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OKS > SEC Filings for OKS > Form 10-K on 25-Feb-2014All Recent SEC Filings

Show all filings for ONEOK PARTNERS LP

Form 10-K for ONEOK PARTNERS LP


25-Feb-2014

Annual Report


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

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 for crude oil and NGL-rich natural gas in many regions where we have operations. We expect continued development of the crude oil and NGL-rich natural gas reserves in the Bakken Shale and Three Forks formations in the Williston Basin, the Niobrara Shale formation in the Powder River 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 $6.0 billion to $6.4 billion in new capital projects and acquisitions from 2010 through 2016, including approximately $1.2 billion in new projects and acquisitions announced in 2013, to meet the needs of natural gas producers and processors in these regions, as well as enhance our natural gas liquids fractionation, distribution and storage infrastructure in the Gulf Coast region. The execution of these capital investments aligns with our goal to grow fee-based earnings. Our acreage dedications and supply commitments from producers and natural gas processors in regions associated with our growth projects are expected to provide incremental cash flows and long-term fee-based earnings.

Sage Creek Acquisition - In September 2013, we completed the acquisition for $305 million of certain natural gas gathering and processing and natural gas liquids facilities in Converse and Campbell counties, Wyoming, in the NGL-rich Niobrara Shale formation of the Powder River Basin. These assets consist primarily of a 50 MMcf/d natural gas processing facility, the Sage Creek plant, and related natural gas gathering and natural gas liquids infrastructure. Included in the acquisition were supply contracts providing for long-term acreage dedications from producers in the area, which are structured with POP and fee-based contractual terms. We plan to invest approximately $135 million, excluding AFUDC, to upgrade and construct natural gas gathering and processing infrastructure and natural gas liquids gathering pipelines. The acquisition is complementary to our existing natural gas liquids assets and provides additional natural gas gathering and processing and natural gas liquids gathering capacity in a region where producers are actively drilling for crude oil and NGL-rich natural gas. For additional discussion, see Note B of the Notes to Consolidated Financial Statements.

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.

Cash Distributions - During 2013, we paid cash distributions totaling $2.87 per unit, an increase of approximately 11 percent over the $2.59 per unit paid during 2012. In January 2014, our general partner declared a cash distribution of $0.73 per unit


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($2.92 per unit on an annualized basis) for the fourth quarter 2013, an increase of approximately 3 percent over the $0.71 declared in January 2013.

Partnership Credit Agreement - Effective January 31, 2014, ONEOK Partners amended its Partnership Credit Agreement to increase the size of the facility to $1.7 billion from $1.2 billion and to extend the maturity to January 2019. Under the terms of the Partnership Credit Agreement, we may request an increase in the size of the facility to an aggregate of $2.4 billion by either commitments from new lenders or increased commitments from existing lenders. The facility will be available to provide liquidity for working capital, capital expenditures and for other general partnership purposes.

Debt Issuance - In September 2013, we completed an underwritten public offering of $1.25 billion of senior notes generating net proceeds of approximately $1.24 billion. We used the proceeds to pay down commercial paper and for general partnership purposes.

Equity Issuance - In August 2013, we completed an underwritten public offering of 11.5 million common units at a public offering price of $49.61 per common unit, generating net proceeds of approximately $553.3 million. In conjunction with this issuance, ONEOK Partners GP contributed approximately $11.6 million in order to maintain its 2 percent general partner interest in us. We used a portion of the proceeds from our August 2013 equity issuance to repay amounts outstanding under our commercial paper program, and the balance was used for general partnership purposes.

We have an "at-the-market" equity program for the offer and sale from time to time of our common units up to an aggregate amount of $300 million. The program allows us to offer and sell our common units through a sales agent at prices we deem appropriate. Sales of common units are made by means of ordinary brokers' transactions on the NYSE, in block transactions, or as otherwise agreed to between us and the sales agent. We are under no obligation to offer and sell common units under the program. During the year ended December 31, 2013, we sold approximately 681 thousand common units through this program that resulted in net proceeds, including ONEOK Partners GP's contribution to maintain its 2 percent general partner interest in us, of approximately $36.1 million. We used the proceeds for general partnership purposes.

As a result of these transactions, ONEOK's aggregate ownership interest in us decreased to 41.2 percent at December 31, 2013.

