $2.325 per unit paid during 2011. In January 2013, our general partner declared a cash distribution of $0.71 per unit ($2.84 per unit on an annualized basis) for the fourth quarter 2012, an increase of approximately 16 percent over the $0.61 declared in January 2012.

Debt Issuance - In September 2012, we completed an underwritten public offering of $1.3 billion of senior notes generating net proceeds of approximately $1.3 billion.

Equity Issuance - In March 2012, we completed an underwritten public offering of 8.0 million common units and also sold 8.0 million common units to ONEOK in a private placement, generating net proceeds of approximately $920 million. In conjunction with the issuances, ONEOK contributed approximately $19 million in order to maintain its 2-percent general partner interest in us.

We entered into an Equity Distribution Agreement (EDA) for the offer and sale from time to time of our common units up to an aggregate amount of $300 million. We are under no obligation to offer common units under the EDA. We intend to use the net proceeds from sales under the program for general partnership purposes.

FINANCIAL RESULTS AND OPERATING INFORMATION

Consolidated Operations

The following table sets forth certain selected consolidated financial results
for the periods indicated:
                                                                                Variances                     Variances
                                    Years Ended December 31,                  2012 vs. 2011                 2011 vs. 2010
Financial Results               2012           2011          2010          Increase (Decrease)           Increase (Decrease)
                                                                   (Millions of dollars)
Revenues                    $ 10,182.2     $ 11,322.6     $ 8,675.9     $    (1,140.4 )     (10 )%   $      2,646.7         31 %
Cost of sales and fuel         8,540.4        9,745.2       7,531.0          (1,204.8 )     (12 )%          2,214.2         29 %
Net margin                     1,641.8        1,577.4       1,144.9              64.4         4  %            432.5         38 %
Operating costs                  482.5          459.4         403.5              23.1         5  %             55.9         14 %
Depreciation and
amortization                     203.1          177.5         173.7              25.6        14  %              3.8          2 %
Gain (loss) on sale of
assets                             6.7           (1.0 )        18.6               7.7         *               (19.6 )        *
Operating income            $    962.9     $    939.5     $   586.3     $        23.4         2  %   $        353.2         60 %

Equity earnings from
investments                 $    123.0     $    127.2     $   101.9     $        (4.2 )      (3 )%   $         25.3         25 %
Allowance for equity
funds used during
construction                $     13.6     $      2.3     $     1.0     $        11.3         *      $          1.3          *
Interest expense            $   (206.0 )   $   (223.1 )   $  (204.3 )   $       (17.1 )      (8 )%   $         18.8          9 %
Capital expenditures        $  1,560.5     $  1,063.4     $   352.7     $       497.1        47  %   $        710.7          *

* Percentage change is greater than 100 percent.

2012 vs. 2011 - Revenues for 2012, compared with the prior year, decreased due to lower net realized natural gas and NGL product prices, offset partially by higher natural gas and NGL sales volumes from our completed capital projects. The increase in natural gas supply resulting from the development of nonconventional resource areas in North America and a warmer than normal winter have caused lower natural gas prices and narrower natural gas location and seasonal price differentials in the markets we serve. NGL prices, particularly ethane and propane, also decreased in 2012 due primarily to increased NGL production growth from the development of NGL-rich areas. Propane prices also were affected by a warmer than normal winter. During the second half of 2012, NGL location price differentials also narrowed due to the strong production growth, increased demand in the Mid-Continent region and increased capacity available on pipelines that connect the Mid-Continent and Gulf Coast market centers.

The price differential between the typically higher valued NGL products and the value of natural gas, particularly the price differential between ethane and natural gas, may influence the volume of NGLs recovered from natural gas processing plants. When economic conditions warrant, natural gas processors may elect not to recover the ethane component of the natural gas stream, also known as ethane rejection, and instead leave the ethane component in the natural gas stream sold at the tailgate of natural gas processing plants. Price differentials between ethane and natural gas resulted in periods of ethane rejection in the Mid-Continent and Rocky Mountain regions during 2012. Ethane rejection did not have a material impact on our financial results in 2012. We expect lower natural gas liquids volumes in our Natural Gas Liquids segment as a result of widespread and prolonged ethane rejection in 2013 that is expected to have a significant impact on our financial results. We do not expect prolonged ethane rejection to continue into 2014.

Operating income for the year, compared with the prior year, increased due to higher volumes from our completed projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments. The impact of the increase in volumes was offset partially by less favorable NGL price differentials and lower NGL transportation capacity available for optimization activities in our Natural Gas Liquids segment. Additionally, the increase was offset by higher compression and processing costs and lower realized natural gas and NGL product prices, particularly ethane and propane, compared with the prior year, in our Natural Gas Gathering and Processing segment.

