10-K 1 d881200d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number: 1-14998

 

 

ATLAS PIPELINE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

 

 

 

DELAWARE   23-3011077
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)

Park Place Corporate Center One

1000 Commerce Drive, 4th Floor

Pittsburgh, Pennsylvania

  15275-1011
(Address of principal executive office)   (Zip code)

Registrant’s telephone number, including area code: (877) 950-7473

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

Common Units representing Limited
Partnership Interests
  New York Stock Exchange
8.25% Class E Cumulative Redeemable
Perpetual Preferred Units
  New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of class)

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “small reporting company” in Rule 12b-2 of the Exchange Act (Check one):

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of the equity securities held by non-affiliates of the registrant, based upon the closing price of $34.40 per common limited partner unit on June 30, 2014, was approximately $2,579.8 million.

The number of common units of the registrant outstanding on February 25, 2015 was 99,980,357.

DOCUMENTS INCORPORATED BY REFERENCE: None

 

 

 


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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

INDEX TO ANNUAL REPORT

ON FORM 10-K

 

         Page  

Forward Looking Statements

     1   

Glossary of Terms

     2   

PART I.

    

Item 1.

 

Business

     3   

Item 1A.

 

Risk Factors

     33   

Item 1B.

 

Unresolved Staff Comments

     53   

Item 2.

 

Properties

     53   

Item 3.

 

Legal Proceedings

     54   

Item 4.

 

Mine Safety Disclosure

     56   

PART II.

    

Item 5.

 

Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

     57   

Item 6.

 

Selected Financial Data

     58   

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     66   

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

     99   

Item 8.

 

Financial Statements and Supplementary Data

     100   

Item 9.

 

Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

     161   

Item 9A.

 

Controls and Procedures

     161   

Item 9B.

 

Other Information

     163   

PART III.

    

Item 10.

 

Directors, Executive Officers and Corporate Governance

     163   

Item 11.

 

Executive Compensation

     171   

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

     197   

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

     200   

Item 14.

 

Principal Accountant Fees and Services

     201   

PART IV.

    

Item 15.

 

Exhibits and Financial Statement Schedules

     202   

SIGNATURES

     206   


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FORWARD-LOOKING STATEMENTS

The matters discussed within this report include forward-looking statements. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,” “may,” “might,” “plan,” “potential,” “predict,” “should,” or “will,” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

 

    the demand for natural gas, NGLs and condensate;

 

    the price volatility of natural gas, NGLs and condensate;

 

    our ability to connect new wells to our gathering systems;

 

    our ability to integrate operations and personnel from acquired businesses;

 

    adverse effects of governmental and environmental regulation;

 

    limitations on our access to capital or on the market for our common units; and

 

    the strength and financial resources of our competitors.

Other factors that could cause actual results to differ from those implied by the forward-looking statements in this report are more fully described under Item 1A, “Risk Factors” in this report. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included in this report are made only as of the date hereof. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments.

 

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Glossary of Terms

Definitions of terms and acronyms generally used in the energy industry and in this report are as follows:

 

BPD Barrels per day. Barrel—measurement for a standard US barrel is 42 gallons. Crude oil and condensate are generally reported in barrels.
BTU British thermal unit, a basic measure of heat energy
Condensate Liquid hydrocarbons present in casing head gas that condense within the gathering system and are removed prior to delivery to the gas plant. This product is generally sold on terms more closely tied to crude oil pricing.
EBITDA Net income (loss) before net interest expense, income taxes, and depreciation and amortization. EBITDA is a non-GAAP measure.
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Fractionation The process used to separate an NGL stream into its individual components.
GAAP Generally Accepted Accounting Principles
G.P. general partner or general partnership
GPM Gallons per minute
Keep-Whole A contract with a natural gas producer whereby the plant operator pays for or returns gas having an equivalent BTU content to the gas received at the well-head.
L.P. Limited Partner or Limited Partnership
MCF Thousand cubic feet
MCFD Thousand cubic feet per day
MMBTU Million British thermal units
MMCFD Million cubic feet per day
NGL(s) Natural Gas Liquid(s), primarily ethane, propane, normal butane, isobutane and natural gasoline
Percentage of Proceeds (“POP”) A contract with a natural gas producer whereby the plant operator retains a negotiated percentage of the sale proceeds.
Residue gas The portion of natural gas remaining after natural gas is processed for removal of NGLs and impurities.
SEC Securities and Exchange Commission

 

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PART I

 

ITEM 1. BUSINESS

Partnership Structure

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL.” Our Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) are listed on the New York Stock Exchange under the symbol “APLPE.”

Our general partner, Atlas Pipeline Partners GP, LLC (“Atlas Pipeline GP” or the “General Partner”), manages our operations and activities through its ownership of our general partner interest. Atlas Pipeline GP is a wholly-owned subsidiary of Atlas Energy, L.P. (“ATLS”), a publicly traded Delaware limited partnership (NYSE: ATLS), which owned 5.5% of the limited partner interests in us at December 31, 2014, as well as a 2.0% general partner interest.

The following chart displays our organizational structure as of December 31, 2014:

 

LOGO

 

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General

We are a leading provider of natural gas gathering, processing and treating services primarily in the Anadarko, Ardmore, Arkoma and Permian Basins located in the southwestern and mid-continent regions of the United States and in the Eagle Ford Shale play in southern Texas.

Our operations are all located in or near areas of abundant and long-lived natural gas production, including, within Oklahoma, the Golden Trend, Mississippian Limestone and Hugoton Field in the Anadarko Basin; the South Central Oklahoma Oil Province (“SCOOP”) play in the Ardmore Basin; the Woodford Shale play in the Arkoma Basin; and within Texas, the Spraberry and Wolfberry Trends, which are oil plays with associated natural gas in the Permian Basin; the Eagle Ford Shale; and the Barnett Shale. Our gathering systems are connected to receipt points consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells. We believe we have significant scale in each of our primary service areas. We provide gathering, processing and treating services to the wells connected to our systems primarily under long-term contracts. As a result of the location and capacity of our gathering, processing and treating assets, we believe we are strategically positioned to capitalize on the drilling activity in our service areas.

We conduct our business in the midstream segment of the natural gas industry through two reportable segments: Oklahoma Gathering and Processing (“Oklahoma”) and Texas Gathering and Processing (“Texas”).

As a result of the May 2014 sale of two former subsidiaries that owned an interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) (see “–Recent Developments”), we realigned the management of our business from our previously reportable segments of “Gathering and Processing” and “Transportation and Treating” into the two new reportable segments.

The Oklahoma segment consists of our SouthOK and WestOK operations, which are comprised of natural gas gathering, processing and treating assets servicing drilling activity in the Anadarko, Ardmore and Arkoma Basins. These operations were formerly included within the previous Gathering and Processing segment. Revenues are primarily derived from the sale of residue gas and NGLs and the gathering, processing and treating of natural gas within the state of Oklahoma.

The Texas segment consists of (1) our SouthTX and WestTX operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Permian Basin and the Eagle Ford Shale play in southern Texas; and (2) our natural gas gathering assets located in the Barnett Shale play in Texas. These assets were formerly included within the previous Gathering and Processing segment. Revenues are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas within the state of Texas.

The previous Transportation and Treating segment, which consisted of (1) our gas treating operations, which own contract gas treating facilities located in various shale plays; and (2) the former subsidiaries’ interest in WTLPG, which was sold in May 2014 (see “–Recent Developments”). This segment has been eliminated and the financial information is now included within Corporate and Other. On February 27, 2015, we agreed to transfer 100% of our interest in natural gas gathering assets located in the Appalachian Basin in Tennessee to our affiliate, Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP”) (see “–Recent Developments”). Our Tennessee gathering assets were formerly included in the previous Gathering and Processing Segment, but are now included within Corporate and Other.

 

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Recent Developments

Targa Resources Partners LP Merger

On October 13, 2014, ATLS, our General Partner and we entered into a definitive merger agreement with Targa Resources Corp. (“TRC”), a publicly traded Delaware limited partnership (NYSE: TRGP), Targa Resources Partners, LP (“TRP”), a publicly traded Delaware limited partnership (NYSE: NGLS) and certain other parties (the “Merger Agreement”), pursuant to which TRP agreed to acquire us through a merger of a newly-formed, wholly-owned subsidiary of TRP with and into us (the “Merger”). Upon completion of the Merger, holders of our common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each of our common units. Pursuant to the terms and conditions of the Merger Agreement, we have exercised our right under the certificate of designation of the Class D convertible preferred units (“Class D Preferred Units”) to convert all outstanding Class D Preferred Units into common units, which occurred on January 22, 2015 (see –Financing). Additionally, on January 27, 2015, we announced our intention to exercise our right under the certificate of designation of the Class E Preferred Units to redeem the Class E Preferred Units. TRP has agreed to deposit the funds for redemption with the paying agent (see –Financing).

Concurrently with the Merger Agreement, ATLS announced that it entered into a definitive merger agreement with TRC (the “ATLS Merger Agreement”), pursuant to which TRC agreed to acquire ATLS through a merger of a newly formed wholly-owned subsidiary of TRC with and into ATLS (the “ATLS Merger”). Upon completion of the ATLS Merger, holders of ATLS common units will have the right to receive (i) 0.1809 TRC shares of common stock, par value $0.001 per share, and (ii) $9.12 in cash, without interest, for each ATLS common unit.

Concurrently with the Merger Agreement and the ATLS Merger Agreement, ATLS agreed to (i) transfer its assets and liabilities, other than those related to us, to Atlas Energy Group, LLC (“Atlas Energy Group”), which is currently a subsidiary of ATLS and (ii) immediately prior to the ATLS Merger, effect a pro rata distribution to the ATLS unitholders of common units of Atlas Energy Group representing a 100% interest in Atlas Energy Group (the “Spin-Off”).

Following the announcement on October 13, 2014 of the Merger, we, our General Partner, ATLS, TRC, TRP, Targa Resources GP LLC (“TRP GP”), Trident MLP Merger Sub LLC (“MLP Merger Sub”) and the members of our General Partner’s board of directors were named as defendants in five putative unitholder class action lawsuits challenging the Merger, one of which has subsequently been voluntarily dismissed. In addition, ATLS, Atlas Energy GP LLC (“ATLS GP”), TRC, Trident GP Merger Sub LLC (“GP Merger Sub”) and members of ATLS GP’s board of directors were named as defendants in two putative unitholder class action lawsuits challenging the ATLS Merger, one of which has subsequently been voluntarily dismissed. The lawsuits filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for our unitholders and ATLS unitholders, respectively, in the Merger and ATLS Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses and costs.

ATLS has also been named as a defendant in a putative class action and derivative lawsuit brought on January 28, 2015 and amended on February 23, 2015, by a shareholder of TRC against TRC and its directors. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, approving the ATLS Merger and failing to disclose purportedly material information concerning the ATLS Merger. The lawsuit seeks, among other things, injunctive relief, compensatory and rescissory damages, attorney’s fees, interest and costs.

All of the above referenced lawsuits, except for the January 2015 lawsuit and the two lawsuits that have been voluntarily dismissed, were settled, subject to court approval, pursuant to memoranda of understanding executed in February 2015, which are conditioned upon, among other things, the execution of an appropriate stipulations of settlement. The stipulations of settlement will be subject to customary conditions, including, among other things, judicial approval of the proposed settlements contemplated by the memoranda of understanding. There can be no assurance that the parties will ultimately enter into stipulations of settlement, that the court will approve the settlements, that the settlements will not be terminated according to their terms or that some unitholders will not opt-out of the settlements.

 

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At this time, we cannot reasonably estimate the range of possible loss as a result of the lawsuits. See “Item 3: Legal Proceedings” for more information regarding these lawsuits.

The closing of the Merger is subject to approval by holders of a majority of our common units and other closing conditions, including the closing of the ATLS Merger and the Spin-Off. On February 20, 2015, we held a special meeting, where holders of a majority of our common units approved the Merger. In addition, at special meetings held on the same day: (i) a majority of the holders of ATLS common units approved the ATLS Merger and (ii) a majority of the holders of TRC common stock approved the issuance of TRC shares in connection with the Merger. Completion of each of the ATLS Merger and the Spin-Off are also conditioned on the parties standing ready to complete the Merger. We expect the Merger to close on February 27, 2015.

On February 27, 2015, we agreed to transfer 100% of our interest in the Tennessee gas gathering assets to our affiliate, ARP, for $1.0 million plus working capital adjustments, concurrent with the closing of the Merger on February 27, 2015.

West Texas LPG Sale

On May 14, 2014, we completed the sale of two subsidiaries, which held an aggregate 20% interest in WTLPG, to a subsidiary of Martin Midstream Partners L.P. (NYSE: MMLP). We received $131.0 million in proceeds, net of selling costs and working capital adjustments, which were used to pay down our revolving credit facility.

Growth Projects

In December 2014, we completed the connection between the Velma and Arkoma systems within the SouthOK system. The connection accommodates the increased demand for processing capacity behind the Velma system, where the emerging SCOOP play has attracted significant producer interest. The connection between Velma and Arkoma offers us more operational flexibility and helps us better utilize our processing capacity across the SouthOK system.

On September 15, 2014, we placed in service a new 200 MMCFD cryogenic processing plant, known as the Edward plant, in our WestTX system in the Permian Basin of West Texas, increasing the WestTX system capacity to 655 MMCFD.

On June 25, 2014, we placed in service a new 200 MMCFD cryogenic processing plant, known as the Silver Oak II plant, in our SouthTX system in the Eagle Ford Shale play of southern Texas, increasing the SouthTX system capacity to 400 MMCFD.

On May 1, 2014, we placed in service a new 120 MMCFD cryogenic processing plant, known as the Stonewall plant, in our SouthOK system in the Arkoma Basin of Oklahoma, increasing the SouthOK system capacity to 500 MMCFD. A planned expansion of the Stonewall plant to raise the processing capacity to 200 MMCFD is partially completed and capacity was increased to 160 MMCFD as of December 31, 2014. The full expansion is anticipated to be completed in the first quarter of 2015.

On April 24, 2014, we announced plans to expand the gathering footprint of our WestTX system. This project includes the laying of a high pressure gathering line into Martin and Andrews counties of Texas, as well as adding incremental compression and processing, including installation of a new, 200 MMCFD cryogenic processing plant, known as the Buffalo plant, which is expected to be completed during 2016. This facility will increase the processing capacity in the Permian Basin to 855 MMCFD.

 

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Financing

On January 27, 2015, we delivered notice of our intention to redeem all outstanding shares of our Class E Preferred Units. The redemption of the Class E Preferred Units will occur immediately prior to the close of the Merger. We expect the Merger to close on February 27, 2015 and, accordingly, the redemption would also be on February 27, 2015. The Class E Preferred Units will be redeemed at a redemption price of $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions on the Class E Preferred Units as of the redemption date. TRP has agreed to deposit the funds for such redemption with our paying agent.

On January 22, 2015, we exercised our right under the certificate of designation of the Class D Preferred Units (“Class D Certificate of Designation”) to convert all outstanding Class D Preferred Units and unpaid distributions into common limited partner units, based upon the Execution Date Unit Price of $29.75 per unit, as defined by the Class D Certificate of Designation. As a result of the conversion, 15,389,575 common limited partner units were issued (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Class D Preferred Units”).

On January 15, 2015, TRP announced cash tender offers to redeem any and all of our outstanding $500.0 million aggregate principal amount of our 6.625% unsecured senior notes due October 1, 2020 (“6.625% Senior Notes”); $400.0 million aggregate principal amount of our 4.75% unsecured senior notes due November 15, 2021 (“4.75% Senior Notes”); and $650.0 million aggregate principal amount of our 5.875% unsecured senior notes due August 1, 2023 (“5.875% Senior Notes”). TRP made the cash tender offers in connection with, and conditioned upon, the consummation of the Merger. The Merger, however, is not conditioned on the consummation of the tender offers. On February 2, 2015, TRP announced as of January 29, 2015, it had received tenders pursuant to its previously announced cash tender offers on January 15, 2015 from holders representing:

 

    less than a majority of the total outstanding $500.0 million of our 6.625% Senior Notes;

 

    approximately 98.3% of the total outstanding $400.0 million of our 4.75% Senior Notes; and

 

    approximately 91.0% of the total outstanding $650.0 million of our 5.875% Senior Notes.

Also on February 2, 2015, TRP announced a change of control cash tender offer for any and all of the outstanding $500.0 million of our 6.625% Senior Notes. TRP made the change of control cash tender offer in connection with, and conditioned upon, the consummation of the Merger. The Merger, however, is not conditioned on the consummation of the change in control cash tender offer. The change in control cash tender offer was made independently of TRP’s January 15, 2015 cash tender offers.

On August 28, 2014, we entered into a Second Amended and Restated Credit Agreement (the “Revised Credit Agreement”) which, among other changes:

 

    extended the maturity date to August 28, 2019;

 

    increased the revolving credit commitment from $600 million to $800 million and the incremental revolving credit amount from $200 million to $250 million;

 

    reduced by 0.25% the applicable margin used to determine interest rates for LIBOR Rate Loans, as defined in the Revised Credit Agreement, and for Base Rate Loans, as defined in the Revised Credit Agreement, depending on the Consolidated Funded Debt Ratio, as defined in the Revised Credit Agreement;

 

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    allows us to request incremental term loans, provided the sum of any revolving credit commitments and incremental term loans may not exceed $1.05 billion; and

 

    changed the per annum interest rate on borrowings to (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%, or (ii) the LIBOR rate for the applicable period, in each case plus the applicable margin.

On May 12, 2014, we entered into an Equity Distribution Agreement (the “2014 EDA”) with Citigroup Global Markets Inc., Wells Fargo Securities, LLC and MLV & Co. LLC, as sales agents. Pursuant to the 2014 EDA, we may offer and sell from time to time through our sales agents, common units having an aggregate value of up to $250.0 million. Sales are at market prices prevailing at the time of the sale. However, we are currently restricted from selling common units by the Merger Agreement. During the year ended December 31, 2014, we issued 3,558,005 common units under the 2014 EDA for proceeds of $121.6 million, net of $1.2 million in commissions paid to the sales agents.

On March 17, 2014, we issued 5,060,000 of our Class E Preferred Units to the public at an offering price of $25.00 per Class E Preferred Unit. We received $122.3 million in net proceeds. The proceeds were used to pay down our revolving credit facility.

Business Strategy

The primary business objective of our management team is to provide stable long-term cash distributions to our unitholders. Our business strategies focus on creating value for our unitholders by providing efficient operations; focusing on prudent growth opportunities via organic growth projects and external acquisitions; and maintaining a commodity risk management program in an attempt to manage our commodity price exposure. We intend to accomplish our primary business objective by executing on the following:

 

    Expanding operations through organic growth projects and increasing the profitability of our existing assets. In many cases, we can expand our gathering pipelines and processing plants and, to the extent we have excess capacity, we can connect and process new supplies of natural gas with minimal additional capital requirements, also increasing plant efficiency and economics. We plan to access new supplies of natural gas by providing excellent service to our existing customers; aggressively marketing our services to new customers; and prudently expanding our existing infrastructure to ensure our services can meet the needs of potential customers. Our recent construction of the Stonewall, Silver Oak II, and Edward plants, our completion of the connection between the Arkoma and Velma systems and our announced construction of the Buffalo plant are examples of executing this strategy.

 

    Pursuing strategic acquisitions. We continue to pursue strategic acquisitions that leverage our existing asset base, employees and customer relationships. In the past, we have pursued opportunities in certain regions outside of our current areas of operation and will continue to do so when these options make sense economically and strategically.

 

   

Reducing the sensitivity of our cash flows through prudent economic risk management and contract arrangements. We attempt to structure our contracts in a manner that allows us to achieve our target rates of return while reducing our exposure to commodity price

 

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movements. We actively review our contract mix and seek to optimize a balance of cash flow stability with attractive economic returns. Our commodity price risk management activities are designed to reduce the effect of commodity price volatility related to future sales of natural gas, NGLs and condensate, while allowing us to meet our debt service requirements; fund our maintenance capital program; and meet our distribution objectives.

 

    Maintaining our financial flexibility. We intend to maintain a capital structure in which we do not significantly exceed equal amounts of debt and equity on a long-term basis while not jeopardizing our ability to achieve our other business strategies as listed above. We seek to maintain a minimum total liquidity of at least $100.0 million; a ratio of debt to capital of not more than 50%; and a ratio of long-term debt to trailing 12-month EBITDA, as defined in our Revised Credit Agreement, of less than 4x. We believe our revolving credit facility, our ability to issue additional long-term debt or limited partner units and our relationships with our partners provide us with the ability to achieve this strategy. We will also consider alternative financing, joint venture arrangements and other means that allow us to achieve our business strategies while continuing to maintain an acceptable capital structure.

Contracts and Customer Relationships

Our principal revenue is generated from fees for the gathering, processing and treating of natural gas and the sale of natural gas, NGLs and condensate. For the year ended December 31, 2014, ONEOK Hydrocarbon, L.P. (“ONEOK”); DCP NGL Services, LLC, a subsidiary of DCP Midstream, LLC (“DCP”); and BP Energy Company accounted for approximately 21%, 13% and 11%, respectively, of our third-party revenues within the Oklahoma segment and DCP and Tenaska Marketing Ventures, Inc. accounted for approximately 47% and 16%, respectively, of our third-party revenues within the Texas segment, with no other single customer accounting for more than 10% for this period.

Natural Gas Supply

We have natural gas purchase, gathering and processing agreements with certain producers. These agreements provide for the purchase or gathering of natural gas, primarily under Fee-Based and POP arrangements (see “Item 8: Financial Statements and Supplementary Data – Note 2 – Summary of Significant Accounting Policies”). Many of the agreements provide for gathering, processing, compression, treating and/or low volume fees. Producers generally provide, in-kind, their proportionate share of compressor and plant fuel required to gather the natural gas and to operate our processing plants. In addition, the producers generally bear their proportionate share of gathering system line loss and natural gas plant “shrinkage” for the gas consumed in the production of NGLs.

We have long-term, service-driven relationships with our producing customers, who comprise some of the largest producers in our areas. Several of our top producers have contracts with primary terms running into 2020 and beyond. At the end of the primary terms, most of the contracts with producers on our gathering systems have evergreen term extensions.

In our Oklahoma segment on our WestOK system, we have a contract with SandRidge with a term currently extending through 2017. As part of the agreement, SandRidge has agreed to dedicate the majority of its developed acreage covering the Mississippian Lime formation.

In our Texas segment on our SouthTX system, our primary producers, Statoil Natural Gas LLC (“Statoil”) and Talisman Energy USA Inc. (“Talisman”) both have fixed-fee long term agreements with volume commitments extending into 2022. Also in our Texas segment on our WestTX system, we have a gas sales and purchase agreement with Pioneer Natural Resources Company (NYSE: PXD) (“Pioneer”)

 

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with a term extending into 2032. The gas sales and purchase agreement requires all Pioneer wells within an “area of mutual interest” be dedicated to that system’s gathering and processing operations in return for specified natural gas processing rates. Through this agreement, we anticipate we will continue to provide gathering and processing for the majority of Pioneer’s wells in the Spraberry and Wolfberry Trends in the Permian Basin.

Natural Gas and NGL Marketing

We typically sell natural gas to purchasers downstream of our processing plants priced at various first-of-month indices as published in Inside FERC. Additionally we sell swing gas, which is natural gas sold on a daily basis at various Platt’s Gas Daily midpoint prices.

All NGL agreements are priced at the average daily Oil Price Information Service (or OPIS) price for the month for the selected market, subject to reduction by a “Base Differential” for transportation and fractionation fees and, if applicable, quality adjustment fees.

The Midstream Natural Gas Gathering and Processing Industry

The midstream natural gas gathering and processing industry is characterized by regional competition based on the proximity of gathering systems and processing plants to producing natural gas wells.

The natural gas gathering process begins with the drilling of wells into natural gas or oil bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of pipelines that collect natural gas from points near producing wells and transport gas and other associated products to plants for processing and treating and to larger pipelines for further transportation to end-user markets. Gathering systems are operated at design pressures via pipe size and compression that help maximize the total throughput from all connected wells.

 

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While natural gas produced in some areas does not require treating or processing, natural gas produced in other areas is not suitable for long-haul pipeline transportation or commercial use and must be compressed; gathered via pipeline to a central processing facility; potentially treated; and then processed to remove certain hydrocarbon components, such as NGLs and other contaminants, that would interfere with pipeline transportation or the end use of the natural gas. Natural gas treating and processing plants generally treat (remove carbon dioxide and hydrogen sulfide) and extract the NGLs, enabling the treated, “dry” gas, commonly referred to as residue gas, to meet pipeline specifications for long-haul transport to end users. After being separated from natural gas at the processing plant, the mixed NGL stream, commonly referred to as “y-grade” or “raw mix,” is typically transported in pipelines to a centralized facility for fractionation into discrete NGL purity products: ethane, propane, normal butane, isobutane, and natural gasoline.

Our Oklahoma Operations

Our Oklahoma operations own, operate and/or have interests in 10 natural gas processing facilities, one treating facility and approximately 7,600 miles of intrastate natural gas gathering systems located in Oklahoma and Kansas. Our Oklahoma gathering systems, processing plants and treating assets service long-lived natural gas regions, including the Anadarko, Ardmore and Arkoma Basins. Our Oklahoma systems have receipt points consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells from which we gather natural gas from oil and natural gas wells; process the raw natural gas into residue gas by extracting NGLs and removing impurities; and transport natural gas to interstate and public utility pipelines for delivery to customers.

 

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Gathering Systems

SouthOK. SouthOK consists of the Velma and Arkoma systems, which were connected during 2014 through the installation of approximately 55 miles of gathering pipeline between the systems (see “–Recent Developments”).

The SouthOK gathering system is located in the Ardmore and Anadarko Basins and includes the Golden Trend, SCOOP, and Woodford Shale areas of southern Oklahoma. The gathering system has approximately 1,500 miles of active pipelines. The primary natural gas suppliers on the SouthOK gathering system include Atoka Midstream, LLC; DCP Midstream, L.P.; Marathon Oil Company (“Marathon”); MarkWest Oklahoma Gas Company, LLC (“MarkWest”); Merit Management Partners; XTO Energy, Inc. (“XTO”); and Vanguard Natural Resources, LLC.