Transactions with Affiliates - We have transactions with our affiliate ONEOK Energy Services Company, a subsidiary of ONEOK. Our Natural Gas Gathering and Processing segment sells natural gas to ONEOK Energy Services Company, and our Natural Gas Pipelines segment provides transportation and storage services to ONEOK Energy Services Company. Additionally, our Natural Gas Gathering and Processing and Natural Gas Liquids segments purchase a portion of the natural gas used in their operations from ONEOK Energy Services Company. All of our Natural Gas Gathering and Processing segment's commodity derivative financial contracts are with ONEOK Energy Services Company, and it enters into similar commodity derivative financial contracts with third parties at our direction and on our behalf. In June 2013, ONEOK announced an accelerated wind down of ONEOK Energy Services Company operations that is expected to be substantially completed by April 2014. We expect to continue providing our customers midstream services, including marketing natural gas, NGLs and condensate as a service for third parties or other ONEOK affiliates. We expect to enter into future commodity derivative financial contracts with unaffiliated third parties or ONEOK affiliates after the wind down is completed.

On July 25, 2013, ONEOK announced that its Board of Directors unanimously authorized management to pursue a plan to separate its natural gas distribution business into a standalone publicly traded company, named ONE Gas, Inc. The separation was completed on January 31, 2014. ONEOK and its subsidiaries continue to own the entire general partner interest in us and limited partners units, which together at December 31, 2013, represented a 41.2 percent interest in us. We do not expect the ONEOK separation of ONE Gas to have a material effect on us.


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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,                  2013 vs. 2012                2012 vs. 2011
Financial Results               2013           2012           2011          Increase (Decrease)          Increase (Decrease)
                                                                   (Millions of dollars)
Revenues                    $ 11,869.3     $ 10,182.2     $ 11,322.6     $    1,687.1         17  %   $    (1,140.4 )     (10 )%
Cost of sales and fuel        10,222.2        8,540.4        9,745.2          1,681.8         20  %        (1,204.8 )     (12 )%
Net margin                     1,647.1        1,641.8        1,577.4              5.3          -  %            64.4         4  %
Operating costs                  521.6          482.5          459.4             39.1          8  %            23.1         5  %
Depreciation and
amortization                     236.7          203.1          177.5             33.6         17  %            25.6        14  %
Gain (loss) on sale of
assets                            11.9            6.7           (1.0 )            5.2         78  %             7.7         *
Operating income            $    900.7     $    962.9     $    939.5     $      (62.2 )       (6 )%   $        23.4         2  %

Equity earnings from
investments                 $    110.5     $    123.0     $    127.2     $      (12.5 )      (10 )%   $        (4.2 )      (3 )%
Interest expense            $   (236.7 )   $   (206.0 )   $   (223.1 )   $       30.7         15  %   $       (17.1 )      (8 )%
Capital expenditures        $  1,939.3     $  1,560.5     $  1,063.4     $      378.8         24  %   $       497.1        47  %
Cash paid for
acquisitions                $    394.9     $        -     $        -     $      394.9          *      $           -         -  %

* Percentage change is greater than 100 percent.

2013 vs. 2012 - Revenues and net margin for 2013, compared with 2012, increased due to higher natural gas and NGL volumes gathered, processed and sold from our completed capital projects, offset partially by lower net realized natural gas and NGL product prices and ethane rejection. The increase in natural gas supply resulting from the development of nonconventional resource areas in North America has contributed to lower NGL prices, narrower NGL location price differentials and narrower natural gas location and seasonal price differentials in the markets we serve, compared with 2012. However, in December 2013, the price of propane increased significantly, and the differential between the Conway, Kansas, and Mont Belvieu, Texas, markets for propane also widened in favor of Conway, Kansas, due to colder than normal weather and lower propane inventory levels. We expect these higher propane prices and wider location differentials to continue throughout the end of the 2014 winter heating season, which we expect will have a favorable impact on our first quarter 2014 financial results.