Operating costs and depreciation and amortization increased for 2012, compared with the prior year, due primarily to the growth of our operations related to our completed capital projects.

Gain on sale of assets increased from a loss in 2011 due primarily to the sale of a natural gas pipeline lateral in our Natural Gas Pipelines segment.

Interest expense decreased for 2012, compared with the prior year, primarily as a result of higher interest capitalized associated with our investments in the growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments. The increase in interest expense resulting from the $1.3 billion issuance of senior notes in September 2012 was offset partially by the repayment of $350 million senior notes, which had a higher interest rate, in April 2012.

Capital expenditures and AFUDC increased for 2012, compared with the prior year, due primarily to the growth projects in our Natural Gas Liquids segment.

Additional information regarding our financial results and operating information is provided in the following discussion for each of our segments.

2011 vs. 2010 - NGL and condensate prices were higher while natural gas prices decreased during 2011, compared with 2010. These changes in commodity prices had a direct impact on our revenues and cost of sales and fuel.

Operating income increased approximately 60 percent during 2011, compared with 2010. The increase in operating income reflects higher net margin in our Natural Gas Liquids and Natural Gas Gathering and Processing segments.

Our Natural Gas Liquids segment benefited from more favorable NGL price differentials, as well as additional NGL fractionation and transportation capacity available for optimization activities between the Mid-Continent and Gulf-Coast markets. Our Natural Gas Liquids segment also realized higher exchange service margins due primarily to higher NGL gathering and fractionation volumes and contract renegotiations at higher fees with our customers. In addition, our Natural Gas Liquids segment realized higher isomerization margins resulting from wider price differentials between normal butane and iso-butane, and higher isomerization volumes.

Our Natural Gas Gathering and Processing segment benefited from significantly higher realized NGL and condensate prices, higher natural gas volumes processed and favorable changes in contract terms, offset partially by lower natural gas volumes gathered primarily in the Powder River Basin.

These increases were offset partially by the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company, which is now accounted for under the equity method in our Natural Gas Liquids segment following the sale of a 49-percent ownership interest in Overland Pass Pipeline Company. Additionally, our Natural Gas Pipelines segment realized lower transportation margins due to narrower natural gas price location differentials that caused a reduction in contracted capacity primarily on Midwestern Gas Transmission.

Gain (loss) on sale of assets decreased from 2010, which reflected a $16.3 million gain on the sale of a 49-percent interest of Overland Pass Pipeline Company.

Operating costs increased for 2011, compared with 2010, due primarily to higher labor and employee-related costs associated with incentive and benefit plans, and higher ad valorem taxes, as well as higher materials and outside services expenses associated primarily with scheduled maintenance at our natural gas liquids fractionation and storage facilities. Our employees participate in compensation and benefit plans administered by ONEOK, which include ONEOK's short-term incentive and share-based compensation plans. ONEOK's share price significantly increased in 2011, resulting in increased employee-related costs to us.

Equity earnings from investments increased for 2011, compared with 2010, due to the impact of the September 2010 deconsolidation of Overland Pass Pipeline Company in our Natural Gas Liquids segment and increased contracted capacity on Northern Border Pipeline in our Natural Gas Pipeline segment.

Capital expenditures increased for 2011, compared with 2010, due primarily to growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments and the purchase of leased equipment at our Bushton Plant.

Natural Gas Gathering and Processing

Growth Projects - Our Natural Gas Gathering and Processing segment is investing approximately $2.1 billion to $2.3 billion in growth projects in the Williston Basin and Cana-Woodford Shale areas that will enable us to meet the rapidly growing needs of crude oil and natural gas producers in those areas.

Williston Basin Processing Plants and related projects - Our projects in this basin include five 100 MMcf/d natural gas processing facilities: the Garden Creek, Garden Creek II and Garden Creek III plants located in eastern McKenzie County, North Dakota, and the Stateline I and II plants located in western Williams County, North Dakota. We have acreage dedications of approximately 3.1 million acres supporting these plants. In addition, we are expanding and upgrading our existing natural gas gathering and compression infrastructure and also adding new well connections associated with these plants. The Garden Creek plant was placed in service in December 2011 and together with the related infrastructure cost approximately $360 million, excluding AFUDC. We expect construction costs, excluding AFUDC, for the Garden Creek II plant will be $310 million to $345 million, and for the Garden Creek III plant will be approximately $325 million to $360 million. The Garden Creek II and Garden Creek III plants are expected to be in service during the third quarter 2014 and the first quarter 2015, respectively. Together, the Stateline I and II plants and related infrastructure projects are expected to cost approximately $560 million to $660 million, excluding AFUDC. The 100 MMcf/d Stateline I natural gas processing facility was placed into service in September 2012, and the 100 MMcf/d Stateline II natural gas processing facility is expected to be in service during the first quarter 2013.