 

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WestOK. The WestOK gathering system is located in north central Oklahoma and southern Kansas’ Anadarko Basin. The gathering system has approximately 6,100 miles of active natural gas gathering pipelines. The primary natural gas suppliers on the WestOK gathering system include Chesapeake Energy Corporation and SandRidge Exploration and Production, LLC (“Sandridge”).

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Processing Plants

SouthOK. The SouthOK system includes six separate processing plants: Velma, Velma V-60 (“V-60”), Atoka, Coalgate, Stonewall and Tupelo; and the East Rockpile treating facility. SouthOK’s processing operations have a total name-plate capacity of 540 MMCFD. The Velma facility is a 100 MMFD cryogenic plant in Stephens County, Oklahoma, which was updated in 2003. The V-60 facility is a 60 MMFD cryogenic plant in Stephens County, Oklahoma, which was placed into service in 2012. The Tupelo facility is a 120 MMCFD cryogenic plant in Coal County, Oklahoma, which started operations in December 2011. The East Rockpile facility is a wholly-owned 250 GPM amine treating plant in Pittsburg County, Oklahoma, which started operations in June 2007.

The Atoka, Coalgate and Stonewall facilities are owned by Centrahoma Processing, LLC (“Centrahoma”), a joint venture that we operate, and in which we have a 60% ownership interest; the remaining 40% ownership interest is held by MarkWest. The Atoka facility is a 20 MMCFD cryogenic plant in Atoka County, Oklahoma, which started operations in November 2006 and is currently idle. The Coalgate facility is an 80 MMCFD cryogenic plant in Coal County, Oklahoma, which started operations in September 2007. The Stonewall facility is a 160 MMCFD cryogenic plant located near the Coalgate and Tupelo facilities, which was placed into service on May 1, 2014 (see “–Recent Developments”). A planned expansion of the Stonewall plant to raise the processing capacity to 200 MMCFD is anticipated to be completed in the first quarter of 2015.

 

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WestOK. The WestOK system processes natural gas through three separate cryogenic natural gas processing plants at the Waynoka I and II and the Chester facilities; and one refrigeration plant at the Chaney Dell facility. The WestOK system’s processing operations have total name-plate capacity of approximately 458 MMCFD. Waynoka I, a 200 MMCFD plant located in Woods County, Oklahoma, began operations in 2006. Waynoka II, a 200 MMCFD cryogenic plant in Woods County, Oklahoma, began operations in September 2012. Chester, a 28 MMCFD plant located in Woodward County, Oklahoma, began operations in 1981. Chaney Dell, a 30 MMCFD plant in Woods County, Oklahoma, began operations in January 2012.

Natural Gas and NGL Marketing

SouthOK. The SouthOK system has access to natural gas take-away pipelines owned by Enable Oklahoma Intrastate Transmission, LLC; MarkWest Energy Partners, LP; Natural Gas Pipeline Company of America; ONEOK Gas Transportation, LLC; and Southern Star Central Gas Pipeline, Inc. We sell our NGL production at SouthOK to ONEOK under two separate agreements. The Velma agreement has a term expiring at the end of 2016, and the Arkoma agreement has a term expiring in 2024. We have signed an agreement with DCP to sell our NGL production from our Velma processing facilities upon the expiration of the Velma ONEOK agreement. The Velma DCP agreement has a term of fifteen years. Condensate collected at the SouthOK gas plants and gathering systems is currently sold to EnerWest Trading Company, LLC and Enterprise Products Partners, L.P.

WestOK. The WestOK system has access to natural gas take-away pipelines owned by Enogex LLC; Panhandle Eastern Pipe Line Company, LP; and Southern Star Central Gas Pipeline, Inc. We sell our NGL production at WestOK to DCP. The WestOK DCP agreement has a term expiring in 2029. Condensate collected at the WestOK plants and gathering systems is currently sold to JP Energy Partners, L.P.; Plains Marketing, L.P.; and Murphy Energy Corporation.

Our Texas Operations

Our Texas operations own, operate and/or have interests in seven natural gas processing facilities and approximately 4,600 miles of intrastate natural gas gathering systems located in Texas. Our Texas gathering systems and processing plants service long-lived natural gas regions, including the Permian Basin and the Barnett and Eagle Ford Shales. Our Texas systems have receipt points consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells from which we gather natural gas from oil and natural gas wells; process the raw natural gas into residue gas by extracting NGLs and removing impurities; and transport natural gas to interstate and public utility pipelines for delivery to customers.

 

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SouthTX. The SouthTX gathering system is located in the Eagle Ford Shale in southern Texas. The gathering system has approximately 800 miles of active pipeline with receipt points consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells. Our SouthTX assets also include a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), which has approximately 60 miles of active gathering pipeline; and a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (together with T2 LaSalle, the “T2 Joint Ventures”), which has approximately 116 miles of active gathering pipeline. The T2 Joint Ventures are operated by a subsidiary of Southcross Holdings, L.P., which owns the remaining interests. The primary natural gas suppliers on the SouthTX gathering system include Statoil and Talisman.

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WestTX. The WestTX gathering system, which we operate and in which we have an approximate 72.8% ownership, has approximately 3,800 miles of active natural gas gathering pipelines located across nine counties within the Permian Basin in West Texas. Pioneer, the largest active driller in the Spraberry and Wolfberry Trends and a major producer in the Permian Basin, owns the remaining interest in the WestTX system. The primary natural gas suppliers on the WestTX gathering system include Parsley Energy, COG Operating, LLC; Laredo Petroleum, Inc.; Endeavor Energy Resources LP; and Pioneer.

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Barnett. The Barnett Shale gas gathering system and related assets are located in Tarrant County, Texas. The system consists of 20 miles of gathering pipeline. The Barnett gas gathering system is used to facilitate gathering of the natural gas production of our affiliate, ARP.

Processing Plants

SouthTX. The SouthTX system processes natural gas through the Silver Oak I and II processing plants. The Silver Oak I facility is a 200 MMCFD cryogenic plant located in Bee County, Texas, which started operations in 2012. A second 200 MMCFD cryogenic processing facility, the Silver Oak II plant, was placed into service on June 25, 2014 (see “—Recent Developments”). Our SouthTX assets also include a 50% interest in T2 EF Cogeneration Holdings L.L.C., which owns a cogeneration facility.

 

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WestTX. The WestTX system includes five separate plants: the Consolidator, Driver, Midkiff, Benedum and Edward processing facilities. Our WestTX processing operations have an aggregate processing name-plate capacity of approximately 655 MMCFD. The Consolidator plant is a 150 MMCFD cryogenic plant in Reagan County, Texas, which started operations in 2009. The Driver plant is a 200 MMCFD cryogenic plant in Midland County, Texas, which started operations in April 2013. The Midkiff plant, which started operations in 1990, is a 60 MMCFD cryogenic plant located at the same site as our Consolidator plant. The Benedum plant is a 45 MMCFD cryogenic plant in Upton County, Texas that is currently idle. The Edward plant is a 200 MMCFD cryogenic plant located in Upton County, Texas, near the Benedum plant, which was brought into service on September 15, 2014 (see “–Recent Developments”). To facilitate increased Spraberry production, we are constructing a new 200 MMCFD cryogenic processing plant, known as the Buffalo plant, which is expected to be placed in service during 2016. The Buffalo plant will increase the WestTX aggregate processing name-plate capacity to approximately 855 MMCFD.

Natural Gas and NGL Marketing

SouthTX. Through its Section 311 intrastate transmission pipeline, the SouthTX system has access to natural gas take-away pipelines owned by Enterprise Intrastate, LLC; Kinder Morgan Tejas Pipeline LLC; Natural Gas Pipeline Company of America; Tennessee Gas Pipeline Company, LLC; and Transcontinental Gas Pipe Line. We sell our NGL production at SouthTX to DCP and Enlink Midstream Partners, LP. In September 2014, we signed an NGL agreement with DCP, which expires in 2029. Condensate collected at the SouthTX plants and gathering systems is currently sold to BP Products North America, Inc.; Cima Energy, LTD; Shell Trading (US) Company, Inc.; and Superior Crude Gathering, Inc.

WestTX. The WestTX system has access has access to natural gas take-away pipelines owned by Atmos Energy Corporation; El Paso Natural Gas Company; Kinder Morgan Tejas Pipeline, LLC; Enterprise Interstate, LLC; and Northern Natural Gas Company. In September 2014, we signed an NGL agreement with DCP, which expires in 2029. Condensate collected at the WestTX plants and gathering systems is currently sold to Occidental Energy Marketing, Inc. and Plains Marketing, L.P.

Corporate and Other

Tennessee Gathering System. The Tennessee gathering systems are located in the Appalachian Basin. The gathering systems have approximately 70 miles of natural gas gathering pipelines. A portion of the natural gas we gather in Tennessee is derived from wells operated by our affiliate, ARP. In addition, we gather and transport gas for other natural gas producers in the area.

On February 27, 2015, we agreed to transfer 100% of our interest in the Tennessee gas gathering assets to ARP (see “—Recent Developments”).

Gas Treating. Our gas treating facilities include fifteen skid-mounted amine treating plants of various sizes with total capacity of 1,262 GPM and two propane refrigeration plants with total capacity of 27 MMCFD. The plants are located in the Delaware Basin, Granite Wash, Haynesville, Eagle Ford, Woodford and Fayetteville Shale, or are in inventory awaiting deployment. Key customers include Crestwood Arkansas Pipeline, LLC; TPF II East Texas Gathering, LLC; and XTO. Revenues are derived from fee-based contract services and are a function of the capacity of the treating plant. Revenues are not directly dependent upon the value of the natural gas that is treated and thus commodity price risk is limited.

 

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Commodity Risk Management. Our gathering and processing operations are exposed to certain commodity price risks. These risks result from either taking title to natural gas, NGLs and condensate, or purchasing natural gas from certain producers at the wellhead. The amount and character of this price risk is a function of our contractual relationships with natural gas producers or, alternatively, a function of cost of sales. These contractual relationships are generally of two types:

 

    POP: requires us to pay a percentage of revenue to the producer. This generally results in our having a net long physical position for natural gas, NGLs and condensate.

 

    Wellhead or Keepwhole purchases: generally requires us to purchase natural gas and any resulting NGLs produced belong to us; resulting in a net long physical position for NGLs and a net short physical position for natural gas.

We are, therefore, exposed to price risk at a net equity volume level rather than at a revenue level. We manage the positions for natural gas on a net basis, netting our physical long positions against our physical short positions. Normally we are in a net long position on our natural gas.

We attempt to mitigate a portion of these risks through a commodity price risk management program, which employs a variety of financial tools. The resulting combination of the underlying physical business and the commodity price risk management program attempts to convert the physical price environment that consists of floating prices to a risk-managed environment characterized by: (1) using fixed-for-floating swaps, which result in a fixed price for the products we buy or sell; or (2) by utilizing the purchase of put options, which result in floor prices for the products we buy. We utilize NGL and crude oil swaps and options to manage our NGL and condensate price risks and natural gas swaps and options to manage our natural gas price risks. There are also risks inherent within risk management programs, including, among others, deterioration of the price relationship between the physical and financial instrument; and changes in projected physical volumes.

We generally realize gains and losses from the settlement of our derivative instruments at the same time we sell the associated physical residue gas, NGLs or condensate. We also record the unrealized gains and losses for the mark-to-market valuation of derivative instruments prior to settlement. We determine gains or losses on open and closed derivative transactions as the difference between the derivative contract price and the physical price. This mark-to-market methodology uses (1) daily closing New York Mercantile Exchange (“NYMEX”) prices; (2) third party sources; and/or (3) an internally-generated algorithm, utilizing third party sources, for commodities not traded on an open market. To ensure these derivative instruments will be used solely for managing price risks and not for speculative purposes, we have established a committee to review our derivative instruments for compliance with our policies and procedures.

For additional information on our derivative activities, please see “Item 7A: Quantitative and Qualitative Disclosures About Market Risk.”

Competition

Acquisitions. We have encountered competition in acquiring midstream assets owned by third parties. In several instances, we submitted bids in auction situations and in direct negotiations for the acquisition of such assets and we were either outbid by others or we were unwilling to meet the sellers’ expectations. In the future, we expect to encounter equal, if not greater, competition for the acquisition of midstream assets.

 

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Oklahoma. In our Oklahoma segment, we compete for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by: Caballo Energy, LLC; DCP Midstream Partners, LLC; Enable Midstream Partners, L.P.; Energy Transfer Partners, L.P.; Kinder Morgan Energy Partners, L.P.; Lumen Midstream Partners, LLC; Mustang Fuel Corporation; ONEOK Field Services Company, LLC; SemGas, L.P.; and Superior Pipeline Company, LLC.

Texas. In our Texas segment, we compete for the acquisition of well connections with several other gathering/processing operations. These operations include plants and gathering systems operated by: DCP Midstream Partners, LP; Energy Transfer Partners, L.P.; Enlink Midstream Partners, LP; Enterprise Products Partners, L.P.; Kinder Morgan Energy Partners, L.P.; Southcross Energy Partners, L.P.; Southern Union Company; Targa Resources Partners LP; and West Texas Gas, Inc.

We believe the principal factors upon which competition for new well connections is based are:

 

    the price received by an operator or producer for its production after deduction of allocable charges, principally the use of the natural gas to operate compressors;

 

    the quality and efficiency of the gathering systems and processing plants that will be utilized in delivering the gas to market;

 

    the access to various residue markets that provides flexibility for producers and ensures the gas will make it to market; and

 

    the responsiveness to a well operator’s needs, particularly the speed at which a new well is connected by the gatherer to its system.

We believe we have good relationships with operators connected to our system and that we present an attractive alternative for producers. However, if we cannot compete successfully through pricing or services offered, we may be unable to obtain new well connections.

In our Corporate and Other segment, we compete for gas treating services provided on gas gathering lines, including gas treating services provided by Kinder Morgan Energy Partners, L.P.; Spartan Energy Partners LLC; and TransTex Hunter, LLC.

The factors that typically affect our ability to compete for gas treating services are:

 

    fees charged under our contracts;

 

    the quality and efficiency of our operations; and

 

    our responsiveness to a customer’s needs.

Seasonality

Our business is affected by seasonal fluctuations in commodity prices. Sales volumes are also affected by various factors such as fluctuating and seasonal demands for products and variations in weather patterns from year to year. Generally, natural gas demand increases during the winter months and decreases during the summer months. Freezing conditions can disrupt our gathering process, which could adversely affect our operating results.

 

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Environmental Matters and Regulations

The operation of pipelines, plant and other facilities for gathering, compressing, treating, processing, or transporting natural gas, NGLs and other products is subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as by:

 

    restricting the way waste disposal is handled;

 

    limiting or prohibiting construction and operating activities in sensitive areas such as wetlands, coastal regions, non-attainment areas, tribal lands or areas inhabited by endangered species;

 

    requiring the installation and operation of expensive pollution control equipment;

 

    requiring remedial measures to reduce, and/or respond to releases of pollutants or hazardous substances by our operations or attributable to former operators;

 

    enjoining some or all of the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations; and

 

    imposing substantial liabilities for pollution resulting from operations.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where pollutants or wastes have been disposed or otherwise released. Neighboring landowners and other third parties can file claims for personal injury or property damage allegedly caused by noise and/or the release of pollutants or wastes into the environment. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress, federal and state agencies frequently enact new, or revise existing, environmental laws and regulations that may result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry, which could have a significant impact on our operating costs.

We believe our operations are in substantial compliance with applicable environmental laws and regulations and compliance with existing federal, state and local environmental laws and regulations and continued compliance therewith should not have a material adverse effect on our business, financial position or results of operations. Nevertheless, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, we cannot ensure that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions, will not cause us to incur significant costs.

Environmental laws and regulations that could have a material impact on our operations include the following:

Endangered Species Act. The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Endangered species, including, without limitation, the American Burying Beetle and Lesser Prairie Chicken, are located in various states in which we operate. If endangered species are located in areas where we propose to construct new gathering or

 

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processing facilities, such work could be prohibited or delayed or expensive mitigation may be required. Existing laws, regulations, policies and guidance relating to protected species may also be revised or reinterpreted in a manner that further increases our construction and mitigation costs or further restricts our construction activities. Additionally, construction and operational activities could result in inadvertent impact to habitats of listed species and could result in alleged takings under the ESA, exposing us to civil or criminal enforcement actions and fines or penalties. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where we conduct operations or plan to construct pipelines or facilities could cause us to incur increased costs arising from species protection measures or could result in delays in the construction of our facilities or limitations on our customer’s exploration and production activities, which could have an adverse impact on demand for our midstream operations.

Risk Management Planning. The Environmental Protection Agency (“EPA”), in conjunction with the Occupational Safety and Health Administration (“OSHA”) and the U.S. Department of Homeland Security (“DHS”), in response to numerous recent industrial facility explosions, has initiated a nation-wide Request for Information (“RFI”), with the intent of strengthening the existing Chemical Accident Prevention Provisions (40 CFR 68). The EPA has indicated that rule changes will be forthcoming based upon results of the RFI. If implemented, such changes have the potential to impact our gas plants by defining more rigorous design standards, regulating siting of new processes, requiring installation of automated detection devices and implementing mandatory third-party audits.

Hazardous Waste. The Solid Waste Disposal Act, including the Resource Conservation and Recovery Act (“RCRA”), and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the EPA, individual states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil and natural gas constitute “solid wastes”, which are regulated under the less stringent non-hazardous waste provisions, but there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as solid waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

We believe our operations are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent our operations require them under such laws and regulations. Although we do not believe the current costs of managing our solid wastes to be material, any more stringent regulation of natural gas and oil exploration and production wastes could increase our costs to manage and dispose of such wastes.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up

 

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the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years were used for the measurement, gathering, field compression and processing of natural gas. Although we believe we utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. There may be evidence that petroleum spills or releases have occurred at some of the properties owned or leased by us. However, none of these spills or releases appear to be material to our financial condition and we believe all of them have been or will be appropriately remediated. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform operations to prevent future contamination.

Air Emissions. Our operations are subject to the federal Clean Air Act, as amended and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, certain storage vessels and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. These laws and regulations also apply to entities that use natural gas as fuel, and may increase the costs of customer compliance to the point where demand for natural gas is affected. Various air quality regulations are periodically reviewed by the EPA and are amended as deemed necessary. The EPA may also issue new regulations based on changing environmental concerns.

In 2012, specific federal regulations applicable to the natural gas industry were finalized under the New Source Performance Standards (“NSPS”) program along with National Emissions Standards for Hazardous Air Pollutants (“NESHAP”). These regulations impose additional emissions control requirements and practices on our operations. Some of our facilities may incur additional capital costs in order to comply with new emission limitations. These regulations may increase the costs of compliance for some facilities. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We believe our operations are in substantial compliance with the requirements of the Clean Air Act.

In 2014, the EPA proposed to lower the current ozone National Ambient Air Quality Standards (“NAAQS”) to a more stringent NAAQS. The EPA is required to promulgate the ozone NAAQS by court order no later than October 1, 2015. If lowered, the more stringent ozone NAAQS could impose additional permitting and regulatory requirements on major new facilities and facility expansions as well as existing facilities. These requirements could increase the cost of compliance at our facilities and other industrial sources in future years.

 

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While we will likely be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions, we believe our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than other similarly situated companies.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other natural gas and oil wastes, into navigable waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. These permits may require pretreatment of produced waters before discharge. Compliance with such permits and requirements may be costly. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The Clean Water Act also requires specified facilities to maintain and implement spill prevention, control and countermeasure plans and to take measures to minimize the risks of petroleum spills. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for failure to obtain a permit or non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe our operations are in substantial compliance with the requirements of the Clean Water Act.

OSHA and other regulations. We are subject to the requirements of OSHA and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

Hydrogen Sulfide. Exposure to gas containing high levels of hydrogen sulfide, referred to as sour gas, is harmful to humans and can result in death. A portion of the gas processed at our Velma gas plant contains high levels of hydrogen sulfide, and we employ numerous safety precautions at the system to ensure the safety of our employees. There are various federal and state environmental and safety requirements for handling sour gas, and we believe we are in substantial compliance with such requirements.

Chemicals of Interest. We operate several facilities registered with DHS in order to identify the quantities of various chemicals stored at the sites. The liquid hydrocarbons recovered and stored as a result of facility processing activities, and various chemicals utilized within the processes, have been identified and registered with DHS. These registration requirements for Chemical of Interest were first promulgated by DHS in 2008 and we believe we are currently in substantial compliance with the Department’s requirements. None of our affected facilities are considered high security risks by DHS at this time and no specific security plans for such per DHS regulations are required.

Greenhouse gas regulation and climate change. To date, legislative and regulatory initiatives relating to greenhouse gas emissions have not had a material impact on our business. However, Congress has been actively considering climate change legislation. More recently, the EPA has begun regulating greenhouse gas emissions under the federal Clean Air Act. In response to the Supreme Court’s decision in Massachusetts V. EPA, 549 U.S. 497 (2007) (holding that greenhouse gases are air pollutants covered by the Clean Air Act), the EPA made a final determination that greenhouse gases endangered public health and welfare, 74 Fed. Reg. 66,496 (December 15, 2009). This finding led to the regulation of greenhouse gases under the Clean Air Act. Currently, the EPA has promulgated two rules that will impact our business.

 

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First, the EPA promulgated the so-called “Tailoring Rule” which established emission thresholds for greenhouse gases under the Clean Air Act permitting programs, 75 Fed. Reg. 31514 (June 3, 2010). Both the federal preconstruction review program (Prevention of Significant Deterioration, or PSD) and the operating permit program (Title V) are now implicated by emissions of greenhouse gases. These programs, as modified by the Tailoring Rule, could require some new facilities to obtain a PSD permit depending on the size of the new facilities. Likewise, existing facilities could be required to obtain a PSD permit if modification projects are significant. In addition, existing facilities as well as new facilities that exceed the emissions thresholds could be required to obtain Title V operating permits.

Second, the EPA finalized its Mandatory Reporting of Greenhouse Gases rule in 2009, 74 Fed. Reg. 56,260 (October 30, 2009). Subsequent revisions, additions, and clarification rules were promulgated, including a rule specifically addressing the natural gas industry. These rules require certain industry sectors that emit greenhouse gases above a specified threshold to report greenhouse gas emissions to the EPA on an annual basis. This rule imposes additional obligations on us to determine whether the greenhouse gas reporting applies and if so, to calculate and report greenhouse gas emissions. This rule also imposes monitoring and sampling requirements upon our gas processing plants via the use of expensive instruments. In 2014, EPA proposed regulations that could expand such requirements to compressor stations, which have previously been exempt from these types of monitoring requirements. If finalized, these requirements could increase cost of operation at our compressor stations in future years.

On January 14, 2015, the EPA announced its intent to set new standards for the regulation of Methane and Volatile Organic Compounds emissions in the oil and gas sector. It is anticipated that these standards will be built upon the 2012 New Source Performance Standards for the oil and gas sector and the EPA is aiming to finalize the rulemaking in 2016. The EPA has indicated the rule could address emissions from new and modified oil and gas production sources, and natural gas processing and transmission sources.

There are also ongoing legislative and regulatory efforts to encourage the use of cleaner energy technologies. While natural gas is a fossil fuel, it is considered to be more benign, from a greenhouse gas standpoint, than other carbon-based fuels, such as coal or oil. Thus future regulatory developments could have a positive impact on our business to the extent that they either decrease the demand for other carbon-based fuels or position natural gas as a favored fuel.

In addition to domestic regulatory developments, the United States is a participant in multi-national discussions intended to deal with the greenhouse gas issue on a global basis. To date, those discussions have not resulted in the imposition of any specific regulatory system, but such talks are continuing and may result in treaties or other multi-national agreements that could have an impact on our business. Currently, some scientific and international organizations believe that methane, a greenhouse gas inadvertently emitted from our operations, has a higher global warming potential than previously recognized. The EPA may amend regulations to reflect this change. If so, the change would make it more likely that some of our operations would be subject to PSD and Title V permitting requirements.

Finally, the scientific community continues to engage in a healthy debate as to the impact of greenhouse gas emissions on planetary conditions. For example, such emissions may be responsible for increasing global temperatures, and/or enhancing the frequency and severity of storms, flooding and other similar adverse weather conditions. We do not believe these conditions are having any material current adverse impact on our business, and we are unable to predict at this time, what, if any, long-term impact such climate effects would have.

 

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Pipeline Safety and Other Regulations

Pipeline Safety. Some of our natural gas pipelines are subject to regulation by the U.S. Department of Transportation, or DOT, under the pipeline safety laws, 49 U.S.C. §§ 60101 et seq. The pipeline safety laws authorize DOT to regulate pipeline facilities and persons engaged in the transportation by pipeline of gas, i.e., natural gas, flammable gas, or gas that is toxic or corrosive, and hazardous liquids, i.e., petroleum or petroleum products, including NGLs, and other designated substances that pose an unreasonable risk to life or property when transported in liquid state. The DOT Secretary has delegated that authority to one of the Department’s modal administrations, the Pipeline and Hazardous Materials Safety Administration, or PHMSA. Acting primarily through the Office of Pipeline Safety, or OPS, PHMSA administers a national regulatory program to ensure the safety of transportation-related gas and hazardous liquid pipeline facilities.

As part of that national program, PHMSA has established minimum federal safety standards for the design, construction, testing, operation, and maintenance of gas and hazardous liquid pipeline facilities. These safety standards apply to most pipeline facilities in the United States, including gathering lines, transmission lines, and distribution lines, and are the only safety requirements that apply to interstate pipeline facilities. PHMSA has also promulgated a series of reporting requirements for operators of gas and hazardous liquid pipeline facilities, as well as provisions for establishing the qualification of pipeline personnel and requirements for managing the integrity of gas transmission and distribution lines and certain hazardous liquid pipelines. To ensure compliance with these provisions, OPS performs pipeline safety inspections and has the authority to initiate enforcement actions, which can lead to the assessment of administrative civil penalties of up to $200,000 per day, per violation, not to exceed $2,000,000 for any related series of violations.