NGL location price differentials were significantly narrower between the Mid-Continent market center at Conway, Kansas, and the Gulf Coast market center at Mont Belvieu, Texas, for 2013, compared with 2012, due primarily to strong NGL production growth from the development of NGL-rich areas, exceeding the petrochemical industry's capacity to consume the increased supply resulting in higher ethane inventory levels at Mont Belvieu. Additionally, an unusually long maintenance outage season in the petrochemical industry during 2013 reduced ethane demand, which also contributed to the higher ethane inventory levels.

The differential between the composite price of NGL products and the price of natural gas, particularly the differential between ethane and natural gas, has influenced the volume of NGLs recovered from natural gas processing plants. The low ethane prices have resulted in ethane rejection at most of our natural gas processing plants and some of our customers' natural gas processing plants connected to our natural gas liquids system in the Mid-Continent and Rocky Mountain regions during 2013. We continue to expect that natural gas liquids volumes will be affected negatively in our Natural Gas Liquids segment as a result of ethane rejection. We expect ethane rejection will persist through much of 2016, after which new world-scale ethylene production capacity is expected to begin coming on line, although market conditions may result in periods where it is economical to recover the ethane component in the natural gas stream. Ethane rejection is expected to have a significant impact on our financial results during this period. However, our Natural Gas Liquids segment's integrated assets enable it to mitigate partially the impact of ethane rejection through minimum volume commitments and our ability to utilize the transportation capacity made available due to ethane rejection to capture additional NGL location price differentials in our optimization activities. In addition, new NGL supply commitments are expected to increase volumes in 2014 through 2016 to mitigate further the impact of ethane rejection on our Natural Gas Liquids segment.

Operating costs and depreciation and amortization increased for 2013, compared with 2012, due primarily to the growth of our operations related to the completed capital projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.


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Interest expense increased for 2013, compared with 2012, primarily as a result of higher interest costs incurred associated with a full year of interest costs on our issuance of $1.3 billion of senior notes in September 2012 and interest costs on our issuance of $1.25 billion of senior notes in September 2013. This was offset partially by higher capitalized interest associated with our investments in the growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments.

Capital expenditures increased for 2013, compared with 2012, due primarily to the growth projects in our Natural Gas Gathering and Processing and Natural Gas Liquids segments. In 2013, we also acquired a business in the Niobrara shale formation of the Power River Basin and purchased the remaining 30 percent interest in our Maysville natural gas processing facility.

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

2012 vs. 2011 - Revenues for 2012, compared with 2011, 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.

Operating income for 2012, compared with 2011, 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 2011, in our Natural Gas Gathering and Processing segment.

Operating costs and depreciation and amortization increased for 2012, compared with 2011, 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 2011, 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 2011, due primarily to the growth projects in our Natural Gas Liquids segment.

Natural Gas Gathering and Processing

Growth Projects - Our Natural Gas Gathering and Processing segment is investing approximately $3.0 billion to $3.3 billion from 2010 through 2016 in growth projects, including approximately $950 million in new projects and acquisitions announced in 2013, in NGL-rich areas in the Williston Basin, Cana-Woodford Shale and the Powder River Basin areas that we expect will enable us to meet the rapidly growing needs of crude oil and natural gas producers in those areas.


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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 McKenzie County, North Dakota, and the Stateline I and Stateline II plants located in Williams County, North Dakota. We also plan to construct a 200 MMcf/d processing facility, the Lonesome Creek plant, located in McKenzie County, North Dakota. We have current 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 and related infrastructure will be approximately $310 million to $345 million, and for the Garden Creek III plant and related infrastructure will be approximately $325 million to $360 million. The Garden Creek II and Garden Creek III plants are expected to be completed during the third quarter 2014 and the first quarter 2015, respectively. The Stateline I natural gas processing facility was placed into service in September 2012, and the Stateline II natural gas processing facility was placed into service in April 2013. Together with the related infrastructure, the Stateline I and Stateline II plants cost approximately $565 million, excluding AFUDC. We expect construction costs, excluding AFUDC, for the Lonesome Creek natural gas gathering plant and related infrastructure will be approximately $550 million to $680 million. The Lonesome Creek plant is expected to be completed in the fourth quarter 2015.