We plan to invest $140 million to $160 million to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, North Dakota. The new system will gather and deliver natural gas from producers in the Williston Basin to both of our Stateline natural gas processing facilities in western Williams County, North Dakota. We have secured long-term supply commitments from producers for this new system, which are structured with POP and fee-based contractual components. This project is expected to be completed in the third quarter 2013.

Cana-Woodford Shale projects - We plan to invest approximately $340 million to $360 million to construct a new 200 MMcf/d natural gas processing facility, the Canadian Valley plant, and related infrastructure in the Cana-Woodford Shale in Canadian County, Oklahoma, in close proximity to our existing natural gas transportation and natural gas liquids gathering pipelines. The additional natural gas processing infrastructure is necessary to accommodate increased production of NGL-rich natural gas in the Cana-Woodford Shale where we have substantial acreage dedications from active producers. The new Canadian Valley plant is expected to cost approximately $190 million, excluding AFUDC, and is expected to be in service in the first quarter 2014. The related additional infrastructure is expected to cost approximately $160 million, excluding AFUDC, which we expect will increase our capacity to gather and process natural gas to approximately 390 MMcf/d in the Cana-Woodford Shale.

In both the Williston Basin and Cana-Woodford Shale project areas, nearly all of the new gas production is from horizontally drilled and completed wells. Horizontal wells drilled in the Williston Basin are justified primarily by crude-oil economics, which are currently very favorable. These wells tend to produce at higher initial volumes resulting generally in higher initial decline rates than conventional vertical wells; however, the decline rates flatten out over time. These wells are expected to have long productive lives. The routine growth capital needed to connect to new wells and expand our infrastructure is expected to increase compared with our historical levels of routine growth capital.

For a discussion of our capital expenditure financing, see "Capital Expenditures" in "Liquidity and Capital Resources."

Selected Financial Results - Our Natural Gas Gathering and Processing segment's 2012 operating results include the benefits from our completed growth projects. Operating results for 2012 reflect the completion of our Stateline I natural gas processing plant, which was placed in service in September 2012 and our Garden Creek natural gas processing plant, which was placed in service in December 2011. Placing these plants and their related infrastructure in service has resulted in increases in natural gas volumes gathered and processed in the Williston Basin. We expect drilling activities and development of the reserves to continue in the Bakken Shale and Three Forks formations in the Williston Basin and in the Cana-Woodford Shale and Granite Wash areas in Oklahoma and Texas. The following table sets forth certain selected financial results for our Natural Gas Gathering and Processing segment for the periods indicated:

                                                                           Variances                    Variances
                                  Years Ended December 31,               2012 vs. 2011                2011 vs. 2010
Financial Results              2012          2011        2010         Increase (Decrease)          Increase (Decrease)
                                                                (Millions of dollars)
NGL and condensate sales    $   934.2     $  917.5     $ 722.6     $      16.7           2  %   $   194.9             27 %
Residue gas sales               403.8        461.5       446.9           (57.7 )       (13 )%        14.6              3 %
Gathering, compression,
dehydration and
processing fees and other
revenue                         177.7        154.5       148.4            23.2          15  %         6.1              4 %
Cost of sales and fuel        1,060.5      1,130.6       966.5           (70.1 )        (6 )%       164.1             17 %
Net margin                      455.2        402.9       351.4            52.3          13  %        51.5             15 %
Operating costs                 164.0        153.7       136.8            10.3           7  %        16.9             12 %
Depreciation and
amortization                     83.0         68.3        60.7            14.7          22  %         7.6             13 %
Gain (loss) on sale of
assets                            2.2         (0.3 )      (0.3 )           2.5           *              -              - %
Operating income            $   210.4     $  180.6     $ 153.6     $      29.8          17  %   $    27.0             18 %

Equity earnings from
investments                 $    29.1     $   30.5     $  27.5     $      (1.4 )        (5 )%   $     3.0             11 %
Capital expenditures        $   566.1     $  623.7     $ 216.0     $     (57.6 )        (9 )%   $   407.7              *

* Percentage change is greater than 100 percent.

2012 vs. 2011 - Net margin increased primarily as a result of the following:
• an increase of $131.5 million due to volume growth in the Williston Basin from our new Garden Creek and Stateline I natural gas processing plants and increased drilling activity resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, and higher fees; offset partially by

• a decrease of $38.1 million due primarily to higher compression costs and less favorable contract terms associated with our volume growth in the Williston Basin;

• a decrease of $31.4 million due to lower net realized natural gas and NGL prices, particularly ethane and propane; and

• a decrease of $5.9 million due to lower natural gas volumes gathered in the Powder River Basin as a result of continued declines in coal-bed methane production.