PHMSA also oversees a program that allows the states to submit an annual certification to regulate intrastate pipeline facilities. States that participate in the program can apply additional or more stringent safety standards to the pipeline facilities under their certifications, so long as those standards are compatible with the minimum federal requirements. States can also enter into agreements with PHMSA to participate in the oversight of intrastate or interstate pipelines, primarily by performing inspections for compliance with preemptive federal safety standards. The Kansas Corporation Commission, the Oklahoma Corporation Commission, and the Texas Railroad Commission all participate in the federal gas pipeline safety program and have certification to regulate intrastate gas pipeline facilities. The Oklahoma Corporation Commission and the Texas Railroad Commission also have certification to regulate intrastate hazardous liquid pipeline facilities.

Our operations are required to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation and appropriate state authorities. We believe our pipeline operations are in substantial compliance with the federal pipeline safety laws and regulations and any state laws and regulations that apply to our pipeline facilities. However, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, the activities needed to ensure future compliance could result in additional costs.

On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “Job Act”) was signed into law. The Job Act requires DOT and the U.S. Government Accountability Office to complete a number of reviews, studies, evaluations and reports in preparation for potential rulemakings applicable to pipeline facilities. The issues addressed in these rulemaking provisions include, but are not limited to, the use of automatic or remotely-controlled shut-off valves on new or replaced transmission line facilities, modifying the requirements for pipeline leak detection systems, and expanding the scope of the pipeline integrity management requirements. The PHMSA is considering these and other provisions in the Job Act and has sought public comment on changes to a number of regulations related to pipeline safety. On September 25, 2013, the PHMSA issued a final rule

 

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implementing changes in its administrative procedures required by the Job Act, but the rulemaking process is continuing with respect to aspects of the Job Act related to pipeline safety regulations. At this time, we cannot predict what effect, if any, the future application of such regulations might have on our operations, but we, as part of the midstream natural gas industry, could be required as a result of any new PHMSA regulations to incur additional capital expenditures and increased operating costs.

The state of Texas adopted House Bill 2982, effective on September 1, 2013. This bill amended the Texas laws delegating to the Texas Railroad Commission the authority to regulate pipeline safety for intrastate pipelines to include transportation and gathering facilities for gas in Class 1 locations and for hazardous liquids and CO² in rural locations. Before September 1, 2015, the Texas Railroad Commission must implement rules governing the commission investigations of an accident, an incident, threats to public safety, and complaints related to operational safety; and to require an operator to submit a plan to remediate any such issues and to file reports with respect to any such issues, or to require operators to provide information requested by the Texas Railroad Commission.

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act of 1938, 15 U.S.C. § 717(b), exempts natural gas gathering facilities from the jurisdiction of FERC. We own a number of natural gas gathering lines in Kansas, Oklahoma and Texas that we believe meet the traditional tests FERC has used to establish a pipeline’s status as a gathering facility not subject to FERC jurisdiction. However, the distinction between FERC-regulated natural gas transportation facilities and federally unregulated natural gas gathering facilities is the subject of regular litigation, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by FERC and the courts.

We are currently subject to state ratable take, common purchaser and/or similar statutes in one or more jurisdictions in which we operate. Common purchaser statutes generally require gatherers to purchase production without discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. In particular, Kansas, Oklahoma and Texas have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed or regulation by the Kansas Corporation Commission, the Oklahoma Corporation Commission or the Texas Railroad Commission become more active, our revenues could decrease. Collectively, any of these laws may restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be, or may become, subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered and adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Transmission Pipeline Regulation. We operate natural gas pipelines that extend from some of our processing plants to interconnections with both intrastate and interstate natural gas pipelines. Those facilities, known in the industry as “plant tailgate” pipelines, typically operate at transmission pressure levels and may transport “pipeline quality” natural gas. Because our plant tailgate pipelines are relatively short, we treat them as “stub” lines, which are exempt from FERC’s jurisdiction under the Natural Gas Act. FERC’s treatment of the “stub” line exemption has varied over time, but, absent other factors, FERC generally limits the length of the lines that qualify for the “stub” line exemption.

 

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We own (in conjunction with Pioneer) and operate the Driver Residue Pipeline, a gas transmission pipeline extending from our Driver processing plant in WestTX just over ten miles to points of interconnection with intrastate and interstate natural gas transmission pipelines. We have obtained a limited jurisdiction certificate of public convenience and necessity under the Natural Gas Act for the Driver Residue Pipeline. In the certificate order, among other things, FERC waived requirements pertaining to the filing of an initial rate for service, the filing of a tariff and compliance with specified accounting and reporting requirements. As such, the Driver Residue Pipeline is not currently subject to conventional rate regulation; to requirements FERC imposes on “open access” interstate natural gas pipelines; to the obligation to file and maintain a tariff; or to the obligation to conform to certain business practices and to file certain reports. If, however, we were to receive a bona fide request for firm service on the Driver Residue Pipeline from a third party, FERC would reexamine the waivers it has granted us and would require us to file for authorization to offer “open access” transportation under its regulations, which would impose additional costs upon us.

To the extent our plant tailgate pipelines do not qualify for the “stub” line exemption, we will consider whether we need to obtain FERC authorization to operate our tailgate pipelines or whether they can be reconfigured or otherwise modified to eliminate the possibility that they could be subject to FERC jurisdiction. If we conclude that FERC authorization is necessary, we would expect to seek regulatory treatment similar to the treatment FERC has accorded to the Driver Residue Pipeline. We cannot, however, assure you that FERC would agree to assert only limited jurisdiction. If FERC were to find that it must assert comprehensive jurisdiction, our operating costs would increase and we could be subject to enforcement actions under the Energy Policy Act of 2005.

We have an ownership interest of 50% of the capacity in a 50-mile long intrastate natural gas transmission pipeline, which extends from the tailgate of three natural gas processing plants located near Pettus, Texas to interconnections with existing intrastate and interstate natural gas pipelines near Refugio, Texas. The capacity is held by our subsidiary, APL SouthTex Transmission Company LP (“APL SouthTex Transmission”), which is entitled to transport natural gas through its capacity on behalf of third parties to both intrastate and interstate markets. Because the jointly owned pipeline system was initially interconnected only with intrastate markets, each of the capacity holders qualified as an “intrastate pipeline” within the meaning of the Natural Gas Policy Act of 1978, or the NGPA and therefore are able to provide transportation of natural gas to interstate markets under Section 311 of the NGPA. Under Sections 311 and 601 of the NGPA, an intrastate pipeline may transport natural gas in interstate commerce without becoming subject to FERC regulation as a “natural-gas company” under the Natural Gas Act. Transportation of natural gas under authority of Section 311 must be filed with FERC and must be shown to be “fair and equitable.” APL SouthTex Transmission has a Statement of Operating Conditions on file with FERC, and FERC has accepted the rates, which APL SouthTex Transmission’s predecessor filed, as being in accordance with the “fair and equitable” standard. APL SouthTex Transmission is required to file, on or before November 6, 2017, a petition for approval of its then-existing rates, or to propose a new rate, applicable to NGPA Section 311 service.

NGL Pipeline Regulation. The transportation of crude oil, petroleum products and NGLs is subject in certain circumstances to regulation under the Interstate Commerce Act. Responsibility for the regulation of so-called oil pipelines now resides with the FERC. Rates charged for the interstate movement of crude oil, petroleum products and NGLs must be filed with FERC and are subject to FERC review and, under the Interstate Commerce Act, FERC has exclusive jurisdiction to determine whether oil pipelines’ interstate rates and terms of service are just, reasonable, and not unduly discriminatory. Pursuant to the Interstate Commerce Act, interstate oil pipeline rates can be challenged before FERC

 

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either by protest when they are initially filed or increased or by complaint for as long as they remain on file with FERC. FERC does not, however, regulate oil pipelines’ decisions to commence or terminate service or the construction of oil pipeline facilities. Individual states may regulate oil pipelines as utilities or as common carriers. As a general rule, neither FERC nor the states regulate oil pipelines that are purely proprietary and provide transportation service only for the pipeline’s owner.

The Oklahoma Corporation Commission and Texas Railroad Commission both have authority to regulate rates charged by common carrier pipelines in their respective jurisdictions.

Transportation and Sales of Natural Gas and NGLs. A portion of our revenue is tied to the price of natural gas and NGLs. The wholesale price of natural gas and NGLs is not currently subject to federal regulation and, for the most part, is not subject to state regulation. Sales of natural gas and NGLs are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation of natural gas and NGLs are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting the segments of the natural gas industry, most notably interstate natural gas transportation companies that remain subject to FERC’s jurisdiction. While FERC is less active in proposing changes in the manner in which it regulates the transportation of NGLs under the Interstate Commerce Act, it does nevertheless have authority to address the rates, terms and conditions under which NGLs are transported. FERC initiatives could, therefore, affect the transportation of natural gas and NGLs under certain circumstances. We cannot predict the ultimate impact of any regulatory changes that could result from such FERC initiatives.

Energy Policy Act of 2005. The Energy Policy Act contains numerous provisions relevant to the natural gas industry and to interstate natural gas pipelines in particular. Overall, the legislation attempts to increase supply sources by calling for various studies of the overall resource base and attempting to advantage deep water production on the Outer Continental Shelf in the Gulf of Mexico. However, the provisions of primary interest to us as an operator of natural gas gathering lines and sellers of natural gas focus on two areas: (1) infrastructure development; and (2) market transparency and enhanced enforcement. Regarding infrastructure development, the Energy Policy Act shortens the depreciable life for gathering facilities; statutorily designates FERC as the lead agency for environmental reviews required in connection with federal authorizations and permits relating to interstate natural gas pipelines; provides for the assembly of a consolidated record for all federal decisions relating to necessary authorizations and permits with respect to interstate natural gas pipelines; and provides for expedited judicial review of any agency action involving the permitting of such facilities and review by only the D.C. Circuit Court of Appeals of any alleged failure of a federal agency to act on a permit relating to an interstate natural gas pipeline by a deadline set by FERC as lead agency. Regarding market transparency and manipulation, the Energy Policy Act amended the Natural Gas Act to prohibit market manipulation and directs FERC to prescribe rules designed to encourage the public provision of data and reports regarding the price of natural gas in wholesale markets. In this regard, the Natural Gas Act and the Natural Gas Policy Act were also amended to increase monetary criminal penalties to $1,000,000 from the $5,000 amount specified under prior law and to add and increase civil penalty authority to be administered by FERC to $1,000,000 per day per violation without any limitation as to total amount.

Our Driver Residue Pipeline is subject to only limited regulation by FERC under the Natural Gas Act. Our APL SouthTex Transmission pipeline is subject to limited regulation of the interstate transportation services it provides under Section 311 of the NGPA. Accordingly, the provisions of the Energy Policy Act have only limited applicability to us, primarily in our capacity as a seller of natural gas, as the operator of interstate natural gas pipelines subject to limited jurisdiction certificates, and as operator of an intrastate natural gas pipeline offering interstate service under Section 311 of the NGPA. As such, we are subject to the Energy Policy Act as the owner of facilities, and thus we are subject to

 

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(1) civil penalties for violations of the Natural Gas Act; (2) the NGPA or FERC regulations or orders issued under those laws; and (3) for conduct determined to constitute market manipulation. The penalties associated with any violations of the Energy Policy Act could be substantial.

Other regulation of the natural gas and oil industry. The natural gas and oil industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the natural gas and oil industry is under constant review for amendment or expansion, frequently increasing the regulatory burden that operators must bear. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the natural gas and oil industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the natural gas and oil industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in their industries with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including natural gas and oil facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the potential costs to comply with any such facility security laws or regulations, but such expenditures could be substantial.

 

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Properties

Our principal facilities consist of 17 natural gas processing plants; 18 gas treating facilities; and approximately 12,300 miles of active 2 inch to 30 inch diameter natural gas gathering lines. Substantially all our gathering systems are constructed within rights-of-way granted by property owners named in the appropriate land records. In a few cases, property for gathering system purposes was purchased in fee. All our compressor stations are located on property owned in fee or on property obtained via long-term leases or surface easements.

The following tables set forth certain information relating to our gas processing facilities, and natural gas gathering systems:

Gas Processing Facilities

 

Facility

   Location    Year
Constructed
     Design
Throughput
Capacity
(MMCFD)
     2014
Average
Utilization
Rate
 

Atoka plant (idle)

   Atoka County, OK      2006         20      

Coalgate plant

   Coal County, OK      2007         80      

Stonewall plant

   Coal County, OK      2014         160      

Tupelo plant

   Coal County, OK      2011         120      

Velma plant

   Stephens County, OK      Updated 2003         100      

Velma V-60 plant

   Stephens County, OK      2012         60      
        

 

 

    

 

 

 

Total SouthOK

  540      76 %(1) 
        

 

 

    

 

 

 

Waynoka I plant

Woods County, OK   2006      200   

Waynoka II plant

Woods County, OK   2012      200   

Chaney Dell plant

Major County, OK   2012      30   

Chester plant

Woodward County, OK   1981      28   
        

 

 

    

 

 

 

Total WestOK

  458      100 %(1) 
        

 

 

    

 

 

 

Total Oklahoma

  998      95 %(1) 
        

 

 

    

 

 

 

Consolidator plant

Reagan County, TX   2009      150   

Driver plant

Midland County, TX   2013      200   

Midkiff plant

Reagan County, TX   1990      60   

Benedum plant (idle)

Upton County, TX   Updated 1981      45   

Edward plant

Upton County, TX   2014      200   
        

 

 

    

 

 

 

Total WestTX

  655      70
        

 

 

    

 

 

 

Silver Oak I

Bee County, TX   2012      200   

Silver Oak II

Bee County, TX   2014      200   
        

 

 

    

 

 

 

Total SouthTX

  400      30
        

 

 

    

 

 

 

Total Texas

  1,055      55
        

 

 

    

 

 

 

Total

  2,053      75 %(1) 
        

 

 

    

 

 

 

 

(1) Certain processing facilities in these business units are capable of processing more than their name-plate capacity and when capacity is exceeded we will off-load volumes to other processors, as needed. The calculation of the total average utilization rate for the year includes these off-loaded volumes.

 

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Of the 18 gas treating facilities we own, 17 are held for use to provide contract treating services to natural gas producers located in Arkansas, Louisiana, Oklahoma and Texas. Two of our contract gas treating facilities are refrigeration facilities and the other 15 are amine facilities. The remaining treating facility is a 250 GPM amine treating plant, which is used in our processing operations in the SouthOK system and is included in the Oklahoma segment. Our 17 contract gas treating facilities are included in the Corporate and Other segment.

Natural Gas Gathering Systems

 

System

  

Location

   Approximate Active
Miles of Pipe
 

SouthOK

   Southern Oklahoma and Northern Texas      1,500   

WestOK

   North Central Oklahoma and Southern Kansas      6,100   
     

 

 

 

Total Oklahoma

  7,600   
     

 

 

 

SouthTX

Southern Central Texas   800   

WestTX

West Texas   3,800   

Barnett Shale

Central Texas   20   
     

 

 

 

Total Texas

  4,620   
     

 

 

 

Tennessee

Tennessee   70   
     

 

 

 

Total

  12,290   
     

 

 

 

Our property or rights-of-way are subject to encumbrances, restrictions and other imperfections. These imperfections have not materially interfered, and we do not expect they will materially interfere, with the conduct of our business. In many instances, lands over which rights-of-way have been obtained are subject to prior liens, which have not been subordinated to the rights-of-way grants. In a few instances, our rights-of-way are revocable at the election of the land owners. In some cases, not all of the owners named in the appropriate land records have joined in the rights-of-way grants, but in substantially all such cases signatures of the owners of majority interests have been obtained. Substantially all permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, where necessary, although in some instances these permits are revocable at the election of the grantor. Substantially all permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election.

Certain of our rights to lay and maintain pipelines are derived from recorded gas well leases, with respect to wells currently in production; however, the leases are subject to termination if the wells cease to produce. Because many of these leases affect wells at the end of lines, these rights-of-way will not be used for any other purpose once the related wells cease to produce.

Employees

As is commonly the case with publicly-traded limited partnerships, we do not directly employ any of the persons responsible for our management or operations. In general, employees of ATLS and its affiliates manage and operate our business. ATLS employed approximately 485 people at December 31, 2014 who provided direct support for our operations.

 

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Affiliates of our General Partner will conduct business and activities of their own in which we will have no economic interest; and there could be material competition between our General Partner, affiliates of our General Partner and us for the time and effort of the officers and employees who provide services to our General Partner. Apart from our Executive Chairman and Executive Vice Chairman and officers providing services in the area of corporate development, the officers of our General Partner who provide services to us are generally assigned solely to our operations. However, they are not required to work full time on our affairs. These officers may also devote time to the affairs of our General Partner’s affiliates and be compensated by these affiliates for the services rendered to them. There may be conflicts between affiliates of our General Partner and us regarding the availability of these officers to manage us.

Available Information

We make our periodic reports under the Securities Exchange Act of 1934, including our annual report on Form 10-K, proxy statements and our quarterly reports on Form 10-Q and our current reports on Form 8-K, available through our website at www.atlaspipeline.com. To view these reports, click on “Investor Relations,” then “SEC Filings.” You may also receive, without charge, a paper copy of any such filings by request to us at Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, Pennsylvania 15275-1011, telephone number (877) 950-7473. A complete list of our filings is available on the SEC’s website at www.sec.gov. Any of our filings are also available at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The Public Reference Room may be contacted at telephone number (800) 732-0330 for further information.

 

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ITEM 1A. RISK FACTORS

Partnership interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected.

Risks Relating to Our Business

The amount of cash we generate depends, in part, on factors beyond our control.

The amount of cash we generate may not be sufficient for us to pay distributions at the current distribution levels or at all in the future. Our ability to make cash distributions depends primarily on our cash flows. Cash distributions do not depend directly on our profitability, which is affected by non-cash items. Therefore, cash distributions may be made during periods when we record losses and may not be made during periods when we record profits. The actual amounts of cash we generate will depend upon numerous factors relating to our business, which may be beyond our control, including:

 

    the demand for natural gas, NGLs, crude oil and condensate;

 

    the price of natural gas, NGLs, crude oil and condensate (including the volatility of such prices);

 

    the amount of NGL content in the natural gas we process;

 

    the volume of natural gas we gather;

 

    efficiency of our gathering systems and processing plants;

 

    expiration of significant contracts;

 

    continued development of wells for connection to our gathering systems;

 

    our ability to connect new wells to our gathering systems;

 

    our ability to integrate newly-formed ventures or acquired businesses with our existing operations;

 

    the availability of local, intrastate and interstate transportation systems;

 

    the availability of fractionation capacity;

 

    the expenses we incur in providing our gathering services;

 

    the cost of acquisitions and capital improvements;

 

    required principal and interest payments on our debt;

 

    fluctuations in working capital;

 

    prevailing economic conditions;

 

    fuel conservation measures;

 

    alternate fuel requirements;

 

    the strength and financial resources of our competitors;

 

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    the effectiveness of our commodity price risk management program and the creditworthiness of our derivatives counterparties;

 

    governmental (including environmental and tax) laws and regulations; and

 

    technical advances in fuel economy and energy generation devices.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

 

    the level of capital expenditures we make;

 

    the sources of cash used to fund our acquisitions;

 

    limitations on our access to capital or the market for our common units and notes;

 

    our debt service requirements; and

 

    the amount of cash reserves established by our General Partner for the conduct of our business.

Our ability to make payments on and to refinance our indebtedness will depend on our financial and operating performance, which may fluctuate significantly from quarter to quarter, and is subject to prevailing economic and industry conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you we will continue to generate sufficient cash flow, or be able to borrow sufficient funds, to service our indebtedness or to meet our working capital and capital expenditure requirements. If we are not able to generate sufficient cash flow from operations or to borrow sufficient funds to service our indebtedness, we may be required to sell assets or equity, reduce capital expenditures, refinance all or a portion of our existing indebtedness or obtain additional financing. We cannot assure you we will be able to refinance our indebtedness, sell assets or equity, or borrow more funds on terms acceptable to us, or at all.

Economic conditions and instability in the financial markets could negatively impact our business.

Our operations are affected by the financial markets and related effects in the global financial system. The consequences of an economic recession and the effects of a financial crisis may include a lower level of economic activity and/or increased volatility in energy prices. This may result in a decline in energy consumption and lower market prices for oil and natural gas, and has previously resulted in a reduction in drilling activity in our service area and in wells connected to our pipeline system being shut in by their operators until prices improved. Any of these events may adversely affect our revenues and our ability to fund capital expenditures and, in turn, may impact the cash we have available to fund our operations, pay required debt service and make distributions to our unitholders.

 

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Instability in the financial markets may increase the cost of capital while reducing the availability of funds. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We rely on our cash flow from operations and borrowings under our existing credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain additional capital will be available to us to the extent required and on acceptable terms. Disruptions in the capital and credit markets could limit our access to liquidity needed for our business and impact our flexibility to react to changing economic and business conditions. Any disruption could require us to take measures to conserve cash until the markets stabilize or until we can arrange alternative credit arrangements or other funding for our business needs. Such measures could include reducing or delaying business activities, reducing our operations to lower expenses, and reducing other discretionary uses of cash. We may be unable to execute our growth strategy, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively impact our business.

A weakening of the current economic situation could have an adverse impact on our lenders, producers, key suppliers or other customers, causing them to fail to meet their obligations to us. Market conditions could also impact our derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our cash flow and ability to make required debt service payments and pay distributions could be impacted. The uncertainty and volatility surrounding the global financial crisis may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

We are affected by the volatility of prices for natural gas, NGL and crude oil products.

We derive a majority of our gross margin from POP and Keep-Whole contracts. As a result, our income depends to a significant extent upon the prices at which we buy and sell natural gas and at which we sell NGLs and condensate. Average estimated unhedged 2015 market prices for NGLs, natural gas and crude oil, based upon NYMEX forward price curves as of December 16, 2014, were $0.53 per gallon, $3.58 per MMBTU and $58.19 per barrel, respectively. A 10% change in these prices would change our forecasted net income for the twelve-month period ended December 31, 2015 by approximately $14.5 million. Additionally, changes in natural gas prices may indirectly impact our profitability since prices can influence drilling activity and well operations, and could cause operators of wells currently connected to our pipeline system or that we expect will be connected to our system to shut in their production until prices improve, thereby affecting the volume of gas we gather and process. Historically, the prices of natural gas, NGLs and crude oil have been subject to significant volatility in response to relatively minor changes in the supply and demand for these products, market uncertainty and a variety of additional factors beyond our control, including those we describe in “—The amount of cash we generate depends, in part, on factors beyond our control,” above. West Texas Intermediate crude oil prices traded in a range of $53.27 per barrel to $107.26 per barrel in 2014, while Henry Hub natural gas prices have traded in a range of $2.89 per MMBTU to $6.15 per MMBTU, during the same time period. We expect this volatility to continue. This volatility may cause our gross margin and cash flows to vary widely from period to period. Our commodity price risk management strategies may not be sufficient to offset price volatility risk and, in any event, do not cover all the throughput volumes. Moreover, derivative instruments are subject to inherent risks, which we describe in “–Our commodity price risk management strategies may fail to protect us and could reduce our gross margin and cash flow.”

 

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Our commodity price risk management strategies may fail to protect us and could reduce our gross margin and cash flow.

Our operations expose us to fluctuations in commodity prices. We utilize derivative contracts related to the future price of crude oil, natural gas and NGLs with the intent of reducing the volatility of our cash flows due to fluctuations in commodity prices. To the extent we protect our commodity prices using derivative contracts we may forego the benefits we would otherwise experience if commodity prices were to change in our favor. Our commodity price risk management activity may fail to protect or could harm us because, among other things:

 

    entering into derivative instruments can be expensive, particularly during periods of volatile prices;

 

    available derivative instruments may not correspond directly with the risks against which we seek protection;

 

    price relationship between the physical transaction and the derivative transaction could change;

 

    the anticipated physical transaction could be different than projected due to changes in contracts, lower production volumes or other operational impacts, resulting in possible losses on the derivative instrument, which are not offset by income on the anticipated physical transaction; and

 

    the party owing money in the derivative transaction may default on its obligation to pay.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could negatively impact our business.

We have historically experienced minimal collection issues with our counterparties; however our revenue and receivables are highly concentrated in a few key customers and therefore we are subject to risks of loss resulting from nonpayment or nonperformance by our key customers. In an attempt to reduce this risk, we have established credit limits for each counterparty and we attempt to limit our credit risk by obtaining letters of credit or other appropriate forms of security. Nonetheless, we have key customers whose credit risk cannot realistically be otherwise mitigated. Furthermore, although we evaluate the creditworthiness of our counterparties, we may not always be able to fully anticipate or detect deterioration in their creditworthiness and overall financial condition, which could expose us to an increased risk of nonpayment or other default under our contracts and other arrangements with them. Any material nonpayment or nonperformance by our key customers could impact our cash flow and ability to make required debt service payments and pay distributions.

Due to our lack of asset diversification, negative developments in our operations could reduce our ability to fund our operations, pay required debt service and make distributions to our common unitholders.

We rely primarily on the revenues generated from our gathering, processing and treating operations, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas, NGLs and condensate. Due to our lack of asset-type diversification, a negative development in this business could have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

 

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The amount of natural gas we gather will decline over time unless we are able to attract new wells to connect to our gathering systems.

Production of natural gas from a well generally declines over time until the well can no longer economically produce natural gas and is plugged and abandoned. Failure to connect new wells to our gathering systems could, therefore, result in the amount of natural gas we gather declining substantially over time and could, upon exhaustion of the current wells, cause us to abandon one or more of our gathering systems and, possibly, cease operations. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing wells not committed to other systems, the level of drilling activity near our gathering systems and our ability to attract natural gas producers away from our competitors’ gathering systems.

Over time, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. A decrease in exploration and development activities in the fields served by our gathering, processing and treating facilities could result if there is a sustained decline in natural gas, crude oil and/or NGL prices, which, in turn, would lead to a reduced utilization of these assets. The decline in the credit markets, the lack of availability of credit, debt or equity financing and the decline in commodity prices may result in a reduction of producers’ exploratory drilling. We have no control over the level of drilling activity in our service areas, the amount of reserves underlying wells that connect to our systems and the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, drilling costs, geological considerations, governmental regulation and the availability and cost of capital. In a low price environment, producers may determine to shut in wells already connected to our systems until prices improve. Because our operating costs are fixed to a significant degree, a reduction in the natural gas volumes we gather or process would result in a reduction in our gross margin and cash flow.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in reduced volumes available for us to gather and process.