We are investing approximately $150 million, excluding AFUDC, to construct a 270-mile natural gas gathering system and related infrastructure in Divide County, North Dakota. The system gathers and transports natural gas from producers in the Bakken Shale and Three Forks formations in the Williston Basin to our Stateline natural gas processing facilities in Williams County, North Dakota. We have secured long-term acreage dedications from producers for this new system, which are structured with POP and fee-based contractual terms. Portions of the system were placed in service during the second quarter 2013, and the remaining system expansion is expected to be completed by the end of 2014.

Sage Creek acquisition and related projects - On September 30, 2013, we completed the acquisition of certain natural gas gathering and processing and natural gas liquids facilities in the NGL-rich Niobrara Shale area of the Powder River Basin, which includes a 50 MMcf/d natural gas processing facility, the Sage Creek plant, and related natural gas gathering infrastructure. Included in the acquisition were supply contracts providing for long-term acreage dedications from producers in the area, which are structured with POP and fee-based contractual terms. We plan to invest approximately $50 million, excluding AFUDC, through 2016 to upgrade and construct natural gas gathering and processing infrastructure.

Cana-Woodford Shale projects - We are investing 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 be completed in March 2014. The related additional infrastructure is expected to increase our capacity to gather and process natural gas to approximately 390 MMcf/d in the Cana-Woodford Shale.

In all of our growth project areas, nearly all of the new gas production is from horizontally drilled and completed wells. 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."


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Selected Financial Results - Our Natural Gas Gathering and Processing segment's 2013 operating results include the benefits from our completed growth projects. Operating results for 2013 reflect the completion of our Stateline II natural gas processing plant, which was placed in service in April 2013; and the Stateline I natural gas processing plant, which was placed in service in September 2012. 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 Williston Basin and Niobrara Shale in the Rocky Mountain region and 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,                2013 vs. 2012                2012 vs. 2011
Financial Results               2013          2012         2011         Increase (Decrease)          Increase (Decrease)
                                                                 (Millions of dollars)
NGL and condensate sales    $  1,208.7     $  934.2     $  917.5     $     274.5          29  %   $      16.7           2  %
Residue gas sales                620.5        403.8        461.5           216.7          54  %         (57.7 )       (13 )%
Gathering, compression,
dehydration and
processing fees and other
revenue                          222.3        177.7        154.5            44.6          25  %          23.2          15  %
Cost of sales and fuel         1,550.9      1,060.5      1,130.6           490.4          46  %         (70.1 )        (6 )%
Net margin                       500.6        455.2        402.9            45.4          10  %          52.3          13  %
Operating costs                  193.3        164.0        153.7            29.3          18  %          10.3           7  %
Depreciation and
amortization                     103.9         83.0         68.3            20.9          25  %          14.7          22  %
Gain (loss) on sale of
assets                             0.4          2.2         (0.3 )          (1.8 )       (82 )%           2.5           *
Operating income            $    203.8     $  210.4     $  180.6     $      (6.6 )        (3 )%   $      29.8          17  %

Equity earnings from
investments                 $     23.5     $   29.1     $   30.5     $      (5.6 )       (19 )%   $      (1.4 )        (5 )%
Capital expenditures        $    774.4     $  566.1     $  623.7     $     208.3          37  %   $     (57.6 )        (9 )%
Cash paid for
acquisitions                $    241.9     $      -     $      -     $     241.9           *      $         -           -  %

* Percentage change is greater than 100 percent.

2013 vs. 2012 - Net margin increased primarily as a result of the following:
an increase of $100.1 million due primarily to volume growth in the Williston Basin from our Stateline I and Stateline II natural gas processing plants, and increased well connections resulting in higher natural gas volumes gathered, compressed, processed, transported and sold, higher NGL volumes sold and higher fees; and

an increase of $6.4 million due to a contract settlement in 2013; offset partially by

a decrease of $41.7 million due primarily to lower net realized NGL prices;

a decrease of $13.4 million due primarily to changes in contract mix and terms associated with our volume growth; and

a decrease of $3.5 million due to lower dry natural gas volumes gathered as a result of continued declines in coal-bed methane production in the Powder River Basin.

Operating costs increased due primarily to the growth of our operations and reflect the following:
an increase of $16.8 million in higher materials and supplies, and outside service expenses;

an increase of $10.3 million in employee-related costs due to higher labor and employee benefit costs, offset partially by lower incentive compensation costs; and

an increase of $2.2 million due to higher ad valorem taxes.

. . .

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