Operating costs increased due primarily to the growth of our operations and reflect the following:
• an increase of $4.9 million in higher materials and supplies and outside service expenses;

• an increase of $2.1 million due to higher ad valorem taxes; and

• an increase of $1.5 million related to higher labor and employee-related costs.

Depreciation and amortization increased due to the completion of the Garden Creek and Stateline I natural gas processing plants in the Williston Basin and the completion of well connections and infrastructure projects supporting our volume growth in the Williston Basin.

Capital expenditures decreased due primarily to the timing of expenditures on our growth projects discussed above, offset partially by the completion of approximately 940 well connections in the Williston Basin and Mid-Continent areas in 2012, compared with approximately 600 well connections in 2011.

We expect capital expenditures to increase in 2013 as construction continues on our growth projects. See "Capital Expenditures" in "Liquidity and Capital Resources" for additional detail of our projected capital expenditures.

2011 vs. 2010 - Net margin increased primarily as a result of the following:
• an increase of $32.6 million due to higher net realized NGL and condensate prices;

• an increase of $19.4 million due to higher natural gas volumes processed in the Williston Basin and western Oklahoma resulting from increased drilling activity, offsetting reduced drilling activity in certain parts of Kansas and weather-related outages in the first quarter 2011;

• an increase of $8.8 million due to favorable changes in contract terms; and offset partially by

• a decrease of $8.2 million due to lower natural gas volumes gathered as a result of continued production declines and reduced drilling activity by producers in the Powder River Basin.

Operating costs increased due primarily to the following:
• an increase of $11.9 million of higher labor costs and employee-related costs associated with incentive and benefit plans; and

• an increase of $7.2 million in chemicals, material, supplies and outside services associated with the growth of our operations; offset partially by

• a reduction of $4.7 million in rental costs due to the termination of our Processing and Services Agreement with ONEOK when we acquired the previously leased equipment at the Bushton Plant in June 2011.

Depreciation and amortization increased due to both the completion of the connection of our western Oklahoma natural gas gathering system to our Maysville natural gas processing facility in central Oklahoma and the completion of well connections and infrastructure projects supporting our volume growth in the Williston Basin.

Capital expenditures increased due primarily to our growth projects discussed above and the completion of approximately 600 well connections in the Williston Basin and Mid-Continent areas in 2011, compared with approximately 300 well connections in 2010.

Selected Operating Information - The following tables set forth selected operating information for our Natural Gas Gathering and Processing segment for the periods indicated:

                                                              Years Ended December 31,
Operating Information (a)                                2012              2011           2010
Natural gas gathered (BBtu/d)                             1,119             1,030          1,067
Natural gas processed (BBtu/d) (b)                          866               713            674
NGL sales (MBbl/d)                                           61                48             44
Residue gas sales (BBtu/d)                                  397               317            286
Realized composite NGL net sales price
($/gallon) (c)                                     $       1.06        $     1.08     $     0.94
Realized condensate net sales price ($/Bbl) (c)    $      88.22        $    82.56     $    63.81
Realized residue gas net sales price ($/MMBtu)
(c)                                                $       3.87        $     5.47     $     5.58
Realized gross processing spread ($/MMBtu) (c)     $       8.05        $     8.17     $     6.41

Natural gas gathered volumes increased for 2012, compared with the prior year, due to increased drilling activity in the Williston Basin and western Oklahoma, completion of additional natural gas gathering lines and compression to support our new Garden Creek and Stateline I natural gas processing plants, offset partially by continued declines in coal-bed methane production in the Powder River Basin in Wyoming.

Natural gas gathered decreased for 2011, compared with 2010, due to continued production declines and reduced drilling activity, primarily in the Powder River Basin in Wyoming and certain parts of Kansas, and weather-related outages in the first quarter 2011, offset partially by increased drilling activity in the Williston Basin and western Oklahoma.

Natural gas processed and residue gas sales volumes increased for each of the comparable periods due to an increase in drilling activity in the Williston Basin and western Oklahoma, offsetting reduced drilling activity and natural production declines in Kansas.

Low natural gas prices and the relatively higher crude oil and NGL prices compared with natural gas on a heating-value basis have caused producers primarily to focus development efforts on crude oil and NGL-rich supply basins rather than areas with dry natural gas production, such as the Powder River Basin. The reduced development activities and natural production declines in the Powder River Basin have resulted in lower natural gas volumes available to be gathered. While the reserve potential in the Powder River Basin still exists, future drilling and development will be affected by commodity prices and

. . .