Various federal and state initiatives are underway to regulate, or further investigate, the environmental impacts of hydraulic fracturing, a process that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. The adoption of any future federal, state or local laws or regulations imposing additional permitting, disclosure or regulatory obligations related to, or otherwise restricting or increasing costs regarding the use of, hydraulic fracturing could make it more difficult to drill certain oil and natural gas wells. As a result, the volume of natural gas we gather and process from producer wells in our service area that use hydraulic fracturing could be substantially reduced, which could adversely affect our gross margin and cash flow.

We currently depend on certain key producers for their supply of natural gas; the loss of any of these key producers could reduce our revenues.

During 2014, Atoka Midstream, LLC; Chesapeake Energy Corporation; COG Operating, LLC; DCP; Endeavor Energy Resources L.P.; Laredo Petroleum Inc.; Marathon Oil Company; MarkWest; Merit Management Partners; Parsley Energy, L.P.; Pioneer; SandRidge; Statoil; Talisman; Vanguard Natural Resources, LLC; and XTO accounted for a significant amount of our natural gas supply. If these producers reduce the volumes of natural gas they supply to us, our gross margin and cash flow could be reduced unless we obtain comparable supplies of natural gas from other producers.

 

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We may face increased competition in the future.

We face competition for well connections.

 

    DCP Midstream Partners, LLC; Enable Midstream Partners, L.P.; Energy Transfer Partners, L.P.; Kinder Morgan, Inc.; and ONEOK Partners L.P. operate competing gathering systems and processing plants in our SouthOK service areas.

 

    Caballo Energy, LLC; DCP Midstream Partners, LLC; Lumen Midstream Partners, LLC; Mustang Fuel Corporation; ONEOK Partners L.P.; SemGas, L.P.; and Superior Pipeline Company, LLC operate competing gathering systems and processing plants in our WestOK service area.

 

    DCP Midstream Partners, LLC; Energy Transfer Partners, L.P.; Enterprise Products Partners, L.P.; Kinder Morgan, Inc.; and Southcross Energy Partners, L.P. operate competing gathering systems and processing plants in our SouthTX service area.

 

    DCP Midstream Partners, LLC; Energy Transfer Partners, L.P.; Enlink Midstream Partners, LP; Southern Union Company; Targa Resources Partners L.P.; and West Texas Gas, Inc. operate competing gathering systems and processing plants in our WestTX service area.

Some of our competitors have greater financial and other resources than we do. If these companies become more active in our service areas, we may not be able to compete successfully with them in securing new well connections or retaining current well connections. In addition, customers who are significant producers of natural gas may develop their own gathering and processing systems in lieu of using those operated by us. If we do not compete successfully, the amount of natural gas we gather and process will decrease, reducing our gross margin and cash flow.

The amount of natural gas we gather or process may be reduced if the intrastate and interstate pipelines to which we deliver natural gas or NGLs cannot or will not accept the gas.

Our gathering systems principally serve as intermediate transportation facilities between wells connected to our systems and the intrastate or interstate pipelines to which we deliver natural gas. Our plant tailgate pipelines, including the Driver Residue Pipeline and the APL SouthTex Transmission Section 311 pipeline, provide essential links between our processing plants and intrastate and interstate pipelines that move natural gas to market. We deliver NGLs to intrastate or interstate pipelines at the tailgates of the plants. If one or more of the pipelines or fractionation facilities to which we deliver natural gas and NGLs has service interruptions, capacity limitations or otherwise cannot or do not accept natural gas or NGLs from us, and we cannot arrange for delivery to other pipelines or fractionation facilities, the amount of natural gas we gather and process may be reduced. Since our revenues depend upon the quantities of natural gas we gather and natural gas and NGLs we sell or transport, this could result in a material reduction in our gross margin and cash flow.

Failure of the natural gas or NGLs we deliver to meet the specifications of interconnecting pipelines could result in curtailments by the pipelines.

The pipelines to which we deliver natural gas and NGLs typically establish specifications for the products they are willing to accept. These specifications include requirements such as hydrocarbon dew point, compositions, temperature, and foreign content (such as water, sulfur, carbon dioxide, and hydrogen sulfide), and these specifications can vary by product or pipeline. If the total mix of a product that we deliver to a pipeline fails to meet the applicable product quality specifications, the pipeline may refuse to accept all or a part of the products scheduled for delivery to it or may invoice us for the costs to

 

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handle the out-of-specification products. In those circumstances, we may be required to find alternative markets for that product or to shut-in the producers of the non-conforming natural gas causing the products to be out of specification, potentially reducing our through-put volumes or revenues.

The success of our operations depends upon our ability to continually find and contract for new sources of natural gas supply.

Our agreements with most producers with which we do business generally do not require them to dedicate significant amounts of undeveloped acreage to our systems. While we do have some undeveloped acreage dedicated on our systems, most notably with our partner Pioneer on our WestTX system, we do not have assured sources to provide us with new wells to connect to our gathering systems. Failure to connect new wells to our operations, as described in “–The amount of natural gas we gather will decline over time unless we are able to attract new wells to connect to our gathering systems,” above, could reduce our gross margin and cash flow.

If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, our cash flow could be reduced.

We do not own all the land on which our pipelines are constructed. We obtain the rights to construct and operate our pipelines on land owned by third parties. In some cases, these rights expire at a specified time. Therefore we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations and financial condition. We may be unable to obtain rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, then our cash flow could be reduced.

A change in the regulations related to a state’s use of eminent domain could inhibit our ability to secure rights-of way for future pipeline construction projects.

Certain states where we operate are considering the adoption of laws and regulations that would limit or eliminate a state’s ability to exercise eminent domain over private property. This, in turn, could make it more difficult or costly for us to secure rights-of-way for future pipeline construction and other projects. Further, states may amend their procedures for certain entities within the state to use eminent domain.

The scope and costs of the risks involved in making acquisitions may prove greater than estimated at the time of the acquisition.

Any acquisition involves potential risks, including, among other things:

 

    the risk that reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

 

    mistaken assumptions about revenues and costs, including synergies;

 

    significant increases in our indebtedness and working capital requirements;

 

    delays in obtaining any required regulatory approvals or third party consents;

 

    the imposition of conditions on any acquisition by a regulatory authority;

 

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    an inability to integrate successfully or timely the businesses we acquire;

 

    the assumption of unknown liabilities;

 

    limitations on rights to indemnity from the seller;

 

    the diversion of management’s attention from other business concerns;

 

    increased demands on existing personnel;

 

    customer or key employee losses at the acquired businesses; and

 

    the failure to realize expected growth or profitability.

The scope and cost of these risks may ultimately be materially greater than estimated at the time of the acquisition. Further, our future acquisition costs may be higher than those we have achieved historically. Any of these factors could adversely impact our future growth and our ability to make or increase distributions.

We may be unsuccessful in integrating the operations from acquisitions with our operations and in realizing all the anticipated benefits of these acquisitions.

Our integration of previously independent operations, with our own can be a complex, costly and time-consuming process. The difficulties of combining these systems with existing systems include, among other things:

 

    operating a significantly larger combined entity;

 

    the necessity of coordinating geographically disparate organizations, systems and facilities;

 

    integrating personnel with diverse business backgrounds and organizational cultures;

 

    consolidating operational and administrative functions;

 

    integrating pipeline safety-related records and procedures;

 

    integrating internal controls, compliance under Sarbanes-Oxley Act of 2002 and other corporate governance matters;

 

    the diversion of management’s attention from other business concerns;

 

    customer or key employee loss from the acquired businesses;

 

    a significant increase in our indebtedness; and

 

    potential environmental or regulatory liabilities and title problems.

Our investment and the additional overhead costs we incur to grow our business may not deliver the expected incremental volume or cash flow. Costs incurred and liabilities assumed in connection with the acquisition and increased capital expenditures and overhead costs incurred to expand our operations could harm our business or future prospects, and result in significant decreases in our gross margin and cash flow.

 

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Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal and economic risks, which could impair our results of operations and financial condition.

We are actively growing our business through the construction of new assets. The construction of additions or modifications to our existing systems and facilities, and the construction of new assets, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. If endangered species are located in areas where we propose to construct new gathering or processing facilities, such work could be prohibited or delayed or expensive mitigation may be required. Any projects we undertake may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand a gathering system, the construction may occur over an extended period of time, and we will not receive any material increase in revenues until the project is completed. Moreover, we are constructing facilities to capture anticipated future growth in production in a region in which growth may not materialize. Since we are not engaged in the exploration for, and development of, natural gas reserves, we often do not have access to estimates of potential reserves in an area before constructing facilities in the area. To the extent we rely on estimates of future production in our decision to construct additions to our systems, the estimates may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could impair our results of operations and financial condition. In addition, our actual revenues from a project could materially differ from expectations as a result of the volatility in the price of natural gas, the NGL content of the natural gas processed and other economic factors described in this section.

We continue to expand the natural gas gathering systems surrounding our facilities in order to maximize plant throughput. In addition to the risks discussed above, expected incremental revenue from recent projects could be reduced or delayed due to the following reasons:

 

    difficulties in obtaining capital for additional construction and operating costs;

 

    difficulties in obtaining permits or other regulatory or third-party consents;

 

    additional construction and operating costs exceeding budget estimates;

 

    revenue being less than expected due to lower commodity prices or lower demand;

 

    difficulties in obtaining consistent supplies of natural gas; and

 

    terms in operating agreements that are not favorable to us.

We may not be able to execute our growth strategy successfully.

Our strategy contemplates substantial growth through both the acquisition of other gathering systems and processing assets and the expansion of our existing gathering systems and processing assets. Our growth strategy through acquisitions involves numerous risks, including:

 

    we may not be able to identify suitable acquisition candidates;

 

    we may not be able to make acquisitions on economically acceptable terms for various reasons, including limitations on access to capital and increased competition for a limited pool of suitable assets;

 

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    our costs in seeking to make acquisitions may be material, even if we cannot complete any acquisition we have pursued;

 

    irrespective of estimates at the time we make an acquisition, the acquisition may prove to be dilutive to earnings and operating surplus;

 

    we may encounter delays in receiving regulatory approvals or may receive approvals that are subject to material conditions;

 

    we may encounter difficulties in integrating operations and systems; and

 

    any additional debt we incur to finance an acquisition may impair our ability to service our existing debt.

Limitations on our access to capital or the market for our common units could impair our ability to execute our growth strategy.

Our ability to raise capital for acquisitions and other capital expenditures depends upon ready access to the capital markets. Historically, we have financed our acquisitions and expansions through bank credit facilities and the proceeds of public and private debt and equity offerings. If we are unable to access the capital markets, we may be unable to execute our growth strategy.

Our debt levels and restrictions in our revolving credit facility and the indentures governing our senior notes could limit our ability to fund operations and pay required debt service.

We have a significant amount of debt. We will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, which will reduce the funds that would otherwise be available for operations and future business opportunities. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing or delaying business activities, acquisitions, investments and/or capital expenditures; selling assets; restructuring or refinancing our indebtedness; or seeking additional equity capital or bankruptcy protection. We may not be able to affect any of these remedies on satisfactory terms, or at all.

Our revolving credit facility and the indentures governing our senior notes contain covenants limiting the ability to incur indebtedness, grant liens, engage in transactions with affiliates and make distributions to unitholders. Our revolving credit facility also contains covenants requiring us to maintain certain financial ratios and may limit our ability to capitalize on acquisitions and other business opportunities.

Increases in interest rates could adversely affect our unit price.

Credit markets are continuing to experience low interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units. A rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity or to incur debt to make acquisitions or for other purposes and could impact our ability to make cash distributions.

 

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An impairment of goodwill, long-lived assets, including intangible assets, and equity-method investments could reduce our earnings.

In connection with our acquisitions, we have recorded goodwill and identifiable intangible assets. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Long-lived assets, including intangible assets with finite useful lives, are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable. For the investments we account for under the equity method, the impairment test considers whether the fair value of the equity investment as a whole, not the underlying net assets, has declined and whether that decline is other than temporary. If we determine an impairment is indicated, we would be required to take an immediate noncash charge to earnings with a correlative effect on equity and balance sheet leverage as measured by debt to total capitalization. Although we have not experienced any other events or circumstances that indicate the carrying amounts of our other intangible assets and goodwill were impaired, we could experience future events that result in impairments. An impairment of the value of our existing goodwill and intangible assets could have a significant negative impact on our future operating results and could have an adverse impact on our ability to satisfy the financial ratios or other covenants under our existing or future debt agreements.

Regulation of our gathering operations could increase our operating costs; decrease our revenue; or both.

Our gathering and processing of natural gas is exempt from regulation by FERC, under the Natural Gas Act of 1938. While gas transmission activities conducted through our plant tailgate pipelines, such as the Driver Residue Pipeline and the SouthTX Residue Pipeline, are subject to FERC’s Natural Gas Act, FERC may limit the extent to which it regulates those activities. The way we operate, the implementation of new laws or policies (including changed interpretations of existing laws) or a change in facts relating to our plant tailgate pipeline operations could subject our operations to more extensive regulation by FERC under the Natural Gas Act, the Natural Gas Policy Act, or other laws. Any such regulation could increase our costs; decrease our gross margin and cash flow, or both.

Even if our gathering and processing of natural gas is not generally subject to regulation under the Natural Gas Act, FERC regulation will still affect our business and the market for our products. FERC’s policies and practices affect a range of natural gas pipeline activities, including, for example, its policies on interstate natural gas pipeline open access transportation, ratemaking, capacity release, environmental protection and market center promotion, which indirectly affect intrastate markets. FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. We cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.

Since federal law generally leaves any economic regulation of natural gas gathering to the states, state and local regulations may also affect our business. Matters subject to such regulation include access, rates, terms of service and safety. For example, our gathering lines are subject to ratable take, common purchaser, and similar statutes in one or more jurisdictions in which we operate. Common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer, while ratable take statutes generally require gatherers to take, without discrimination, natural gas production that may be tendered to the gatherer for handling. Kansas, Oklahoma and Texas have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with respect to rates or terms of service. Should a complaint be filed with the Kansas Corporation Commission, Oklahoma Corporation Commission, or Texas Railroad

 

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Commission, or should one or more of these agencies become more active in regulating our industry, our revenues could decrease. Collectively, all of these statutes may restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Compliance with pipeline integrity regulations issued by the DOT and state agencies could result in substantial expenditures for testing, repairs and replacement.

DOT and state agency regulations require pipeline operators to develop integrity management programs for transportation pipelines located in “high consequence areas.” The regulations require operators to:

 

    perform ongoing assessments of pipeline integrity;

 

    identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

    improve data collection, integration and analysis;

 

    repair and remediate the pipeline as necessary; and

 

    implement preventative and mitigating actions.

While we do not believe the cost of implementing integrity management program testing along segments of our pipeline will have a material effect on our results of operations, the costs of any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program could be substantial.

Our midstream natural gas operations could incur significant costs if PHMSA adopts more stringent regulations governing our business.

On January 3, 2012, the Job Act was signed into law. The Act directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in natural gas and hazardous liquids pipeline safety rulemakings. These rulemakings will be conducted by PHMSA.

Since passage of the Job Act, PHMSA has published several notices of proposed rulemaking which propose a number of changes to regulations governing the safety of gas transmission pipelines, gathering lines and related facilities, including increased safety requirements and increased penalties.

The adoption of regulations that apply more comprehensive or stringent safety standards to gathering lines could require us to install new or modified safety controls, incur additional capital expenditures, or conduct maintenance programs on an accelerated basis. Such requirements could result in our incurrence of increased operational costs that could be significant; or if we fail to, or are unable to, comply, we may be subject to administrative, civil and criminal enforcement actions, including assessment of monetary penalties or suspension of operations, which could have a material adverse effect on our financial position or results of operations and our ability to make distributions to our unitholders.

Our midstream natural gas operations may incur significant costs and liabilities resulting from a failure to comply with new or existing environmental regulations or a release of regulated materials into the environment by us or the producers in our service areas.

The operations of our gathering systems, plants and other facilities, as well as the operations of the producers in our service areas, are subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact our business

 

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activities in many ways, including restricting the manner in which we, and our producers, dispose of substances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with control requirements. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, increased cost of operations, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of regulated substances or wastes into the environment.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations including releases of regulated substances into the environment, and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from (1) environmental cleanup, restoration costs and natural resource damages; (2) claims made by neighboring landowners and other third parties for personal injury and property damage; and (3) fines or penalties for related violations of environmental laws or regulations. Moreover, the possibility exists that stricter laws, regulations or enforcement policies, including those relating to emissions from production, processing and transmission activities, could significantly increase our compliance costs and the cost of any remediation that may become necessary. Producers in our service areas may curtail or abandon exploration and production activities if any of these regulations cause their operations to become uneconomical. We may not be able to recover some or any of these costs from insurance.

Climate change legislation or regulations at the international, federal and state levels restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for our midstream services.

In response to findings that emissions of carbon dioxide, methane, and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA adopted regulations under existing provisions of the federal Clean Air Act that require entities that produce certain gases to inventory, monitor and report such gases. Additionally, the EPA adopted rules to regulate GHG emissions through traditional major source construction and operating permit programs. The EPA confirmed the permitting thresholds established in a 2010 rule in July 2012. These permitting programs require consideration of and, if deemed necessary, implementation of best available control technology to reduce GHG emissions. In addition there are several international and state level initiatives and proposals addressing domestic and global climate issues. As a result, our operations could face additional costs for emissions control and higher costs of doing business.

Litigation or governmental regulation relating to environmental protection and operational safety may result in substantial costs and liabilities.

Our operations are subject to federal and state environmental laws under which owners of natural gas pipelines can be liable for clean-up costs and fines in connection with any pollution caused by their pipelines. We may also be held liable for clean-up costs resulting from pollution that occurred before our acquisition of a gathering system. In addition, we are subject to federal and state safety laws that dictate the type of pipeline, quality of pipe protection, depth of pipelines, methods of welding and other construction-related standards, as well as certain operations and maintenance practices. Any violation of environmental, construction or safety laws could impose substantial liabilities and costs on us.

 

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We are also subject to the requirements of OSHA, and comparable state statutes. Any violation of OSHA could impose substantial costs on us.

Oil and gas operators can be impacted by litigation brought against the agencies which regulate the oil and gas industry. The outcomes of such activities can impact our operations.

We cannot predict whether or in what form any new litigation or regulatory requirements might be enacted or adopted, nor can we predict our costs of compliance. In general, we expect new regulations would increase our operating costs and, possibly, require us to obtain additional capital to pay for improvements or other compliance actions necessitated by those regulations.

We are subject to operating and litigation risks that may not be covered by insurance.

Our operations are subject to all operating hazards and risks incidental to gathering, processing and treating natural gas and NGLs. These hazards include:

 

    damage to pipelines, plants, related equipment and surrounding properties caused by floods and other natural disasters;

 

    inadvertent damage from construction and farm equipment;

 

    leakage of natural gas, NGLs and other hydrocarbons;

 

    fires and explosions;

 

    other hazards, including those associated with high-sulfur content, or sour gas, that could also result in personal injury and loss of life, pollution and suspension of operations;

 

    nuisance and other landowner claims arising from our operations; and

 

    acts of terrorism directed at our pipeline infrastructure, production facilities and surrounding properties.

As a result, we may be a defendant in various legal proceedings and litigation arising from our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for our insurance policies could escalate in the future. Our existing insurance coverage does not cover all potential losses, costs, or liabilities and we could suffer losses in amounts in excess of our existing insurance coverage. Moreover, in some instances, insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers require broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability, for which we were not fully insured, our gross margin and cash flow would be materially reduced.

Catastrophic weather events may curtail operations at, or cause closure of, any of our processing plants, which could harm our business.

Our assets and operations can be adversely affected by hurricanes, floods, earthquakes, tornadoes and other natural phenomena and weather conditions, including extreme temperatures. If operations at any of our processing plants were to be curtailed, or closed, whether due to natural catastrophe, accident, environmental regulation, periodic maintenance, or for any other reason, our ability to process natural gas from the relevant gathering system and, as a result, our ability to extract and sell NGLs, would be harmed. If this curtailment or stoppage were to extend for more than a short period, our gross margin and cash flow could be materially reduced.

 

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Disruption due to political uncertainties, civil unrest or the threat of terrorist attacks has resulted in increased costs, and future war or risk of war may adversely impact our results of operations and our ability to raise capital.

Political uncertainties, civil unrest and terrorist attacks or the threat of terrorist attacks cause instability in the global financial markets and other industries, including the energy industry. Such disruptions could adversely affect our operations and the markets for our products and services, including through increased volatility in crude oil and natural gas prices, or the possibility that our infrastructure facilities, including pipelines, production facilities, and transmission and distribution facilities, could be direct targets, or indirect casualties, of an act of terror. In addition, instabilities in the financial and insurance markets caused by such disruptions may make it more difficult for us to access capital and may increase insurance premiums or make it difficult to obtain the insurance coverage that we consider adequate.

The loss of key personnel could adversely affect our ability to operate.

Our ability to manage and grow our business effectively may be adversely affected if we lose key management or operational personnel. We depend on the continuing efforts of our General Partner’s executive officers. The departure of any of these executive officers could have a significant negative impact on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, our ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow. Our ability to grow and to continue our current level of service to our customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

Risks Relating to Our Ownership Structure

ATLS and its affiliates have conflicts of interest and limited fiduciary responsibilities, which may permit it to favor its own interests to the detriment of our unitholders.

ATLS owns and controls our General Partner and also has a 5.5% limited partner interest in us. We do not have any employees and rely solely on employees of ATLS and its affiliates, who serve as our agents, including all the senior managers who operate our business. A number of officers and employees of ATLS also own interests in us. Conflicts of interest may arise between ATLS, our General Partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our General Partner may favor its own interests and the interests of its affiliates over our interests and the interests of our unitholders. These conflicts include, among others, the following situations:

 

    Employees of ATLS who provide services to us also devote time to the businesses of ATLS in which we have no economic interest. If these separate activities are greater than our activities, there could be material competition for the time and effort of the employees who provide services to our General Partner, which could result in insufficient attention to the management and operation of our business.

 

    Neither our partnership agreement nor any other agreement requires ATLS to pursue a future business strategy that favors us or to use our gathering or processing services. ATLS’ directors and officers have a fiduciary duty to make these decisions in the best interests of the unitholders of ATLS.

 

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    Our General Partner is allowed to take into account the interests of parties other than us, such as ATLS, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us.

 

    Our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates.

Conflicts of interest with ATLS and its affiliates, including the foregoing factors, could exacerbate periods of lower or declining performance, or otherwise reduce our gross margin and cash flow.

Cost reimbursements due to our General Partner may be substantial.

We reimburse ATLS, our General Partner and its affiliates, including officers and directors of ATLS, for all expenses they incur on our behalf. Our General Partner has sole discretion to determine the amount of these expenses. In addition, ATLS provides us with services for which we are charged reasonable fees as determined by ATLS in its sole discretion. The reimbursement of expenses or payment of fees could adversely affect our ability to fund our operations and pay required debt service.

Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our General Partner or the managing board of our General Partner and have no right to elect our General Partner or the managing board of our General Partner on an annual or other continuing basis. The managing board of our General Partner is chosen by ATLS, the owner of 100% of the equity of our General Partner. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they have little ability to remove our General Partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our General Partner from transferring all or a portion of their respective ownership interest in our General Partner to a third party. The new owners of our General Partner would then be in a position to replace the managing board and officers of our General Partner with its own choices and thereby influence the decisions taken by the managing board and officers.

We may issue additional units without unitholder approval, which would dilute existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders, including units that rank senior to our common units as to quarterly cash distributions. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

    our existing unitholders’ proportionate ownership interest in us will decrease;

 

    the amount of cash available for distribution on each unit may decrease; and

 

    the market price of the common units may decline.

 

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We own and operate certain of our systems through joint ventures, and our control of such systems is limited by provisions of the agreements we have entered into with our joint venture partners and by our percentage ownership in such joint venture entities.

Certain of our joint ventures are structured so that a subsidiary of ours is the managing member of the limited liability company that owns the system being operated. However, the operational agreements applicable to such joint venture entities generally require consent of our joint venture partner for specified extraordinary transactions, such as admission of new members; engaging in transactions with our affiliates not approved by the company conflicts committee; incurring debt outside the ordinary course of business; and disposing of company assets above specified thresholds.

In addition, certain of our systems are operated by joint venture entities that we do not operate, or in which we do not have an ownership stake that permits us to control the business activities of the entity. We have limited ability to influence the business decisions of such joint venture entities, and we may be unable to control the amount of cash we will receive from the operation and could be required to contribute significant cash to fund our share of their operations, which could adversely affect our ability to distribute cash to our unitholders.

Tax Risks Relating to Unit Ownership

If we were treated as a corporation for federal income tax purposes, or if we were to become subject to a material amount of entity-level taxation for federal or state income tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.

We are currently treated as a partnership for federal income tax purposes, which requires that 90% or more of our gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy, and timber). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for federal income tax purposes or otherwise subject to federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. Distributions to our unitholders would generally be taxed again as corporate dividends, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Thus, treatment of us as a corporation would result in a material reduction in our anticipated cash flows, likely causing a substantial reduction in the value of our units.

Current tax law may change, causing us to be treated as a corporation for federal and/or state income tax purposes or otherwise subjecting us to entity level taxation. For example, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to our unitholders would be reduced. Furthermore, any modification to the federal income tax laws and interpretations thereof may or may not

 

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be applied retroactively and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income, adversely affect an investment in our common units or otherwise negatively impact the value of an investment in our common units.

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.

Unitholders may be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability, which results from the taxation of their share of our taxable income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If a unitholder sells their common units, they will recognize a gain or loss equal to the difference between the amount realized and the adjusted tax basis in those common units. Prior distributions and the allocation of losses, including depreciation deductions, to the unitholder in excess of the total net taxable income allocated to them, which decreased the tax basis in their common units, will, in effect, become taxable income to them if the common units are sold at a price greater than their tax basis in those common units, even if the price is less than the original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to the unitholder.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income.

We treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

The sale or exchange of 50% or more of our capital and profits interest within a 12-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in our capital and profits within a 12-month

 

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period. The termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholder with respect to that period.

Unitholders may be subject to state and local taxes and return filing requirements as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We presently anticipate substantially all of our income will be generated in Kansas, Oklahoma, and Texas. Kansas and Oklahoma currently imposes a personal income tax. We may do business or own property in other states in the future. It is the responsibility of each unitholder to file all United States federal, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

The IRS may challenge our tax treatment related to transfers of units, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely affected, and the costs of any such contest will reduce cash available for distributions to our unitholders.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our positions. A court may not agree with some or all of our positions. Any contest with the IRS may materially and adversely impact the market for our common units and the prices at which they trade. In addition, we will bear the costs of any contest with the IRS thereby reducing the cash available for distribution to our unitholders.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and our public unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we determine the fair market value of our assets and allocate any unrealized gain or loss attributable to such assets to the capital accounts of our unitholders and our General Partner. Although we may from time to time consult with professional appraisers regarding valuation matters, including the valuation of our assets, we make many of the fair market value estimates of our assets ourselves using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our General Partner, which may be unfavorable to such

 

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unitholders. Moreover, under our current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our General Partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Risks related to the Merger and ATLS Merger

Combining the two companies may be more difficult, costly, or time consuming than expected and the anticipated benefits and cost savings of the Merger may not be realized.

TRP and we have operated and, until the completion of the Merger, will continue to operate, independently. The success of the Merger, including anticipated benefits and cost savings, will depend, in part, on TRP’s ability to successfully combine and integrate our businesses. It is possible the pending nature of the Merger and/or the integration process could result in the loss of key employees; higher than expected costs; diversion of TRP’s and our management’s attention; increased competition; the disruption of either company’s ongoing businesses; or inconsistencies in standards, controls, procedures and policies that adversely affect the combined company’s ability to maintain relationships with customers, suppliers, employees and other business partners or to achieve the anticipated benefits and cost savings of the Merger. If TRP experiences difficulties with the integration process, the anticipated benefits of the Merger may not be realized fully or at all, or may take longer to realize than expected. Integration efforts between the two companies will also divert management’s attention and resources. These integration matters could have an adverse effect on each of us and TRP during this transition period and for an undetermined period after completion of the Merger on the combined company. In addition, the actual cost savings and other benefits of the Merger could be less than anticipated.

 

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The market price of TRP common units after the Merger will continue to fluctuate and may be affected by factors different from those affecting our common units currently.

Upon completion of the Merger, holders of our common units will become holders of TRP common units. The market price of TRP common units may fluctuate significantly following consummation of the Merger and holders of our common units could lose some or all of the value of their investment in TRP common units. In addition, the stock market has experienced significant price and volume fluctuations in recent times, which could have a material adverse effect on the market for, or liquidity of, the TRP common units, regardless of TRP’s actual operating performance. In addition, TRP’s business differs in important respects from ours, and accordingly, the results of operations of the combined company and the market price of TRP common units after the completion of the Merger may be affected by factors different from those currently affecting the independent results of our operations and TRP’s operations.

Sales of TRP common units before and after the completion of the Merger may cause the market price of TRP common units to fall.

The issuance of new TRP common units in connection with the Merger could have the effect of depressing the market price for TRP common units. In addition, holders of our common units may decide not to hold the TRP common units they will receive in the Merger. Such sales of TRP common units could have the effect of depressing the market price for TRP common units and may take place promptly following the Merger.

TRC, TRP and we are subject to litigation related to the Merger and ATLS Merger.

TRC, TRP and we have been subject to litigation related to the Merger and ATLS Merger (together the “Atlas Mergers”). Between October and December 2014, five of our public unitholders filed putative class action lawsuits, one of which has subsequently been voluntarily dismissed, against us, our General Partner, its managers, ATLS, TRC, TRP, TRP GP and MLP Merger Sub. In October and November 2014, two ATLS public unitholders filed putative class action lawsuits, one of which has subsequently been voluntarily dismissed, against ATLS, ATLS GP, its managers, TRC and GP Merger Sub. In January 2015, a public shareholder of TRC filed a putative class action and derivative suit against TRC, its directors and various other parties. The plaintiffs alleged a variety of causes of action challenging the Atlas Mergers. These matters, except for the January 2015 lawsuit and the two lawsuits that have been voluntarily dismissed, were settled, subject to court approval, pursuant to memoranda of understanding executed in February 2015. These memoranda of understanding are conditioned upon, among other things, the execution of appropriate stipulations of settlement. The stipulations of settlement will be subject to customary conditions, including, among other things, judicial approval of the proposed settlements contemplated by the memoranda of understanding. There can be no assurance that the parties will ultimately enter into stipulations of settlement, that the court will approve the settlements, that the settlements will not be terminated according to their terms or that some unitholders will not opt-out of the settlements. It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs, members of the putative classes they purport to represent or by others in an effort to enjoin the Atlas Mergers or seek monetary relief. We cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuits. An unfavorable resolution of any such litigation surrounding the Atlas Mergers could delay or prevent their consummation. In addition, the costs of defending the litigation, even if resolved in TRC, TRP or our favor, could be substantial and such litigation could distract TRC, TRP and us from pursuing the consummation of the Atlas Mergers and other potentially beneficial business opportunities. For additional information regarding this litigation, see “Item 3. Legal Proceedings.”

 

ITEM 1B: UNRESOLVED STAFF COMMENTS

Not applicable

 

ITEM 2: PROPERTIES

A description of our properties is contained within Item 1, “Business–Properties.

 

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ITEM 3. LEGAL PROCEEDINGS

We and our subsidiaries are party to various routine legal proceedings arising in the ordinary course of our business. We do not believe that any of these actions, individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations. See “Item 8: Financial Statements and Supplementary Data – Note 15”.

On October 13, 2014, we announced the transactions (the “Merger”) contemplated by the definitive Agreement and Plan of Merger (the “Merger Agreement”) between Atlas Pipeline Partners GP, LLC (our “General Partner”), Atlas Energy, L.P. (“ATLS”), Targa Resources Corp. (“TRC”), Targa Resources Partners LP (“TRP”), certain other parties and us. Concurrently with the Merger Agreement, ATLS announced that it had entered into a definitive merger agreement with TRC, pursuant to which TRC agreed to acquire ATLS through a merger of a newly formed wholly owned subsidiary of TRC with and into ATLS (the “ATLS Merger,” and, together with the Merger, the “Atlas Mergers”).

Following announcement of the Atlas Mergers, five (5) of our public unitholders filed putative class action lawsuits against us, the other parties to the Merger Agreement and certain of their managers. These lawsuits are styled (a) Michael Evnin v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; (b) William B. Federman Family Wealth Preservation Trust v. Atlas Pipeline Partners, L.P., et al., in the District Court of Tulsa County, Oklahoma; (the “Tulsa Lawsuit”) (c) Greenthal Living Trust U/A 01/26/88 v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; (d) Mike Welborn v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania; and (e) Irving Feldbaum v. Atlas Pipeline Partners, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania. The Evnin, Greenthal, Welborn and Feldbaum lawsuits have been consolidated as In re Atlas Pipeline Partners, L.P. Unitholder Litigation, Case No. GD-14-019245, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated APL Lawsuit”). The Tulsa Lawsuit was voluntarily dismissed on February 4, 2015.

Following announcement of the Atlas Mergers, two (2) public unitholders of ATLS also filed putative class action lawsuits against ATLS, ATLS Energy GP LLC, its managers, TRC and Trident GP Merger Sub LLC. These lawsuits are styled (a) Rick Kane v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania and (b) Jeffrey Ayers v. Atlas Energy, L.P., et al., in the Court of Common Pleas for Allegheny County, Pennsylvania. These lawsuits were consolidated as In re Atlas Energy, L.P. Unitholder Litigation, Case No. GD-14-019658, in the Court of Common Pleas for Allegheny County, Pennsylvania (the “Consolidated ATLS Lawsuit”), although the Kane lawsuit has since been voluntarily dismissed.

The lawsuits generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for the ATLS and our unitholders in, respectively, each of the ATLS Merger and the Merger, agreeing to certain terms in each of the merger agreements that allegedly restrict the defendants’ ability to obtain a more favorable offer, favoring their self-interests over the interests of ATLS and our unitholders, and omitting material information from the Proxy Statements. The lawsuits further allege that those breaches were aided and abetted by some combination of ATLS, TRC, TRP, us or various affiliates of those entities named above. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses, and costs.

 

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Additionally, a putative stockholder class action and derivative lawsuit, captioned Inspired Investors v. Perkins et. al., Cause No. 2015-04961, was filed purportedly on behalf of TRC shareholders in the District Court of Harris County, Texas on January 28, 2015 and amended on February 23, 2015. The lawsuit names ATLS and the individual members of the board of directors of TRC as defendants and TRC as a nominal defendant. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, approving the ATLS Merger, omitting purportedly material information from the registration statement on Form S-4 that TRC initially filed with the SEC on November 20, 2014 and most recently amended on January 22, 2015. The lawsuit seeks, among other things, injunctive relief, compensatory and rescissory damages, attorney’s fees, interest and costs.

On February 9, 2015, the defendants in the Consolidated APL Lawsuit reached an agreement with the plaintiffs regarding a settlement of that action. That agreement is reflected in a Memorandum of Understanding that outlines the terms of the parties’ agreement to settle, dismiss and release all claims which were or could have been asserted in the Consolidated APL Lawsuit, and is subject to court approval. Defendants agreed to the Memorandum of Understanding solely to avoid the uncertainty, risk, burden, and expense inherent in litigation and without admitting or denying that further supplemental disclosure is required under any applicable rule, statute, regulation or law. The Memorandum of Understanding is conditioned upon, among other things, the execution of an appropriate stipulation of settlement. The stipulation of settlement will be subject to customary conditions, including judicial approval of the proposed settlement contemplated by the Memorandum of Understanding, following notice to our unitholders. There can be no assurance that the parties will ultimately enter into a stipulation of settlement, that the court will approve the settlement, that the settlement will not be terminated according to its terms, or that some unitholders will not opt-out of the settlement.

In the event that the parties enter into a stipulation of settlement, a hearing will be scheduled at which the Court of Common Pleas for Allegheny County, Pennsylvania will consider the fairness, reasonableness, and adequacy of the proposed settlement. If the proposed settlement is finally approved by the court, it is anticipated that the settlement will result in a release of all claims that were or could have been brought by plaintiffs or any member of the putative class of our unitholders that they purport to represent challenging any aspect of or otherwise relating to the Transactions, any actions, deliberations or negotiations in connection with the Transactions or any agreements, disclosures, or events related thereto, and that the Consolidated APL Lawsuit will be dismissed with prejudice. In addition, in connection with the proposed settlement, the parties contemplate that plaintiffs’ counsel will file a petition for an award of attorneys’ fees and expenses, which the defendants may oppose. We or our successor will pay or cause to be paid those attorneys’ fees and expenses awarded by the court. The settlement will not affect the consideration to be paid to our unitholders in connection with the Merger.

On February 9, 2015, the defendants in the Consolidated ATLS Lawsuit reached an agreement with the plaintiffs regarding a settlement of that action. That agreement is reflected in a Memorandum of Understanding that outlines the terms of the parties’ agreement to settle, dismiss and release all claims which were or could have been asserted in the Consolidated ATLS Lawsuit, and is subject to court approval. Defendants agreed to the Memorandum of Understanding solely to avoid the uncertainty, risk, burden, and expense inherent in litigation and without admitting or denying that further supplemental disclosure is required under any applicable rule, statute, regulation or law. The Memorandum of Understanding is conditioned upon, among other things, the execution of an appropriate stipulation of settlement. The stipulation of settlement will be subject to customary conditions, including judicial approval of the proposed settlement contemplated by the Memorandum of Understanding, following notice to ATLS unitholders. There can be no assurance that the parties will ultimately enter into a stipulation of settlement, that the court will approve the settlement, that the settlement will not be terminated according to its terms, or that some unitholders will not opt-out of the settlement.

In the event that the parties enter into a stipulation of settlement, a hearing will be scheduled at which the Court of Common Pleas for Allegheny County, Pennsylvania will consider the fairness, reasonableness, and adequacy of the proposed settlement. If the proposed settlement is finally approved by the court, it is anticipated that the settlement will result in a release of all claims that were or could have been brought by plaintiffs or any member of the putative class of ATLS unitholders that they purport to represent challenging any aspect of or otherwise relating to the Transactions, any

 

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actions, deliberations or negotiations in connection with the Transactions or any agreements, disclosures, or events related thereto, and that the Consolidated ATLS Lawsuit will be dismissed with prejudice. In addition, in connection with the proposed settlement the parties contemplate that plaintiffs’ counsel will file a petition for an award of attorneys’ fees and expenses, which the defendants may oppose. ATLS or its successor will pay or cause to be paid those attorneys’ fees and expenses awarded by the court. The settlement will not affect, among other things, the consideration to be paid to ATLS’s unitholders in connection with the ATLS Merger.

 

ITEM 4: MINE SAFETY DISCLOSURE

Not applicable

 

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PART II

 

ITEM 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common limited partner units are listed on the New York Stock Exchange under the symbol “APL.” At the close of business on February 25, 2015, the closing price for our common units was $27.45 and there were 92 record holders, one of which is the holder for all beneficial owners who hold in street name.

The following table sets forth the range of high and low sales prices of our common limited partner units and distributions declared by quarter per unit on our common limited partner units for the years ended December 31, 2014 and 2013:

 

     High      Low      Distributions
Declared
 

2014

        

Fourth Quarter

   $ 37.96       $ 22.36       $ 0.64   

Third Quarter

     37.93         32.16         0.64   

Second Quarter

     34.58         30.55         0.63   

First Quarter

     35.62         28.88         0.62   

2013

        

Fourth Quarter

   $ 40.02       $ 32.50       $ 0.62   

Third Quarter

     40.06         35.07         0.62   

Second Quarter

     39.94         33.05         0.62   

First Quarter

     34.82         31.55         0.59   

Our Cash Distribution Policy

Our partnership agreement requires we distribute 100% of available cash, for each calendar quarter, to our General Partner and common limited partners within 45 days following the end of such calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

Our General Partner is granted discretion by our partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, rate refunds and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our General Partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

 

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Available cash is initially distributed 98% to our common limited partners and 2% to our General Partner. These distribution percentages are modified to provide for incentive distributions to be paid to our General Partner if quarterly distributions to common unitholders exceed specified targets, as follows:

 

Minimum Distributions
Per Unit Per Quarter

     Percent of Available
Cash in Excess of
Minimum Allocated

to General Partner(1)
$ 0.42       15%
  0.52       25%
  0.60       50%

 

(1) Percent allocated to our General Partner includes 2% general partner interest in addition to incentive distributions.

We make distributions of available cash to common unitholders regardless of whether the amount distributed is less than the minimum quarterly distribution. Incentive distributions are generally defined as all cash distributions paid to our General Partner that are in excess of 2% of the aggregate amount of cash being distributed. Our General Partner, the holder of all our incentive distribution rights, has agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to us after the General Partner receives the initial $7.0 million per quarter of incentive distribution rights. The General Partner’s incentive distributions paid for the years ended December 31, 2014 and 2013 were $22.7 million and $15.0 million, respectively.

For information concerning units authorized for issuance under our long-term incentive plans, see “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

 

ITEM 6: SELECTED FINANCIAL DATA

The following table should be read together with our consolidated financial statements and notes thereto included within “Item 8: Financial Statements and Supplementary Data” and “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this report. We have derived the selected financial data set forth in the table for each of the years ended December 31, 2014, 2013 and 2012 and at December 31, 2014 and 2013 from our consolidated financial statements appearing elsewhere in this report, which have been audited by Grant Thornton LLP, independent registered public accounting firm. We derived the financial data for the years ended December 31, 2011 and 2010 from our consolidated financial statements, which were audited by Grant Thornton LLP and are not included elsewhere within this report.

 

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     Years Ended December 31,  
     2014     2013     2012     2011     2010  
     (in thousands)  

Statements of operations data:

          

Revenue:

          

Natural gas and liquids sales

   $ 2,621,428      $ 1,959,144      $ 1,137,261      $ 1,268,195      $ 890,048   

Transportation, processing and other fees

     201,073        165,177        66,722        43,799        41,093   

Derivative gain (loss), net

     131,064        (28,764     31,940        (20,452     (5,945

Other income, net

     21,555        11,292        10,097        11,192        10,392   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  2,975,120      2,106,849      1,246,020      1,302,734      935,588   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

Natural gas and liquids cost of sales

  2,291,914      1,690,382      927,946      1,047,025      720,215   

Operating expenses

  113,606      94,527      62,098      55,519      49,731   

General and administrative(1)

  73,943      60,856      47,206      36,357      34,021   

Other expenses(2)

  6,073      20,005      15,069      1,040      —     

Depreciation and amortization

  202,543      168,617      90,029      77,435      74,897   

Interest

  93,147      89,637      41,760      31,603      87,273   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

  2,781,226      2,124,024      1,184,108      1,248,979      966,137   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Equity income (loss) in joint ventures

  (14,007   (4,736   6,323      5,025      4,920   

Gain (loss) on asset dispositions and other(3)

  47,381      (1,519   —        256,272      (10,729

Goodwill impairment loss

  —        (43,866   —        —        —     

Loss on early extinguishment of debt

  —        (26,601   —        (19,574   (4,359
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before tax

  227,268      (93,897   68,235      295,478      (40,717

Income tax expense (benefit)

  (2,376   (2,260   176      —        —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations

  229,644      (91,637   68,059      295,478      (40,717

Income (loss) from discontinued operations net of tax

  —        —        —        (81   321,155   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  229,644      (91,637   68,059      295,397      280,438   

Income attributable to non-controlling interests(4)

  (13,164   (6,975   (6,010   (6,200   (4,738

Preferred unit imputed dividend effect

  (45,513   (29,485   —        —        —     

Preferred unit dividends in kind

  (42,552   (23,583   —        —        —     

Preferred unit dividends

  (8,233   —        —        (389   (780
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners and the General Partner

$ 120,182    $ (151,680 $ 62,049    $ 288,808    $ 274,920   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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     Years Ended December 31,  
     2014      2013     2012      2011     2010  
     (in thousands, except per unit data)  

Allocation of net income (loss) attributable to:

            

Common limited partner interest:

            

Continuing operations

   $ 93,684       $ (165,923   $ 52,391       $ 281,449      $ (45,347

Discontinued operations

     —           —          —           (79     315,021   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 
  93,684      (165,923   52,391      281,370      269,674   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

General Partner interest:

Continuing operations

  26,498      14,243      9,658      7,440      (888

Discontinued operations

  —        —        —        (2   6,134   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 
  26,498      14,243      9,658      7,438      5,246   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Net income (loss) attributable to:

Continuing operations

  120,182      (151,680   62,049      288,889      (46,235

Discontinued operations

  —        —        —        (81   321,155   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 
$ 120,182    $ (151,680 $ 62,049    $ 288,808    $ 274,920   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Net income (loss) attributable to common limited partners per unit:

Basic:

Continuing operations

$ 0.95    $ (2.23 $ 0.95    $ 5.22    $ (0.85

Discontinued operations

  —        —        —        —        5.92   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 
$ 0.95    $ (2.23 $ 0.95    $ 5.22    $ 5.07   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Diluted(5):

Continuing operations

$ 0.95    $ (2.23 $ 0.95    $ 5.22    $ (0.85

Discontinued operations

  —        —        —        —        5.92   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 
$ 0.95    $ (2.23 $ 0.95    $ 5.22    $ 5.07   
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

 

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     Years Ended December 31,  
     2014     2013     2012     2011     2010  
     (in thousands)  

Balance sheet data (at period end):

          

Property, plant and equipment, net

   $ 3,249,973      $ 2,724,192      $ 2,200,381      $ 1,567,828      $ 1,341,002   

Total assets

     4,824,733        4,327,845        3,065,638        1,930,812        1,764,848   

Total debt, including current portion

     1,939,110        1,707,310        1,179,918        524,140        565,974   

Total equity

     2,518,467        2,259,905        1,606,408        1,236,228        1,041,647   

Cash flow data:

          

Net cash provided by (used in):

          

Operating activities

   $ 292,529      $ 210,844      $ 174,638      $ 102,867      $ 106,427   

Investing activities

     (524,339     (1,443,083     (1,006,641     67,763        594,753   

Financing activities

     234,999        1,233,755        835,233        (170,626     (702,037

Other financial data (unaudited):

          

Gross margin from continuing operations (6)

   $ 536,475      $ 434,188      $ 278,148      $ 264,923      $ 210,580   

EBITDA (7)

     522,958        164,357        200,024        404,435        443,212   

Adjusted EBITDA (7)

     382,024        324,870        220,207        181,026        209,799   

Distributable cash flow (7)

     256,297        203,863        146,013        129,938        86,871   

Maintenance capital expenditures

   $ 25,680      $ 21,919      $ 19,021      $ 18,247      $ 10,921   

Expansion capital expenditures (8)

     622,067        428,641        354,512        227,179        35,715   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total capital expenditures

$ 647,747    $ 450,560    $ 373,533    $ 245,426    $ 46,636   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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     Years Ended December 31,  
     2014      2013      2012      2011      2010  

Operating data (unaudited):

              

Oklahoma

              

SouthOK system(9):

              

Gathered gas volume (MCFD)

     435,455         406,073         350,593         103,328         84,455   

Processed gas volume (MCFD)

     409,741         378,732         325,453         98,126         78,606   

Residue gas volume (MCFD)

     374,342         324,025         275,315         80,330         64,138   

NGL volume (BPD)

     29,033         35,088         29,988         11,433         9,218   

Condensate volume (BPD)

     662         525         531         423         416   

WestOK system:

              

Gathered gas volume (MCFD)

     570,800         500,756         369,035         268,329         228,684   

Processed gas volume (MCFD)

     542,960         475,441         348,041         254,397         214,695   

Residue gas volume (MCFD)

     497,170         438,611         322,751         230,907         193,200   

NGL volume (BPD)

     25,357         20,971         14,505         13,635         12,395   

Condensate volume (BPD)

     2,475         1,887         1,360         898         697   

Texas

              

SouthTX system:

              

Gathered gas volume (MCFD)

     120,506         132,826         N/A         N/A         N/A   

Processed gas volume (MCFD)

     118,712         131,745         N/A         N/A         N/A   

Residue gas volume (MCFD)

     95,678         105,207         N/A         N/A         N/A   

NGL volume (BPD)

     14,523         16,711         N/A         N/A         N/A   

Condensate volume (BPD)

     158         77         N/A         N/A         N/A   

WestTX system(9):

              

Gathered gas volume (MCFD)

     480,722         357,524         275,946         212,775         178,111   

Processed gas volume (MCFD)

     460,823         328,678         249,221         196,412         163,475   

Residue gas volume (MCFD)

     340,212         244,294         179,539         133,857         105,982   

NGL volume (BPD)

     59,807         41,920         32,314         29,052         26,678   

Condensate volume (BPD)

     1,911         1,657         1,524         1,500         1,289   

Barnett system:

              

Average throughput volumes (MCFD)

     20,133         21,356         22,935         N/A         N/A   

 

(1) Includes non-cash compensation (income) expense of $25.1 million, $19.3 million, $11.6 million, $3.3 million and $3.5 million for the years ended December 31, 2014, 2013, 2012, 2011 and 2010, respectively; and includes compensation reimbursement to affiliates.
(2) Includes acquisition costs in connection with the Targa Resources LP Merger for the year ended December 31, 2014 (see “Item 8. Financial Statements and Supplementary Data – Note 3”) and the TEAK and Cardinal Acquisitions for the years ended December 31, 2013 and 2012, respectively (see “Item 8. Financial Statements and Supplementary Data – Note 4”).
(3) Includes the gain on sale of two subsidiaries in 2014 which held an aggregate 20% interest in WTLPG (see “Item 8. Financial Statements and Supplementary Data – Note 5”) and the gain on sale of our 49% non-controlling interest in Laurel Mountain in 2011.
(4) Represents Anadarko Petroleum Corporation’s (“Anadarko” – NYSE: APC) non-controlling interest in the operating results of the WestOK and WestTX systems and MarkWest Oklahoma Gas Company, LLC’s (“MarkWest”) non-controlling interest in Centrahoma Processing, LLC (“Centrahoma”).
(5) For the years ended December 31, 2013 and 2010, approximately 1,240,000 and 300,000 phantom units, respectively, were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such phantom units would have been anti-dilutive. For the year ended December 31, 2013, approximately 9,110,000 Class D Preferred Units were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such preferred units would have been anti-dilutive. For the year ended December 31, 2010, 75,000 unit options were excluded from the computation of diluted earnings attributable to common limited partners per unit because the inclusion of such unit options would have been anti-dilutive.

 

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(6) We define gross margin from continuing operations as natural gas and liquids sales revenue plus transportation, processing and other fees less natural gas and liquids cost of sales, subject to certain non-cash adjustments. Natural gas and liquids cost of sales include the cost of natural gas, NGLs and condensate we purchase from third parties. Gross margin, as we define it, does not include operating expenses and derivative gain (loss) related to undesignated hedges, as movements in gross margin generally do not result in directly correlated movements in these categories. Operating expenses generally include the costs required to operate and maintain our pipelines and processing facilities, including salaries and wages, repair and maintenance expense, real estate taxes and other overhead costs. Our management views gross margin as an important performance measure of core profitability for our operations and as a key component of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses. The following table reconciles net income (loss) to gross margin from continuing operations (in thousands):

RECONCILIATION OF GROSS MARGIN FROM CONTINUING OPERATIONS

 

     Years Ended December 31,  
     2014     2013     2012     2011     2010  
     (in thousands)  

Net income (loss)

   $ 229,644      $ (91,637   $ 68,059      $ 295,397      $ 280,438   

Derivative (gain) loss, net

     (131,064     28,764        (31,940     20,452        5,340   

Other income, net

     (21,555     (11,292     (10,097     (11,192     (9,787

Operating expenses(10)

     119,679        114,532        77,167        56,559        49,731   

General and administrative(1)

     73,943        60,856        47,206        36,357        34,021   

Depreciation and amortization

     202,543        168,617        90,029        77,435        74,897   

Interest

     93,147        89,637        41,760        31,603        87,273   

Income tax expense (benefit)

     (2,376     (2,260     176        —          —     

Equity (income) loss in joint ventures

     14,007        4,736        (6,323     (5,025     (4,920

(Gain) loss on asset dispositions and other(3)

     (47,381     1,519        —          (256,272     10,729   

Goodwill impairment loss

     —          43,866        —          —          —     

Loss on early extinguishment of debt

     —          26,601        —          19,574        4,359   

Non-cash linefill (gain) loss (11)

     5,888        249        2,111        (46     (346

(Income) loss from discontinued operations

     —          —          —          81        (321,155
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Gross margin from continuing operations

$ 536,475    $ 434,188    $ 278,148    $ 264,923    $ 210,580   
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(7) The following table reconciles net income (loss) to EBITDA; EBITDA to Adjusted EBITDA; and Adjusted EBITDA to Distributable Cash Flow (See “Item 7. Management’s Discussion and Analysis –How We Evaluate Our Operations” for definitions of our Non-GAAP financial information) (in thousands):

 

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RECONCILIATION OF EBITDA, ADJUSTED EBITDA AND DISTRIBUTABLE CASH FLOW

 

     Years Ended December 31,  
     2014     2013     2012     2011     2010  
     (in thousands)  

Net income (loss)

   $ 229,644     $ (91,637   $ 68,059     $ 295,397     $ 280,438  

Adjustments:

          

Interest expense(12)

     93,147       89,637       41,760       31,603       87,877  

Income tax expense (benefit)

     (2,376     (2,260     176       —          —     

Depreciation and amortization

     202,543       168,617       90,029       77,435       74,897  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

  522,958     164,357     200,024     404,435     443,212  

Adjustments:

Income attributable to non-controlling interests from continuing operations(4)

  (13,164   (6,975   (6,010   (6,200   (4,738

Non-controlling interest depreciation, amortization and interest expense(13)

  (3,672   (2,778   —        —        —     

Equity (income) loss in joint ventures

  14,007     4,736     (6,323   (5,025   (4,920

Distributions from joint ventures

  5,264     7,400     7,200     4,448     11,066  

(Gain) loss on asset dispositions and other(14)

  (47,381   1,519     —        (256,191   (301,373

Goodwill impairment loss

  —        43,866     —        —        —     

Loss on early extinguishment of debt

  —        26,601     —        19,574     4,359  

Non-cash (gain) loss on derivatives

  (141,025   28,440     (23,283   4,538     (10,166

Premium expense on derivative instruments

  6,500     17,083     17,759     12,219     21,123  

Unrecognized economic impact of acquisitions(15)

  —        1,023     1,698     —        —     

Other expenses(2)

  6,073     20,005     15,395     —        —     

Net cash derivative early termination expense(16)

  —        —        —        —        22,401  

Non-cash compensation expense

  25,116     19,344     11,636     3,274     3,484  

Non-cash linefill (gain) loss (11)

  5,888     249     2,111     (46   (346

Minimum volume adjustment

  1,460     —        —        —        —     

Discontinued operations adjustments(17)

  —        —        —        —        25,697  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  382,024     324,870     220,207     181,026     209,799  

Adjustments:

Interest expense(18)

  (93,147   (89,637   (41,760   (31,603   (87,835

Preferred dividend obligation

  (8,233   —        —        (389   (780

Amortization of deferred finance costs

  7,082     6,965     4,672     4,480     6,186  

Proceeds remaining from asset sale(19)

  —        —        —        5,850     —     

Premium expense on derivative instruments(18)

  (6,500   (17,083   (17,759   (12,219   (28,320

Other costs

  —        —        (326   1,040     —     

Maintenance capital, net(20)

  (24,929   (21,252   (19,021   (18,247   (12,179
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Distributable Cash Flow

$ 256,297   $ 203,863   $ 146,013   $ 129,938   $ 86,871  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(8) Represents total expansion capital expenditures which includes the portion attributable to our joint interest partners.
(9) Operating data for SouthOK and WestTX represents 100% of the operating activity for these systems. SouthOK gathered volumes include volumes gathered by MarkWest and processed through the Arkoma facilities.
(10) Operating expenses include operating expenses and other expenses.
(11) Represents the non-cash impact of commodity price movements on pipeline linefill.

 

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(12) Interest expense in 2010 includes interest expense related to interest rate swaps.
(13) Represents the depreciation, amortization and interest expense included in income attributable to non-controlling interest for MarkWest interest in Centrahoma.
(14) For the year ended December 31, 2014, includes the gain on sale of two subsidiaries which held an aggregate 20% interest in WTLPG (see “Item 8. Financial Statements and Supplementary Data – Note 5”). For the year ended December 31, 2011, includes the gain on the sale of our non-controlling interest in Laurel Mountain. For the year ended December 31, 2010, includes the gain on the sale of Elk City gathering system and related processing facilities and expenses related to the sale of our non-controlling interest in Laurel Mountain.
(15) Represents the earnings from the (a) TEAK Acquisition (see “Item 8. Financial Statements and Supplementary Data – Note 4”) from April 1, 2013, the effective date of the purchase, through May 7, 2013, the closing date of the purchase, and (b) the Cardinal Acquisition from December 1, 2012, the effective date of the purchase, through December 20, 2012, the closing date of the purchase. These earnings were recorded as a reduction of the purchase price of each respective acquisition.
(16) During the year ended December 31, 2010, we made net payments of $33.7 million, which resulted in a net cash expense recognized of $33.7 million related to the early termination of derivative contracts principally entered into as proxy hedges for the prices received on the ethane and propane portion of our NGL equity volume.
(17) Includes depreciation, amortization, and interest expense; non-cash (gain) loss on derivatives; non-recurring cash derivative early termination; and premium expense on derivative instruments recorded in discontinued operations.
(18) For the year ended December 31, 2010, includes amounts recorded within discontinued operations.
(19) Net proceeds remaining from the sale of Laurel Mountain Midstream, LLC after repayment of the amount outstanding on our revolving credit facility, redemption of our 8.125% Senior Notes due 2015 and purchase of the 8.75% Senior Notes due 2018.
(20) Net of non-controlling interest maintenance capital of $752 thousand and $667 thousand for the years ended December 31, 2014 and 2013, respectively.

 

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

The following discussion provides information to assist in understanding our financial condition and results of operations. This discussion should be read in conjunction with our consolidated financial statements and related notes thereto appearing elsewhere in this report.

General

We are a publicly-traded Delaware limited partnership formed in 1999 whose common units are listed on the New York Stock Exchange under the symbol “APL” and Class E cumulative redeemable perpetual preferred units (“Class E Preferred Units”) are listed under the symbol “APLPE.”

We conduct our business in the midstream segment of the natural gas industry through two reportable segments: Oklahoma Gathering and Processing (“Oklahoma”) and Texas Gathering and Processing (“Texas”).

As a result of the May 2014 sale of two former subsidiaries holding an interest in West Texas LPG Pipeline Limited Partnership (“WTLPG”) (see “–Recent Events”), we realigned the management of our business from our previously reportable segments of “Gathering and Processing” and “Transportation and Treating” into the two new reportable segments.

The Oklahoma segment consists of our SouthOK and WestOK operations, which are comprised of natural gas gathering, processing and treating assets servicing drilling activity in the Anadarko, Ardmore and Arkoma Basins. These operations were formerly included with the previous Gathering and Processing segment. Revenues are primarily derived from the sale of residue gas and NGLs and the gathering, processing and treating of natural gas within the state of Oklahoma.

The Texas segment consists of (1) our SouthTX and WestTX operations, which are comprised of natural gas gathering and processing assets servicing drilling activity in the Permian Basin and the Eagle Ford Shale play in southern Texas; and (2) natural gas gathering assets located in the Barnett Shale play in Texas. These assets were formerly included with the previous Gathering and Processing segment. Revenues are primarily derived from the sale of residue gas and NGLs and the gathering and processing of natural gas within the state of Texas.

The previous Transportation and Treating segment, which consisted of (1) our gas treating operations, which own contract gas treating facilities located in various shale plays; and (2) the former subsidiaries’ interest in WTLPG, which was sold in May 2014 (see “–Recent Events”). This segment has been eliminated and the financial information is now included within Corporate and Other. On February 27, 2015, we agreed to transfer 100% of our interest in natural the gas gathering assets located in the Appalachian Basin in Tennessee to our affiliate, Atlas Resource Partners, L.P. (NYSE: ARP) (“ARP”) (see “–Subsequent Events”). Our Tennessee gathering assets were formerly included in the previous Gathering and Processing Segment, but are now included within Corporate and Other.

As of December 31, 2014, our Oklahoma segment owns and has interests in 10 natural gas processing plants with aggregate capacity of approximately 1,000 MMCFD, a gas treating facility and approximately 7,600 miles of active natural gas gathering systems located in Oklahoma and Kansas. As of December 31, 2014, our Texas segment owns and has interests in seven natural gas processing plants with aggregate capacity of approximately 1,050 MMCFD and approximately 4,600 miles of active natural

 

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gas gathering systems located in Texas. Our gathering systems have receipt points consisting primarily of individual well connections and, secondarily, central delivery points, which are linked to multiple wells from which we gather natural gas from oil and natural gas wells; process the raw natural gas into residue gas by extracting NGLs and removing impurities; and transport natural gas to interstate and public utility pipelines for delivery to customers.

Our Oklahoma and Texas segments are all located in or near areas of abundant and long-lived natural gas production. In Oklahoma, our operations are in or near the Golden Trend, Mississippian Limestone and Hugoton field in the Anadarko Basin, the South Central Oklahoma Oil Province (“SCOOP”) play in the Ardmore Basin and the Woodford Shale play in the Arkoma Basin. In Texas, our operations are in or near the Spraberry and Wolfberry Trends, which are oil plays with associated natural gas in the Permian Basin; the Barnett Shale; and the Eagle Ford Shale. We believe we have significant scale in each of our primary service areas. We provide gathering, processing and treating services to the wells connected to our systems, primarily under long-term contracts. As a result of the location and capacity of our gathering, processing and treating assets, we believe we are strategically positioned to capitalize on the drilling activity in our service areas.

Recent Events

In December 2014, we completed the connection between the Velma and Arkoma systems within the SouthOK system. The connection accommodates the increased demand for processing capacity behind the Velma system, where the emerging SCOOP play has attracted significant producer interest. The connection between Velma and Arkoma offers us more operational flexibility and helps us better utilize our processing capacity across the SouthOK system.

On October 13, 2014, Atlas Energy, L.P. (“ATLS”), Atlas Pipeline Partners GP, LLC, (the “General Partner”), and we entered into a definitive merger agreement with Targa Resources Corp. (“TRC”), Targa Resources Partners, LP (“TRP”) and certain other parties (the “Merger Agreement”), pursuant to which TRP agreed to acquire us through a merger of a newly-formed, wholly-owned subsidiary of TRP with and into us (the “Merger”). Upon completion of the Merger, holders of our common units will have the right to receive (i) 0.5846 TRP common units and (ii) $1.26 in cash for each of our common units.

Concurrently with the Merger Agreement, ATLS announced that it entered into a definitive merger agreement with TRC (the “ATLS Merger Agreement”), pursuant to which TRC agreed to acquire ATLS through a merger of a newly formed wholly-owned subsidiary of TRC with and into ATLS (the “ATLS Merger”). Upon completion of the ATLS Merger, holders of ATLS common units will have the right to receive (i) 0.1809 TRC shares of common stock, par value $0.001 per share, and (ii) $9.12 in cash, without interest, for each ATLS common unit.

Concurrently with the Merger Agreement and the ATLS Merger Agreement, ATLS agreed to (i) transfer its assets and liabilities, other than those related to us, to Atlas Energy Group, LLC (“Atlas Energy Group”), which is currently a subsidiary of ATLS and (ii) immediately prior to the ATLS Merger, effect a pro rata distribution to the ATLS unitholders of common units of Atlas Energy Group representing a 100% interest in Atlas Energy Group (the “Spin-Off”).

Following the announcement on October 13, 2014 of the Merger, we, our General Partner, ATLS, TRC, TRP, Targa Resources GP LLC, Trident MLP Merger Sub LLC and the members of our General Partner’s board of directors were named as defendants in five putative unitholder class action lawsuits challenging the Merger, one of which has subsequently been voluntarily dismissed. In addition, ATLS, Atlas Energy GP LLC (“ATLS GP”), TRC, Trident GP Merger Sub LLC and members of ATLS GP’s board of directors were named as defendants in two putative unitholder class action lawsuits challenging the ATLS Merger, one of which has subsequently been voluntarily dismissed. The lawsuits

 

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filed generally allege that the individual defendants breached their fiduciary duties and/or contractual obligations by, among other things, failing to obtain sufficient value for our unitholders and ATLS unitholders, respectively, in the Merger and ATLS Merger. The plaintiffs seek, among other things, injunctive relief, unspecified compensatory and/or rescissory damages, attorney’s fees, other expenses and costs.

ATLS has also been named as a defendant in a putative class action and derivative lawsuit brought on January 28, 2015 and amended on February 23, 2015, by a shareholder of TRC against TRC and its directors. The lawsuit generally alleges that the individual defendants breached their fiduciary duties by, among other things, approving the ATLS Merger and failing to disclose purportedly material information concerning the ATLS Merger. The lawsuit seeks, among other things, injunctive relief, compensatory and rescissory damages, attorney’s fees, interest and costs.

All of the above referenced lawsuits, except for the January 2015 lawsuit and the two lawsuits that have been voluntarily dismissed, were settled, subject to court approval, pursuant to memoranda of understanding executed in February 2015, which are conditioned upon, among other things, the execution of an appropriate stipulations of settlement. The stipulations of settlement will be subject to customary conditions, including, among other things, judicial approval of the proposed settlements contemplated by the memoranda of understanding. There can be no assurance that the parties will ultimately enter into stipulations of settlement, that the court will approve the settlements, that the settlements will not be terminated according to their terms or that some unitholders will not opt-out of the settlements.

At this time, we cannot reasonably estimate the range of possible loss as a result of the lawsuits. See “Item 3: Legal Proceedings” for more information regarding these lawsuits.

On September 15, 2014, we placed in service a new 200 MMCFD cryogenic processing plant, known as the Edward plant, in our WestTX system in the Permian Basin of West Texas, increasing the WestTX system capacity to 655 MMCFD.

On August 28, 2014, we entered into a Second Amended and Restated Credit Agreement (the “Revised Credit Agreement”) which, among other changes:

 

    extended the maturity date to August 28, 2019;

 

    increased the revolving credit commitment from $600 million to $800 million and the incremental revolving credit amount from $200 million to $250 million;

 

    reduced by 0.25% the applicable margin used to determine interest rates for LIBOR Rate Loans, as defined in the Revised Credit Agreement, and for Base Rate Loans, as defined in the Revised Credit Agreement, depending on the Consolidated Funded Debt Ratio, as defined in the Revised Credit Agreement;

 

    allows us to request incremental term loans, provided the sum of any revolving credit commitments and incremental term loans may not exceed $1.05 billion; and

 

    changed the per annum interest rate on borrowings to (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%, or (ii) the LIBOR rate for the applicable period, in each case plus the applicable margin.

On June 25, 2014, we placed in service a new 200 MMCFD cryogenic processing plant, known as the Silver Oak II plant, in our SouthTX system in the Eagle Ford Shale play of southern Texas, increasing the SouthTX system capacity to 400 MMCFD.

On May 14, 2014, we completed the sale of two subsidiaries, which held an aggregate 20% interest in WTLPG, to a subsidiary of Martin Midstream Partners L.P. (NYSE: MMLP). We received $131.0 million in proceeds, net of selling costs and working capital adjustments, which were used to pay down our revolving credit facility. As a result of the sale, we recorded a $47.8 million gain on asset dispositions on our consolidated statements of operations for the year ended December 31, 2014, respectively (see “Item 8. Financial Statements and Supplementary Data – Note 5 – West Texas LPG Pipeline Limited Partnership”).

 

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On May 12, 2014, we entered into an Equity Distribution Agreement (the “2014 EDA”) with Citigroup Global Markets Inc., Wells Fargo Securities, LLC and MLV & Co. LLC as sales agents. Pursuant to the 2014 EDA, we may offer and sell from time to time through our sales agents, common units having an aggregate value of up to $250.0 million. Sales are at market prices prevailing at the time of the sale. However, we are currently restricted from selling common units by the Merger Agreement. During the year ended December 31, 2014, we issued 3,558,005 common units under the 2014 EDA for proceeds of $121.6 million, net of $1.2 million in commissions paid to the sales agents (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Common Units”).

On May 1, 2014, we placed in service a new 120 MMCFD cryogenic processing plant, known as the Stonewall plant, in our SouthOK system in the Arkoma Basin of Oklahoma, increasing the SouthOK system capacity to 500 MMCFD. A planned expansion of the Stonewall plant to raise the processing capacity to 200 MMCFD is anticipated to be completed in the first quarter of 2015.

On March 17, 2014, we issued 5,060,000 of our 8.25% Class E Preferred Units to the public at an offering price of $25.00 per Class E Preferred Unit. We received $122.3 million in net proceeds, which were used to pay down the revolving credit facility (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Class E Preferred Units”).

Subsequent Events

On January 9, 2015, we declared a cash distribution of $0.64 per unit on our outstanding common limited partner units, representing the cash distribution for the quarter ended December 31, 2014. The $62.2 million distribution, including $8.1 million to the General Partner for its general partner interest and incentive distribution rights, was paid on February 13, 2015 to unitholders of record at the close of business on January 21, 2015 (see “Item 8. Financial Statements and Supplementary Data – Note 6 –Cash Distributions”).

On January 15, 2015, we paid a cash distribution of $0.515625 per unit, or approximately $2.6 million, on our Class E Preferred Units, representing the cash distribution for the period October 15, 2014 through January 14, 2015 (see “Item 8. Financial Statements and Supplementary Data – Note 6 –Class E Preferred Units”).

On January 15, 2015, TRP announced cash tender offers to redeem any and all of our outstanding $500.0 million aggregate principal amount of our 6.625% unsecured senior notes due October 1, 2020 (“6.625% Senior Notes”); $400.0 million aggregate principal amount of our 4.75% unsecured senior notes due November 15, 2021 (“4.75% Senior Notes”); and $650.0 million aggregate principal amount of our 5.875% unsecured senior notes due August 1, 2023 (“5.875% Senior Notes”). TRP made the cash tender offers in connection with, and conditioned upon, the consummation of the Merger (see “–Recent Events”). The Merger, however, is not conditioned on the consummation of the tender offers. On February 2, 2015, TRP announced as of January 29, 2015, it had received tenders pursuant to its previously announced cash tender offers on January 15, 2015 from holders representing:

 

    less than a majority of the total outstanding $500.0 million of our 6.625% Senior Notes;

 

    approximately 98.3% of the total outstanding $400.0 million of our 4.75% Senior Notes; and

 

    approximately 91.0% of the total outstanding $650.0 million of our 5.875% Senior Notes.

 

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Also on February 2, 2015, TRP announced a change of control cash tender offer for any and all of the outstanding $500.0 million of our 6.625% Senior Notes. TRP made the change of control cash tender offer in connection with, and conditioned upon, the consummation of the Merger (see “–Recent Events”). The Merger, however, is not conditioned on the consummation of the change in control cash tender offer. The change in control cash tender offer was made independently of TRP’s January 15, 2015 cash tender offers.

On January 22, 2015, we exercised our right under the certificate of designation of the Class D Preferred Units (“Class D Certificate of Designation”) to convert all outstanding Class D Preferred Units and unpaid distributions into common limited partner units, based upon the Execution Date Unit Price of $29.75 per unit, as defined by the Class D Certificate of Designation. As a result of the conversion, 15,389,575 common limited partner units were issued (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Class D Preferred Units”).

On January 27, 2015, we delivered notice of our intention to redeem all outstanding shares of our Class E Preferred Units. The redemption of the Class E Preferred Units will occur immediately prior to the close of the Merger (see “–Recent Events”). We expect the Merger to close on February 27, 2015 and, accordingly, the redemption would also be on February 27, 2015. The Class E Preferred Units will be redeemed at a redemption price of $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions on the Class E Preferred Units as of the redemption date. TRP has agreed to deposit the funds for such redemption with our paying agent (see “Item 8. Financial Statements and Supplementary Data – Note 6 –Class E Preferred Units”).

On February 20, 2015, we held a special meeting, where holders of a majority of our common units approved the Merger. In addition, at special meetings held on the same day: (i) a majority of the holders of ATLS common units approved the ATLS Merger and (ii) a majority of the holders of TRC common stock approved the issuance of TRC shares in connection with the Merger. Completion of each of the ATLS Merger and the Spin-Off are also conditioned on the parties standing ready to complete the Merger.

On February 27, 2015, we agreed to transfer 100% of our interest in the Tennessee gas gathering assets to our affiliate, ARP, for $1.0 million plus working capital adjustments, concurrent with the closing of the Merger on February 27, 2015.

Acquisitions

In May 2013, we completed the acquisition of 100% of the equity interests of TEAK Midstream, LLC (“TEAK”) for $974.7 million in cash, including final purchase price adjustments, less cash received (the “TEAK Acquisition”) (see “Item 8. Financial Statements and Supplementary Data – Note 4 – TEAK Midstream, LLC”). The assets acquired, which are referred to as the SouthTX assets, include the following gas gathering and processing facilities in the Eagle Ford shale region of southern Texas:

 

    the Silver Oak I plant, which is a 200 MMCFD cryogenic processing facility;

 

    a second 200 MMCFD cryogenic processing facility, the Silver Oak II plant, which was placed in service in June 2014 (see “–Recent Events);

 

    265 miles of primarily 20-24 inch gathering and residue lines;

 

    approximately 275 miles of low pressure gathering lines;

 

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    a 75% interest in T2 LaSalle Gathering Company L.L.C. (“T2 LaSalle”), which owns a 62 mile, 24-inch gathering line;

 

    a 50% interest in T2 Eagle Ford Gathering Company L.L.C. (“T2 Eagle Ford”), which owns a 45 mile, 16-inch gathering pipeline; a 71 mile 24-inch gathering line; and a 50 mile residue pipeline; and

 

    a 50% interest in T2 EF Cogeneration Holdings L.L.C. (“T2 Co-Gen”), which owns a cogeneration facility.

In December 2012, we acquired 100% of the equity interests held by Cardinal Midstream, LLC (“Cardinal”) in three wholly-owned subsidiaries for $598.9 million in cash, including final purchase price adjustments, less cash received (the “Cardinal Acquisition”) (see “Item 8. Financial Statements and Supplementary Data – Note 4 – Cardinal Midstream, LLC”). The assets of these companies represented the majority of the operating assets of Cardinal and include gas gathering, processing and treating facilities in Arkansas, Louisiana, Oklahoma and Texas (included within the SouthOK system) as follows:

 

    the Tupelo plant, which is a 120 MMCFD cryogenic processing facility;

 

    approximately 60 miles of gathering pipeline;

 

    the East Rockpile treating facility, a 250 GPM amine treating plant;

 

    a fixed fee contract gas treating business that includes 15 amine treating plants and two propane refrigeration plants; and

 

    a 60% interest in a joint venture known as Centrahoma Processing, LLC (“Centrahoma”). The remaining 40% interest is owned by MarkWest Oklahoma Gas Company, LLC, (“MarkWest”), a wholly-owned subsidiary of MarkWest Energy Partners, L.P. (NYSE: MWE). Centrahoma owns the following assets:

 

    the Coalgate and Atoka plants, which are cryogenic processing facilities with a combined current processing capacity of approximately 100 MMCFD;

 

    the Stonewall plant, which is a 160 MMCFD cryogenic processing facility that was under construction on the date of acquisition and subsequently placed in service in May 2014 (see “–Recent Events”); and

 

    15 miles of NGL pipeline.

In June 2012, we acquired a gas gathering system and related assets in the Barnett Shale in Tarrant County, Texas for an initial net purchase price of $18.0 million. The system is used to facilitate gathering of newly-acquired natural gas production of our affiliate, ARP. We do not directly gather natural gas for ARP; rather, we gather natural gas for a third party that purchases ARP’s production. ARP’s general partner is wholly-owned by ATLS, and two members of our General Partner’s managing board are members of ARP’s board of directors.

In February 2012, we acquired a gas gathering system and related assets at our WestOK system for an initial net purchase price of $19.0 million. We agreed to pay up to an additional $12.0 million, payable in two equal amounts, subject to delivery of certain minimum volumes of natural gas from a specified area and within certain specified time periods. Sufficient volumes were achieved in December 2012 and we paid the first contingent payment of $6.0 million in January 2013. In connection with this acquisition, we received assignment of the gas purchase agreements for natural gas then currently gathered on the acquired system.

 

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Disposition

On May 14, 2014, we completed the sale of two subsidiaries, which held an aggregate 20% interest in WTLPG (see “–Recent Events”).

Recent Trends and Uncertainties

The midstream natural gas industry links the exploration and production of natural gas and the delivery of its components to end-use markets; and provides natural gas gathering, compression, dehydration, treating, conditioning, processing, fractionation and transportation services. This industry group is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

We face competition in obtaining natural gas supplies for our processing and related services operations. Competition for natural gas supplies is based primarily on the location of gas gathering facilities and gas processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competition for customers is based primarily on price, delivery capabilities, quality of assets, flexibility, service history and maintenance of high-quality customer relationships. Many of our competitors operate as master limited partnerships and enjoy a cost of capital comparable to, and in some cases lower than, ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. We believe the primary difference between us and some of our competitors is that we provide an integrated and responsive package of midstream services, while some of our competitors provide only certain services. We believe offering an integrated package of services, while remaining flexible in the types of contractual arrangements we offer producers, allows us to compete more effectively for new natural gas supplies in our regions of operations.

Our results of operations and financial condition substantially depend upon the price of natural gas, NGLs and crude oil (see “Item 8. Financial Statements and Supplementary Data – Note 2 – Revenue Recognition”). We believe future natural gas prices will be influenced by supply deliverability, the severity of winter and summer weather and the level of United States economic growth. Based on historical trends, we generally expect NGL prices to follow changes in crude oil prices over the long term, which we believe will in large part be determined by the level of production from major crude oil exporting countries and the demand generated by growth in the world economy. Crude oil prices have declined significantly during the last half of 2014 primarily due to rising levels of crude oil production in the U.S. and around the world, combined with weaker global demand for crude oil. A sustained decline in the price of crude oil may negatively impact drilling activities in our service areas. Lower drilling levels and shut-in wells over a sustained period would have a negative effect on natural gas volumes gathered, processed and treated.

We are exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash and from purchasing natural gas from certain producers at the wellhead. We closely monitor the risks associated with commodity price changes on our future operations and, where appropriate, use various commodity-based derivative instruments such as natural gas, crude oil and NGL financial contracts to hedge a portion of the value of our assets and operations from such price risks. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk” for further discussion of commodity price risk.

Currently, there is a significant level of uncertainty in the financial markets. This uncertainty presents additional potential risks to us. These risks include the availability and costs associated with our borrowing capabilities and ability to raise additional capital, and an increase in the volatility of the price of our common units.

 

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How We Evaluate Our Operations

Our principal revenue is generated from the gathering, processing and treating of natural gas and the sale of natural gas, NGLs and condensate (see “Item 8. Financial Statements and Supplementary Data – Note 2 – Revenue Recognition”). Our profitability is a function of the difference between the revenues we receive and the costs associated with conducting our operations, including the cost of natural gas, NGLs and condensate we purchase as well as operating and general and administrative costs and the impact of our commodity hedging activities. Because commodity price movements tend to impact both revenues and costs, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. Variables that affect our profitability include:

 

    the volumes of natural gas we gather, process and treat, which in turn, depend upon the number of wells connected to our gathering systems, the amount of natural gas the wells produce, and the demand for natural gas, NGLs and condensate;

 

    the price of the natural gas we gather; process and treat; and the NGLs and condensate we recover and sell, which is a function of the relevant supply and demand in the mid-continent area of the United States;

 

    the NGL and BTU content of the gas gathered and processed;

 

    the contract terms with each producer; and

 

    the efficiency of our gathering systems and processing and treating plants.

Our management uses a variety of financial measures and operational measurements other than our GAAP financial statements to analyze our performance. These include: (1) volumes, (2) operating expenses and (3) certain non-GAAP measures, consisting of gross margin, EBITDA, adjusted EBITDA and distributable cash flow. Our management views these measures as important performance measures of core profitability for our operations and as key components of our internal financial reporting. We believe investors benefit from having access to the same financial measures that our management uses.

Volumes. Our profitability is impacted by our ability to add new sources of natural gas supply to offset the natural decline of existing volumes from natural gas wells that are connected to our gathering, processing and treating systems. This is achieved by connecting new wells and adding new volumes in existing areas of production. Our performance at our plants is also significantly impacted by the quality of the natural gas we process, the NGL content of the natural gas and the plants’ recovery capability. In addition, we monitor fuel consumption and losses because they have a significant impact on the gross margin realized from our processing operations.

Operating Expenses. Operating expenses generally include the costs required to operate and maintain our pipelines and processing facilities, including salaries and wages, repair and maintenance expense, ad valorem taxes and other overhead costs.

Gross Margins. We define gross margin as natural gas and liquids sales revenue plus transportation, processing and other fee revenues less natural gas and liquids cost of sales, subject to certain non-cash adjustments. Natural gas and liquids cost of sales include the cost of natural gas, NGLs and condensate we purchase from third parties. Gross margin, as we define it, does not include operating expenses and derivative gain (loss) related to undesignated hedges, as movements in gross margin generally do not result in directly correlated movements in these categories.

 

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Gross margin is a non-GAAP measure. The GAAP measure most directly comparable to gross margin is net income. Gross margin is not an alternative to GAAP net income and has important limitations as an analytical tool. Investors should not consider gross margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because gross margin excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of gross margin may not be comparable to gross margin measures of other companies, thereby diminishing its utility (see “Item 6. Selected Financial Data” for a reconciliation of net income to gross margin).

EBITDA and Adjusted EBITDA. EBITDA represents net income (loss) before interest expense, income taxes, depreciation and amortization. Adjusted EBITDA is calculated by adding to EBITDA other non-cash items such as compensation expenses associated with unit issuances, principally to directors and employees; impairment charges; and certain cash items such as non-recurring cash derivative early termination expense. The GAAP measure most directly comparable to EBITDA and Adjusted EBITDA is net income. EBITDA and Adjusted EBITDA are not intended to represent cash flow and do not represent the measure of cash available for distribution. Our method of computing Adjusted EBITDA may not be the same method used to compute similar measures reported by other companies. The Adjusted EBITDA calculation is similar to the Consolidated EBITDA calculation utilized within the financial covenants under our credit facility, with the exception that Adjusted EBITDA includes certain non-cash items specifically excluded under our credit facility and excludes the capital expansion add back included in Consolidated EBITDA as defined in the credit facility (see “–Revolving Credit Facility”).

Certain items excluded from EBITDA and Adjusted EBITDA are significant components in understanding and assessing an entity’s financial performance, such as cost of capital and historic costs of depreciable assets. We have included information concerning EBITDA and Adjusted EBITDA because they provide investors and management with additional information to better understand our operating performance and are presented solely as a supplemental financial measure. EBITDA and Adjusted EBITDA should not be considered as alternatives to, or more meaningful than, net income or cash flow as determined in accordance with GAAP or as indicators of our operating performance or liquidity. The economic substance behind our use of Adjusted EBITDA is to measure the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make distributions to our unit holders.

Distributable Cash Flow. We define distributable cash flow as net income plus tax, depreciation and amortization; amortization of deferred financing costs included in interest expense; and non-cash gain (losses) on derivative contracts, less income attributable to non-controlling interests, preferred unit dividends, maintenance capital expenditures, gains (losses) on asset sales and other non-cash gains (losses).

Distributable cash flow is a significant performance metric used by our management and by external users of our financial statements, such as investors, commercial banks and research analysts, to compare basic cash flows generated by us to the cash distributions we expect to pay our unitholders. Using this metric, management and external users of our financial statements can compute the ratio of distributable cash flow per unit to the declared cash distribution per unit to determine the rate at which the distributable cash flow covers the distribution. Distributable cash flow is also an important financial measure for our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships because the value of a unit of such an entity is generally determined by the unit’s yield, which in turn is based on the amount of cash distributions the entity pays to a unitholder.

The GAAP measure most directly comparable to distributable cash flow is net income. Distributable cash flow should not be considered as an alternative to GAAP net income or GAAP cash flows from operating activities. Distributable cash flow is not a presentation made in accordance with GAAP and has important limitations as an analytical tool. Investors should not consider distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because distributable cash flow excludes some, but not all, items that affect net income and is defined differently by different companies in our industry, our definition of distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility (see “Item 6. Selected Financial Data” for a reconciliation of net income to EBITDA, Adjusted EBITDA and distributable cash flow).

 

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Results of Operations

The following tables illustrate selected pricing before the effect of derivatives and volumetric information for the periods indicated:

 

     Years Ended December 31,  
     2014      2013      Percent
Change
    2012      Percent
Change
 

Pricing:

             

Weighted average prices:

             

NGL price per gallon—Conway hub

   $ 0.89      $ 0.82        8.5   $ 0.78        5.1

NGL price per gallon—Mt. Belvieu hub

     0.85        0.85        —       0.96        (11.5 )% 

Oklahoma

             

Natural gas sales ($/MMBTU):

             

SouthOK

     4.07        3.46        17.6     2.60        33.1

WestOK

     4.02        3.42        17.5     2.66        28.6

NGL sales ($/gallon):

             

SouthOK

     0.96        0.79        21.5     0.78        1.3

WestOK

     1.02        1.04        (1.9 )%      0.89        16.9

Condensate sales ($/barrel):

             

SouthOK

     84.99        94.02        (9.6 )%      94.82        (0.8 )% 

WestOK

     84.14        87.17        (3.5 )%      84.76        2.8

Texas

             

Natural gas sales ($/MMBTU):

             

SouthTX

     4.22        N/A         N/A        N/A         N/A   

WestTX

     4.01        3.38        18.6     2.54        33.1

NGL sales ($/gallon):

             

SouthTX

     0.86        0.79        8.9     N/A         N/A   

WestTX

     0.86        0.92        (6.5 )%      0.98        (6.1 )% 

Condensate sales ($/barrel):

             

SouthTX

     80.34        93.75        (14.3 )%      N/A         N/A   

WestTX

     89.14        98.55        (9.5 )%      89.40        10.2

Weighted Average

             

Natural gas sales ($/MMBTU):

     4.02        3.44        16.9     2.62        31.3

NGL sales ($/gallon):

     0.93        0.91        2.2     0.90        1.1

Condensate sales ($/barrel):

     85.52        91.90        (6.9 )%      87.88        4.6

 

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     Years Ended December 31,  
     2014      2013      Percent
Change
    2012      Percent
Change
 

Operating data:

             

Oklahoma

             

SouthOK system(1)

             

Gathered gas volume (MCFD)

     435,455         406,073        7.2     350,593        15.8

Processed gas volume (MCFD)

     409,741         378,732        8.2     325,453        16.4

Residue Gas volume (MCFD)

     374,342         324,025        15.5     275,315        17.7

NGL volume (BPD)

     29,033         35,088        (17.3 )%      29,988        17.0

Condensate volume (BPD)

     662         525        26.1     531        (1.1 )% 

WestOK system:

             

Gathered gas volume (MCFD)

     570,800         500,756        14.0     369,035        35.7

Processed gas volume (MCFD)

     542,960         475,441        14.2     348,041        36.6

Residue Gas volume (MCFD)

     497,170         438,611        13.4     322,751        35.9

NGL volume (BPD)

     25,357         20,971        20.9     14,505        44.6

Condensate volume (BPD)

     2,475         1,887        31.2     1,360        38.8

Texas

             

SouthTX system:

             

Gathered gas volume (MCFD)

     120,506         132,826        (9.3 )%      N/A         N/A   

Processed gas volume (MCFD)

     118,712         131,745        (9.9 )%      N/A         N/A   

Residue Gas volume (MCFD)

     95,678         105,207        (9.1 )%      N/A         N/A   

NGL volume (BPD)

     14,523         16,711        (13.1 )%      N/A         N/A   

Condensate volume (BPD)

     158         77        105.2     N/A         N/A   

WestTX system(1):

             

Gathered gas volume (MCFD)

     480,722         357,524        34.5     275,946        29.6

Processed gas volume (MCFD)

     460,823         328,678        40.2     249,221        31.9

Residue Gas volume (MCFD)

     340,212         244,294        39.3     179,539        36.1

NGL volume (BPD)

     59,807         41,920        42.7     32,314        29.7

Condensate volume (BPD)

     1,911         1,657        15.3     1,524        8.7

Barnett system:

             

Average throughput volume – (MCFD)

     20,133         21,356        (5.7 )%      22,935        (6.9 )% 

 

(1) Operating data for SouthOK and WestTX represent 100% of operating activity for these systems. SouthOK gathered volumes include volumes gathered by MarkWest and processed through our facilities.

 

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Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

The following table and discussion is a summary of our consolidated results of operations for the years ended December 31, 2014 and 2013 (in thousands):

 

     Years Ended
December 31,
          Percent
Change
 
     2014     2013     Variance    

Gross margin(1)

        

Natural gas and liquids sales

   $ 2,621,428      $ 1,959,144      $ 662,284        33.8

Transportation, processing and other fees

     201,073        165,177        35,896        21.7

Less: non-cash line fill loss(2)

     (5,888     (249     (5,639     (2,264.7 )% 

Less: natural gas and liquids cost of sales

     2,291,914        1,690,382        601,532        35.6
  

 

 

   

 

 

   

 

 

   

Gross margin

  536,475      434,188      102,287      23.6

Gross margin %

  19.0   20.4

Expenses:

Operating expenses

  113,606      94,527      19,079      20.2

General and administrative(3)

  73,943      60,856      13,087      21.5

Other expenses(4)

  6,073      20,005      (13,932   (69.6 )% 

Depreciation and amortization

  202,543      168,617      33,926      20.1

Interest expense

  93,147      89,637      3,510      3.9
  

 

 

   

 

 

   

 

 

   

Total expenses

  489,312      433,642      55,670      12.8

Other income items:

Derivative gain (loss), net

  131,064      (28,764   159,828      555.7

Other income, net

  21,555      11,292      10,263      90.9

Non-cash line fill loss(2)

  (5,888   (249   (5,639   (2,264.7 )% 

Equity loss in joint ventures

  (14,007   (4,736   (9,271   (195.8 )% 

Goodwill impairment loss

  —        (43,866   43,866      100.0

Gain (loss) on asset disposition

  47,381      (1,519   48,900      3,219.2

Loss on early extinguishment of debt

  —        (26,601   26,601      100.0

Income tax benefit

  2,376      2,260      116      5.1

Income attributable to non-controlling interests(5)

  (13,164   (6,975   (6,189   (88.7 )% 

Preferred unit imputed dividend effect

  (45,513   (29,485   (16,028   (54.4 )% 

Preferred unit dividends in kind

  (42,552   (23,583   (18,969   (80.4 )% 

Preferred unit dividends

  (8,233   —        (8,233   (100.0 )% 
  

 

 

   

 

 

   

 

 

   

Net income (loss) attributable to common limited partners and General Partner

$ 120,182    $ (151,680 $ 271,862      179.2
  

 

 

   

 

 

   

 

 

   

Non-GAAP financial data:

EBITDA(1)

$ 522,958    $ 164,357    $ 358,601      218.2

Adjusted EBITDA(1)

  382,024      324,870      57,154      17.6

Distributable cash flow(1)

  256,297      203,863      52,434      25.7

 

(1) Gross margin, EBITDA, Adjusted EBITDA and distributable cash flow are non-GAAP financial measures (see “–How We Evaluate Our Operations” and “Item 6. Selected Financial Data –Reconciliation of Net Income to Gross Margin and –Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow”).
(2) Includes the non-cash impact of commodity price movements of pipeline linefill.
(3) General and administrative includes compensation reimbursement to affiliates.
(4) Includes Merger costs in connection with the Targa Resources LP Merger for the year ended December 31, 2014 (see “Item 8. Financial Statements and Supplementary Data –Note 3”) and the TEAK and Cardinal Acquisitions for the years ended December 31, 2013 and 2012, respectively (see “Item 8. Financial Statements and Supplementary Data –Note 4”).
(5) Represents Anadarko’s non-controlling interest in the operating results of the WestOK and WestTX systems and MarkWest’s non-controlling interest in Centrahoma.

 

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Gross margin

Gross margin from natural gas and liquids sales and transportation, processing and other fees and the related natural gas and liquids cost of sales for the year ended December 31, 2014 increased primarily due to higher production volumes. Overall gross margin percentages are lower for the year ended December 31, 2014 due to the conversion of keep-whole contracts to POP during the period, which reduced our NGL-related commodity price risk, but negatively impacted our gross margin rate.

 

    Oklahoma. For the year ended December 31, 2014, Oklahoma gross margins increased $42.3 million compared to the prior year. Gathering and processing volumes across the Oklahoma segment for the year ended December 31, 2014 increased as a result of increased production on the gathering systems, which continue to be expanded to meet producer demand.

 

    Texas. For the year ended December 31, 2014, Texas gross margins increased $61.0 million compared to the prior year. The WestTX system’s gathering and processing volumes for the year ended December 31, 2014 increased compared to the prior year period due to continued increased volumes from Pioneer Natural Resources Company (NYSE: PXD) and others as a result of their continued drilling programs, and due to the April 2013 start-up of the Driver plant. Gross margin also increased compared to the prior year due to the May 2013 acquisition of the SouthTX system as part of the TEAK Acquisition (see “–Acquisitions”).

Expenses

Operating expenses for the year ended December 31, 2014 increased due to continued expansion of our gathering and processing systems and volume growth across both the Oklahoma and Texas segments (see “–Recent Events”). In addition, operating expenses also increased for the year ended December 31, 2014 due to the May 2013 acquisition of the SouthTX system as part of the TEAK Acquisition (see “–Acquisitions”).

General and administrative expense, including amounts reimbursed to affiliates, increased for the year ended December 31, 2014 mainly due to a $5.8 million increase in non-cash compensation (see “Item 8: Financial Statements and Supplementary Data –Note 17”) and a $6.3 million increase in salaries and wages. These increases are partially due to the increase in the number of employees as a result of the TEAK Acquisition during 2013 (see “–Acquisitions”) and our plant and gathering system expansion projects (see “–Recent Events”).

Other expenses for the year ended December 31, 2014 represent costs related to the Merger (see “–Recent Events”). Other expenses for the year ended December 31, 2013 represent acquisition costs related to the TEAK Acquisition (see “–Acquisitions”).

Depreciation and amortization expense for the year ended December 31, 2014 increased primarily due to growth capital expenditures incurred subsequent to December 31, 2013.

Interest expense for the year ended December 31, 2014 increased primarily due to $6.9 million additional interest related to our 4.75% Senior Notes; $4.2 million of additional interest related to our 5.875% Senior Notes; and $2.0 million increased interest on the senior secured revolving credit facility; offset by $4.2 million reduced interest expense on the 8.75% unsecured senior notes due June 15, 2018 (“8.75% Senior Notes”) and a $5.1 million increase in capitalized interest expense. The increase in the interest on the 4.75% Senior Notes and the 5.875% Senior Notes is due to their issuance during 2013 (see “Item 8. Financial Statements and Supplementary Data – Note 14 – Senior Notes”). The decrease in the interest for the 8.75% Senior Notes is due to their redemption in February 2013 (see “Item 8. Financial

 

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Statements and Supplementary Data – Note 14 – Senior Notes”). The increase in the interest on the senior secured revolving credit facility is due to increased borrowings compared to the prior year (see “Item 8. Financial Statements and Supplementary Data – Note 14 –Revolving Credit Facility”). The increase in capitalized interest is due to increased capital expenditures over the same period last year (see further discussion of capital expenditures under “–Capital Requirements”).

Other income items

Derivative gain (loss), net for the year ended December 31, 2014 had a $169.5 million favorable mark-to-market gain (loss) compared to the prior year primarily due to a $141.0 million mark-to-market gain in the current year as a result of a decrease in forward prices, related to falling oil prices, combined with an increase in forward prices during the prior year, which resulted in $28.4 million mark-to-market losses on derivatives; offset by a $9.6 million unfavorable variance in cash settlements in the current year compared to the prior year mainly due to favorable propane swap settlements in the prior year.

While we utilize either quoted market prices or observable market data to calculate the fair value of natural gas and crude oil derivatives, valuations of NGL fixed price swaps are based on a forward price curve modeled on a regression analysis of quoted price curves for NGLs for similar geographic locations, and valuations of NGL options are based on forward price curves developed by third-party financial institutions. The use of unobservable market data for NGL fixed price swaps and NGL options has no impact on the settlement of these derivatives. However, a change in management’s estimated fair values for these derivatives could impact net income, although it would have no impact on liquidity or capital resources (see “Item 8. Financial Statements and Supplementary Information – Note 2 – Fair Value of Financial Instruments” for further discussion of derivative instrument valuations). We recognized a $74.9 million mark-to-market gain and a $19.7 million mark-to-market loss on derivatives valued based upon unobservable inputs for the year ended December 31, 2014 and 2013, respectively. We enter into derivative instruments solely to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. See further discussion of derivatives under “Item 7A: Quantitative and Qualitative Disclosures About Market Risk.”

Other income had a favorable variance for the year ended December 31, 2014 compared to the prior year primarily due to an arrangement with respect to our SouthTX system.

Non-cash linefill gain (loss) had an unfavorable variance for the year ended December 31, 2014 compared to the prior year primarily due to the changes in the forward prices as described for the derivative gain (loss), net (see “Item 8. Financial Statements and Supplementary Information – Note 12 – NGL Linefill”).

Equity loss in joint ventures had an unfavorable variance for the year ended December 31, 2014 mainly due to $5.0 million in income in the prior year related to WTLPG, which was sold on May 14, 2014 (see “–Recent Events”) and due to a $4.3 million increase in the loss on the T2 Eagle Ford joint venture. The T2 LaSalle and T2 Eagle Ford joint ventures are structured to earn revenues equal to their operating costs, exclusive of depreciation expense. The loss primarily represents depreciation expense.

Income attributable to non-controlling interests for the year ended December 31, 2014 increased $5.0 million in our Oklahoma segment primarily due to Anadarko’s non-controlling interest in higher net income for the WestOK joint venture, and due to MarkWest’s non-controlling interest in higher net income for the Centrahoma joint venture. The increase in net income of the WestOK joint venture was principally due to higher gross margins on the sale of commodities, resulting from higher volumes. The increase in net income of the Centrahoma joint venture was partially due to the start-up of the Stonewall Plant on May 1, 2014 (see “–Recent Events”), which resulted in higher processing revenues during the year.

 

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Income attributable to non-controlling interests for the year ended December 31, 2014 increased $1.2 million in our Texas segment primarily due to Anadarko’s non-controlling interest in higher net income for the WestTX joint venture. The increase in net income of the WestTX joint venture was principally due to higher gross margins on the sale of commodities, resulting from higher volumes.

Preferred unit imputed dividend effect for the year ended December 31, 2014 represents the accretion of the beneficial conversion discount of the Class D Preferred Units which were issued in May 2013 (see “Item 8. Financial Statements and Supplementary Data – Note 6 –Class D Preferred Units”).

Preferred unit dividends in-kind for the year ended December 31, 2014 represent the distributions to the Class D Preferred Units (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Class D Preferred Units”). The unfavorable variance compared to the prior year is due to an increased distribution per unit and increased number of preferred units outstanding over the prior year.

Preferred unit dividends for the year ended December 31, 2014 represent the cash distributions to the Class E Preferred Units (see “–Class E Preferred Units”).

Non-GAAP financial data

EBITDA had a favorable variance for the year ended December 31, 2014 compared to the prior year mainly due to mark-to-market gains on derivatives in the current year compared to mark-to-market losses on derivatives in the prior year, as discussed above in “–Other income items,” and due to the favorable gross margin variance, as discussed above in “–Gross margin.”

Adjusted EBITDA had a favorable variance for the year ended December 31, 2014 compared to the prior year mainly due to the favorable gross margin variance, as discussed above in “–Gross Margin.”

Distributable cash flow had a favorable variance for the year ended December 31, 2014 compared to the prior year mainly due to the favorable Adjusted EBITDA variance, as discussed above, partially offset by increased preferred unit dividends, as discussed above in “–Other income items.”

 

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Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

The following table and discussion is a summary of our consolidated results of operations for the years ended December 31, 2013 and 2012 (in thousands):

 

     Years Ended
December 31,
          Percent
Change
 
     2013     2012     Variance    

Gross margin(1)

        

Natural gas and liquids sales

   $ 1,959,144      $ 1,137,261      $ 821,883        72.3

Transportation, processing and other fees

     165,177        66,722        98,455        147.6

Less: non-cash line fill loss(2)

     (249     (2,111     1,862        88.2

Less: natural gas and liquids cost of sales

     1,690,382        927,946        762,436        82.2
  

 

 

   

 

 

   

 

 

   

Gross margin

  434,188      278,148      156,040      56.1

Gross margin %

  20.4   23.1

Expenses:

Operating expenses

  94,527      62,098      32,429      52.2

General and administrative(3)

  60,856      47,206      13,650      28.9

Other expenses(4)

  20,005      15,069      4,936      32.8

Depreciation and amortization

  168,617      90,029      78,588      87.3

Interest expense

  89,637      41,760      47,877      114.6
  

 

 

   

 

 

   

 

 

   

Total expenses

  433,642      256,162      177,480      69.3

Other income items:

Derivative gain (loss), net

  (28,764   31,940      (60,704   (190.1 )% 

Other income, net

  11,292      10,097      1,195      11.8

Non-cash line fill loss(2)

  (249   (2,111   1,862      88.2

Equity income (loss) in joint ventures

  (4,736   6,323      (11,059   (174.9 )% 

Goodwill impairment loss

  (43,866   —        (43,866   (100.0 )% 

Loss on asset disposition

  (1,519   —        (1,519   (100.0 )% 

Loss on early extinguishment of debt

  (26,601   —        (26,601   (100.0 )% 

Income tax benefit (expense)

  2,260      (176   2,436      1,384.1

Income attributable to non-controlling interests(5)

  (6,975   (6,010   (965   (16.1 )% 

Preferred unit imputed dividend effect

  (29,485   —        (29,485   (100.0 )% 

Preferred unit dividends in kind

  (23,583   —        (23,583   (100.0 )% 
  

 

 

   

 

 

   

 

 

   

Net income (loss) attributable to common limited partners and General Partner

$ (151,680 $ 62,049    $ (213,729   (344.5 )% 
  

 

 

   

 

 

   

 

 

   

Non-GAAP financial data:

EBITDA(1)

$ 164,357    $ 200,024    $ (35,667   (17.8 )% 

Adjusted EBITDA(1)

  324,870      220,207      104,663      47.5

Distributable cash flow(1)

  203,863      146,013      57,850      39.6

 

(1) Gross margin, EBITDA, Adjusted EBITDA and distributable cash flow are non-GAAP financial measures (see “–How We Evaluate Our Operations” and “Item 6. Selected Financial Data –Reconciliation of Net Income to Gross Margin and – Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow”).
(2) Includes the non-cash impact of commodity price movements of pipeline linefill.
(3) General and administrative also includes compensation reimbursement to affiliates.
(4) Includes acquisition costs in connection with the Cardinal and TEAK Acquisitions for the year ended December 31, 2013 (see “Item 8. Financial Statements and Supplementary Data –Note 4”).
(5) Represents Anadarko’s non-controlling interest in the operating results of the WestOK and WestTX systems and MarkWest’s non-controlling interest in Centrahoma.

 

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Gross margin

Gross margin from natural gas and liquids sales and transportation, processing and other fees and the related natural gas and liquids cost of sales for the year ended December 31, 2013 increased primarily due to higher production volumes, including the new volumes in 2013 from the SouthOK and SouthTX systems due to the Cardinal and TEAK Acquisitions (see “–Acquisitions”). Overall gross margin percentages are lower for the year ended December 31, 2013 due to the increase in natural gas prices compared to the prior year, which increased at a higher rate than NGL prices, negatively impacting the gross margin rate achieved on Keep-Whole contracts.

 

    Oklahoma. For the year ended December 31, 2013, Oklahoma gross margins increased $89.5 million compared to the prior year primarily due to increased production from the V-60 plant, which was placed into service in July 2012 and from the new volumes in 2013 from the SouthOK system due to the Cardinal Acquisition (see “–Acquisitions”). Also, gathering and processing volumes on the WestOK system increased for the year ended December 31, 2013 compared to the prior year primarily due to increased production on the gathering systems and the start-up of the Waynoka II plant, which was placed into service in September 2012

 

    Texas. For the year ended December 31, 2013, Texas gross margins increased $56.8 million compared to the prior year primarily due to new volumes in 2013 from the SouthTX system acquired in the TEAK Acquisition (see “–Acquisitions”). Also, WestTX system’s gathering and processing volumes for the year ended December 31, 2013 increased compared to the prior year due to increased volumes from Pioneer Natural Resources Company (NYSE: PXD) and others as a result of their continued drilling programs; and the start-up of the Driver plant in April 2013.

Expenses

Operating expenses, comprised primarily of plant operating expenses and transportation and compression expenses, for the year ended December 31, 2013 increased compared to the prior year mainly due to $11.7 million in additional expenses from the Arkoma plants, within the SouthOK system, acquired in the Cardinal Acquisition (see “–Acquisitions”); $6.9 million in additional expenses from the SouthTX systems acquired in the TEAK Acquisition (see “–Acquisitions”); a $7.0 million increase on the WestOK system primarily due to increased gathered volumes in comparison to the prior year period, as discussed above in “Gross margin”; and a $4.5 million increase on the WestTX system primarily due to increased gathered volumes from Pioneer Natural Resources Company and other producers and the start-up of the Driver plant in April 2013.

General and administrative expense, including amounts reimbursed to affiliates, increased for the year ended December 31, 2013 mainly due to a $7.7 million increase in share-based compensation related to phantom units granted to employees (see “Item 8: Financial Statements and Supplementary Data – Note 17”); and a $3.6 million increase in salaries and wages partially due to the increase in the number of employees as a result of the Cardinal and TEAK Acquisitions (see “–Acquisitions”).

Other expenses for the year ended December 31, 2013 increased mainly due to $19.3 million in acquisition costs related to the TEAK Acquisition in 2013 compared to $15.4 million in acquisition costs related to the Cardinal Acquisition in the prior year (see “–Acquisitions”).

Depreciation and amortization expense for the year ended December 31, 2013 increased compared to the prior year primarily due to $31.8 million additional expense related to assets acquired in the Cardinal Acquisition (see “–Acquisitions”); $26.9 million additional expense related to assets acquired in the TEAK Acquisition (see “–Acquisitions”); and due to growth capital expenditures incurred subsequent to December 31, 2012.

 

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Interest expense for the year ended December 31, 2013 increased compared to the prior year primarily due to $33.9 million additional interest related to our 5.875% Senior Notes; $26.7 million increase in interest expense associated with our 6.625% Senior Notes; and $12.1 million additional interest related to our 4.75% Senior Notes; partially offset by $27.0 million reduced interest on the 8.75% Senior Notes. The increase in the interest on the 5.875% Senior Notes and the 4.75% Senior Notes is due to their issuance in 2013 (see “–Senior Notes”). The increase in the interest on the 6.625% Senior Notes is due to an additional issuance of $175.0 million in December 2012. The decrease in the interest for the 8.75% Senior Notes is due to their redemption in February 2013 (see “Item 8. Financial Statements and Supplementary Data – Note 14 –Senior Notes”).

Other income items

Derivative gain (loss), net for the year ended December 31, 2013 compared to the prior year had a $60.7 unfavorable variance primarily due to a $49.4 million unfavorable variance on the non-cash fair value revaluation of commodity derivative contracts in 2013 compared to the prior year because of a $20.9 million mark-to-market gain in the prior year resulting from a decrease in prices during the prior year period; and a $28.4 million mark-to-market loss in 2013 resulting from an increase in prices during 2013.

We recognized a $19.7 million mark-to-market loss and a $27.3 million mark-to-market gain on derivatives that were valued based upon unobservable inputs for the years ended December 31, 2013 and 2012, respectively.

Other income, net for the year ended December 31, 2013 had a favorable variance primarily due to a $1.0 million settlement of business interruption insurance related to a loss of revenue in our WestOK system in May 2011 due to storm damage at the Chester plant.

Non-cash line fill loss had a favorable variance for the year ended December 31, 2013 compared to the prior year primarily due to a decrease in forward curve prices during the prior year period.

Equity income (loss) in joint ventures decreased for the year ended December 31, 2013 compared to the prior year primarily due to a $9.7 million loss in the current period from the SouthTX equity method investments. The T2 LaSalle and T2 Eagle Ford joint ventures are structured to earn revenues equal to their operating costs, exclusive of depreciation expense. The loss primarily represents depreciation expense.

Goodwill impairment loss of $43.9 million for the year ended December 31, 2013 pertained to an impairment of goodwill related to our contract gas treating business acquired during the Cardinal Acquisition (see “Item 8: Financial Statements and Supplementary Data – Note 8”).

Loss on asset disposition for the year ended December 31, 2013 pertained to management’s decision to not pursue a project to lay pipe in an area where acquired rights of way had expired in the SouthOK system.

Loss on early extinguishment of debt for the year ended December 31, 2013 represents $17.5 million premiums paid; $8.0 million consent payment made; and $5.3 million write off of deferred financing costs, offset by $4.2 million recognition of unamortized premium related to the redemption of the 8.75% Senior Notes (see “Item 8. Financial Statements and Supplementary Data – Note 14 –Senior Notes”).

 

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Income tax benefit for the year ended December 31, 2013 represents the accrued income tax related to the income earned on APL Arkoma, Inc., which was acquired as part of the Cardinal Acquisition (see “–Acquisitions”).

Income attributable to non-controlling interests for the year ended December 31, 2013 increased compared to the prior year primarily due to Anadarko’s non-controlling interest in higher net income for the WestOK and WestTX joint ventures. The increase in net income of the WestOK and WestTX joint ventures was principally due to higher gross margins on the sale of commodities, resulting from higher volumes.

Preferred unit imputed dividend effect for the year ended December 31, 2013 represents the accretion of the beneficial conversion discount of the Class D Preferred Units which were issued in May 2013 (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Class D Preferred Units”).

Preferred unit dividends in-kind for the year ended December 31, 2013 represent the distributions to the Class D Preferred Units which were issued in May 2013 (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Class D Preferred Units”).

Preferred unit dividends in-kind for the year ended December 31, 2013 represent the distributions to the Class D Preferred Units issued in May 2013, which have been declared (see “–Class D Preferred Units”).

Non-GAAP financial data

EBITDA had an unfavorable variance for the year ended December 31, 2013 compared to the prior year mainly due to the impairment of goodwill acquired during the Cardinal Acquisition and the loss on early extinguishment of debt related to the redemption of the 8.75% Senior Notes during 2013, as discussed above in “–Other income items.”

Adjusted EBITDA had a favorable variance for the year ended December 31, 2013 compared to the prior year mainly due to the improved gross margin variance, as discussed above in “–Gross Margin,” partially offset by higher operating expenses as discussed above in “–Expenses.”

Distributable cash flow had a favorable variance for the year ended December 31, 2013 compared to the prior year mainly due to the favorable Adjusted EBITDA variance, as discussed above, partially offset by higher interest expense as discussed above in “–Expenses.”

Liquidity and Capital Resources

General

Our primary sources of liquidity are cash generated from operations and borrowings under our revolving credit facility. Our primary cash requirements, in addition to normal operating expenses, are for debt service, capital expenditures and quarterly distributions to our common unitholders and General Partner. In general, we expect to fund:

 

    cash distributions and maintenance capital expenditures through existing cash and cash flows from operating activities;

 

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    expansion capital expenditures and working capital deficits through the retention of cash and additional capital raising; and

 

    debt principal payments through operating cash flows and refinancings as they become due, or by the issuance of additional limited partner units or asset sales.

At December 31, 2014, we had $385.0 million outstanding borrowings under our $800.0 million senior secured revolving credit facility and $4.2 million of outstanding letters of credit, which are not reflected as borrowings on our consolidated balance sheets, with $410.8 million of remaining committed capacity under the revolving credit facility, (see “–Revolving Credit Facility”). We were in compliance with the credit facility’s covenants at December 31, 2014. We had a working capital surplus of $24.5 million at December 31, 2014 compared with a $78.4 million working capital deficit at December 31, 2013. We believe we will have sufficient liquid assets, cash from operations and borrowing capacity to meet our financial commitments, debt service obligations, contingencies and anticipated capital expenditures for at least the next twelve-month period. However, we are subject to business, operational and other risks that could adversely affect our cash flows. We may need to supplement our cash generation with proceeds from financing activities, including borrowings under our revolving credit facility and other borrowings, the issuance of additional limited partner units and sales of our assets.

Instability in the financial markets, as a result of recession or otherwise, may cause volatility in the markets and may impact the availability of funds from those markets. This may affect our ability to raise capital and reduce the amount of cash available to fund our operations. We rely on our cash flows from operations and our revolving credit facility to execute our growth strategy and to meet our financial commitments and other short-term liquidity needs. We cannot be certain additional capital will be available to the extent required and on acceptable terms.

Cash Flows – Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

The following table details the cash flow changes between the years ended December 31, 2014 and 2013 (in thousands):

 

     Year Ended December 31,             Percent
Change
 
     2014      2013      Variance     

Net cash provided by (used in):

           

Operating activities

   $ 292,529       $ 210,844       $ 81,685         38.7

Investing activities

     (524,339      (1,443,083      918,744         63.7

Financing activities

     234,999         1,233,755         (998,756      (81.0 )% 
  

 

 

    

 

 

    

 

 

    

 

 

 

Net change in cash and cash equivalents

$ 3,189    $ 1,516    $ 1,673      —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Net cash provided by operating activities for the year ended December 31, 2014 increased compared to the prior year period primarily due to a $74.1 million increase in net earnings from continuing operations excluding non-cash charges. The increase is primarily due to increased gross margins from the sale of natural gas and NGLs offset by an increase in operating expense and general and administrative expense (see “–Results of Operations”).

Net cash used in investing activities for the year ended December 31, 2014 decreased compared to the prior year period mainly due to the $974.7 million TEAK Acquisition (see “Item 8. Financial Statements and Supplementary Data – Note 4”) in the prior year and due to the receipt of $131.0 million in net proceeds from the sale of WTLPG (see “–Recent Events”), partially offset by an increase in capital expenditures of $197.2 million in the current year compared to the prior year (see “–Capital Requirements”).

 

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Net cash provided by financing activities for the year ended December 31, 2014 decreased compared to the prior year period mainly due to (i) $637.3 million provided by the issuance of the 5.875% Senior Notes in the prior year (see “–Senior Notes”); (ii) $397.7 million provided by the issuance of Class D Preferred Units in the prior year (see “–Class D Preferred Units”); (iii) $391.2 million provided by the issuance of the 4.75% Senior Notes in the prior year (see “–Senior Notes”); and (iv) $388.4 million provided by the April 2013 common unit issuance of 11,845,000 common units in the prior year (see “–Common Equity Offerings). These decreases were partially offset by (i) the $391.4 million redemption of the 8.75% Senior Notes, including the cost of early retirement of debt in the prior year (see “–Senior Notes”); (ii) a $141.0 million net decrease in the prior year to outstanding borrowings on the revolving credit facility; and (iii) $122.3 million provided by the issuance of the Class E Preferred Units in the current period (see “–Class E Preferred Units”). The gross amount of borrowings and repayments under the revolving credit facility included within net cash provided by financing activities in the consolidated combined statements of cash flows, which are generally in excess of net borrowings or repayments during the period or at period end, reflect the timing of (i) cash receipts, which generally occur at specific intervals during the period and are utilized to reduce borrowings under the revolving credit facility, and (ii) payments, which generally occur throughout the period and increase borrowings under the revolving credit facility, which is generally common practice for the industry.

Cash Flows – Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

The following table details the cash flow changes between the years ended December 31, 2013 and 2012 (in thousands):

 

     Year Ended December 31,             Percent
Change
 
     2013      2012      Variance     

Net cash provided by (used in):

           

Operating activities

   $ 210,844       $ 174,638       $ 36,206         20.7

Investing activities

     (1,443,083      (1,006,641      (436,442      (43.4 )% 

Financing activities

     1,233,755         835,233         398,522         47.7
  

 

 

    

 

 

    

 

 

    

 

 

 

Net change in cash and cash equivalents

$ 1,516    $ 3,230    $ (1,714   —     
  

 

 

    

 

 

    

 

 

    

 

 

 

Net cash provided by operating activities for the year ended December 31, 2013 increased compared to the prior year period due to a $60.0 million increase in net earnings from continuing operations excluding non-cash charges, offset by a $23.8 million unfavorable variance in the change in working capital. The increase in net earnings from continuing operations excluding non-cash charges is primarily due to increased gross margins from the sale of natural gas and NGLs offset by an increase in interest expense (see “–Results of Operations”). The change in working capital is mainly due to a $16.3 million increase in accrued interest primarily related to our Senior Notes (see “–Senior Notes”), and due to a net increase in working capital deficit related to the Cardinal and TEAK Acquisitions (see “–Acquisitions”).

Net cash used in investing activities for the year ended December 31, 2013 increased compared to the prior year period mainly due to the $974.7 million net cash paid for the TEAK Acquisition (see “–Acquisitions”); a $77.0 million increase in capital expenditures in the 2013 period compared to the prior year period (see further discussion of capital expenditures under “–Capital Requirements”); and a $13.4 million increase in contributions to equity method joint ventures (see “Item 8. Financial Statements and Supplementary Data – Note 5 – Equity Method Investments”). These increases in net cash used in investing activities were partially offset by $633.6 million net cash paid for acquisition of assets in the prior period, including the Cardinal Acquisition (see “–Acquisitions”).

 

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Net cash provided by financing activities for the year ended December 31, 2013 increased compared to the prior year period mainly due to (i) $637.3 million provided by the issuance of the 5.875% Senior Notes in February 2013; (ii) $391.2 million provided by the issuance of the 4.75% Senior Notes in May 2013 (see “–Senior Notes”); (iii) $397.7 million provided by the issuance of Class D Preferred Units (see “–Class D Preferred Units”); (iv) an increase of $128.8 million provided by the sale of common units under our equity distribution program (see “–Common Equity Offerings”); and (v) an increase of $75.9 million provided by the issuance of common units related to acquisitions (see “–Common Equity Offerings). The increases were partially offset by the $391.4 million redemption of the 8.75% Senior Notes in 2013, including the cost of early retirement of debt (see “–Senior Notes”); $495.4 million provided by the issuance of the 6.625% Senior Notes in the prior year (see “Item 8: Financial Statements and Supplementary Data – Note 14 – Senior Notes”); a $151.0 million, net increase in the prior period to outstanding borrowings on the revolving credit facility; and a $141.0 million, net decrease in 2013 to outstanding borrowings on the revolving credit facility.

Capital Requirements

Our operations require continual investment to upgrade or enhance existing operations and to ensure compliance with safety, operational, and environmental regulations. Our capital requirements consist primarily of:

 

    maintenance capital expenditures to maintain equipment reliability and safety and to address environmental regulations; and

 

    expansion capital expenditures to acquire complementary assets and to expand the capacity of our existing operations.

The following table summarizes maintenance and expansion capital expenditures, excluding amounts paid for acquisitions, for the periods presented (in thousands):

 

     Years Ended
December 31,
 
     2014      2013      2012  

Maintenance capital expenditures

   $ 25,680       $ 21,919       $ 19,021   

Expansion capital expenditures

     622,067         428,641         354,512   
  

 

 

    

 

 

    

 

 

 

Total

$ 647,747    $ 450,560    $ 373,533   
  

 

 

    

 

 

    

 

 

 

The increase in maintenance capital for the year ended December 31, 2014 when compared to the prior years was due to the fluctuations in the timing of scheduled maintenance activity.

Expansion capital expenditures increased for the year ended December 31, 2014 compared to the prior year primarily due to construction costs for (i) the Stonewall plant within SouthOK, which was placed in service May 1, 2014 (see “–Recent Events”), (ii) the Silver Oak II plant within SouthTX placed in service on June 25, 2014 (see “–Recent Events”), (iii) the Edward plant within WestTX placed in service on September 15, 2014 (see “–Recent Events”); and (iv) the construction of the Velma to Arkoma connection within SouthOK, which was completed in December 2014. As of December 31, 2014, we had approved additional expenditures of approximately $267.9 million on processing facility expansions, pipeline extensions and compressor station upgrades, of which approximately $179.1 million in purchase commitments had been made. We expect to fund these projects through operating cash flows and borrowings under our revolving credit facility.

Expansion capital expenditures increased for the year ended December 31, 2013 compared to the prior year primarily due to the completion of the Driver Plant within WestTX in April 2013 and construction costs for the Stonewall Plant within SouthOK, the Silver Oak II Plant within SouthTX, and the Edward Plant within WestTX.

 

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Partnership Distributions

Our partnership agreement requires that we distribute 100% of available cash, for each calendar quarter, to our common unitholders and our General Partner within 45 days following the end of such calendar quarter in accordance with their respective percentage interests. Available cash consists generally of all our cash receipts, less cash disbursements and net additions to reserves, including any reserves required under debt instruments for future principal and interest payments.

The Class D Preferred Units received distributions of additional Class D Preferred Units in each of the full quarterly periods following their issuance in May 2013. On January 22, 2015, we exercised our right to convert all outstanding Class D Preferred Units into common limited partner units (see “–Subsequent Events”).

We make cumulative cash distributions on the Class E Preferred Units. The cash distributions are payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year, when, and if, declared by the board of directors. The initial distribution on the Class E Preferred Units was paid on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million, representing the distribution for the period March 17, 2014 through July 14, 2014. Thereafter, we pay cumulative distributions in cash on the Class E Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year.

Our General Partner is granted discretion by our partnership agreement to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When our General Partner determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level.

Available cash is initially distributed 98% to our common limited partners and 2.0% to our General Partner. These distribution percentages are modified to provide for incentive distributions to be paid to our General Partner if quarterly distributions to common limited partners exceed specified targets. Incentive distributions are generally defined as all cash distributions paid to our General Partner that are in excess of 2.0% of the aggregate amount of cash being distributed. Our General Partner, holder of all our incentive distribution rights, has agreed to allocate up to $3.75 million of its incentive distribution rights per quarter back to us after the General Partner receives an initial $7.0 million of incentive distribution rights per quarter. Incentive distributions of $22.7 million, $15.0 million and $6.3 million were paid during the years ended December 31, 2014, 2013 and 2012, respectively.

Common Equity Offerings

On May 12, 2014, we entered into an Equity Distribution Agreement (the “2014 EDA”) with Citigroup Global Markets Inc. (“Citigroup”), Wells Fargo Securities, LLC and MLV & Co. LLC, as sales agents. Pursuant to the 2014 EDA, we may offer and sell from time to time through the sales agents, common units having an aggregate value up to $250.0 million. Sales are at market prices prevailing at the time of the sale. However, we are currently restricted from selling common units by the Merger Agreement (see “–Recent Events”).

In November 2012, we entered into an Equity Distribution Agreement (the “2012 EDA” and together, with the 2014 EDA, the “EDAs”) with Citigroup. Pursuant to this program, we offered and sold through Citigroup, as its sales agent, common units for $150.0 million. We used the full capacity under the 2012 EDA during the year ended 2013.

 

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During the years ended December 31, 2014 and 2013, we issued 3,558,005 and 3,895,679 common units, respectively, under the EDAs for proceeds of $121.6 million and $137.8 million, respectively, net of $1.2 million and $2.8 million, respectively, in commissions paid to the sales agents. We also received capital contributions from the General Partner of $2.5 million and $2.9 million, respectively, during the years ended December 31, 2014 and 2013, to maintain its 2.0% general partner interest in us. The net proceeds from the common unit offerings and General Partner contributions were utilized for general partnership purposes. As of December 31, 2014, we had $127.0 million remaining capacity under the 2014 EDA (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Common Units”).

In April 2013, we sold 11,845,000 of our common units to the public at a price of $34.00 per unit, yielding net proceeds of $388.4 million after underwriting commissions and expenses. We also received a capital contribution from the General Partner of $8.3 million to maintain its 2.0% general partnership interest (see “Item 8: Financial Statements and Supplementary Data – Note 6 –Common Units”). We used the proceeds from this offering to fund a portion of the purchase price of the TEAK Acquisition (see “Item 8. Financial Statements and Supplementary Data – Note 4 – TEAK Midstream, LLC”).

Class D Preferred Units

On May 7, 2013 we completed the private placement of $400.0 million of our Class D Preferred Units to third party investors, at a negotiated price per unit of $29.75 for net proceeds of $397.7 million. The Class D Preferred Units were offered and sold in a private transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended. We also received a capital contribution from the General Partner of $8.2 million to maintain its 2.0% general partner interest in us (see “Item 8: Financial Statements and Supplementary Data—Note 6 – Class D Preferred Units”). We used the proceeds to fund a portion of the purchase price of the TEAK Acquisition (see “Item 8: Financial Statements and Supplementary Data – Note 4 – TEAK Midstream, LLC”).

On January 22, 2015, we exercised our right under the certificate of designation of the Class D Preferred Units to convert all outstanding Class D Preferred Units, plus any unpaid distributions, into common limited partner units. As a result of the conversion, 15,389,575 common limited partner units were issued (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Class D Preferred Units”).

Class E Preferred Units

On March 17, 2014, we issued 5,060,000 of our Class E Preferred Units to the public at an offering price of $25.00 per Class E Preferred Unit. Our Class E Preferred Units are listed on the New York Stock Exchange under the symbol “APLPE”. We received $122.3 million in net proceeds, which were used to pay down the revolving credit facility. We will make cumulative cash distributions on the Class E Preferred Units from the date of original issue. The cash distributions will be payable quarterly in arrears on January 15, April 15, July 15, and October 15 of each year, when, and if, declared by the board of directors. The initial distribution on the Class E Preferred Units was paid on July 15, 2014 in an amount equal to $0.67604 per unit, or approximately $3.4 million. Thereafter, we will pay cumulative distributions in cash on the Class E Preferred Units on a quarterly basis at a rate of $0.515625 per unit, or 8.25% per year (see “Item 8. Financial Statements and Supplementary Data –Note 6 – Class E Preferred Units”).

On January 15, 2015, we paid a cash distribution of $0.515625 per unit, or approximately $2.6 million, on our Class E Preferred Units, representing the cash distribution for the period October 15, 2014 through January 14, 2015 (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Class E Preferred Units”).

 

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On January 27, 2015, we delivered notice of its intention to redeem all outstanding shares of its Class E Preferred Units. The redemption of the Class E Preferred Units will occur immediately prior to the close of the Merger (See “–Recent Events”). We expect the Merger to close on February 27, 2015 and, accordingly, the redemption date would also be on February 27, 2015. The Class E Preferred Units will be redeemed at a redemption price of $25.00 per unit, plus an amount equal to all accumulated and unpaid distributions on the Class E Preferred Units as of the redemption date (see “Item 8. Financial Statements and Supplementary Data – Note 6 – Class E Preferred Units”).

Revolving Credit Facility

At December 31, 2014, we had an $800.0 million senior secured revolving credit facility with a syndicate of banks, which matures in August 2019. We had $385.0 million outstanding borrowings as of December 31, 2014. Borrowings under the revolving credit facility bear interest, at our option, at either (i) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%, or (ii) the LIBOR rate for the applicable period, in each case plus the applicable margin. The weighted average interest rate for borrowings on the revolving credit facility, at December 31, 2014, was 2.7%. Up to $50.0 million of the revolving credit facility may be utilized for letters of credit, of which $4.2 million was outstanding at December 31, 2014. These outstanding letter of credit amounts were not reflected as borrowings on our consolidated balance sheets.

On August 28, 2014, we entered into a Second Amended and Restated Credit Agreement which, among other changes, extended the maturity date; increased the revolving credit commitment and incremental revolving credit amount; and reduced the applicable margin used to determine interest rates by 0.25% (see “Item 8. Financial Statements and Supplementary Data – Note 14 – Revolving Credit Facility”).

Borrowings under the revolving credit facility are secured by a lien on and security interest in all our property and that of our subsidiaries, except for the assets owned by the WestOK, WestTX and Centrahoma joint ventures and their respective subsidiaries. Borrowings are also secured by the guaranty of each of our consolidated subsidiaries other than the joint venture companies. The revolving credit facility contains customary covenants, including covenants to maintain specified financial ratios, restrictions on our ability to incur additional indebtedness; make certain acquisitions, loans or investments; make distribution payments to our unitholders if an event of default exists; or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. We are also unable to borrow under our revolving credit facility to pay distributions of available cash to unitholders because such borrowings would not constitute “working capital borrowings” pursuant to our partnership agreement.

The events that constitute an event of default for our revolving credit facility include payment defaults, breaches of representations or covenants contained in the credit agreement, adverse judgments against us in excess of a specified amount, and a change of control of our General Partner. As of December 31, 2014, we were in compliance with all covenants under the revolving credit facility.

Senior Notes

At December 31, 2014, we had $500.0 million principal outstanding of 6.625% Senior Notes, $650.0 million principal outstanding of 5.875% Senior Notes, and $400.0 million principal outstanding of 4.75% Senior Notes (together with the 6.625% Senior Notes and 5.875% Senior Notes, the “Senior Notes”).

 

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The Senior Notes are subject to repurchase by us at a price equal to 101% of their principal amount, plus accrued and unpaid interest, upon a change of control or upon certain asset sales if we do not reinvest the net proceeds within 360 days. The Senior Notes are junior in right of payment to our secured debt, including our obligations under our revolving credit facility.

Indentures governing the Senior Notes contain covenants, including limitations of our ability to: incur certain liens; engage in sale/leaseback transactions; incur additional indebtedness; declare or pay distributions if an event of default has occurred; redeem, repurchase or retire equity interests or subordinated indebtedness; make certain investments; or merge, consolidate or sell substantially all our assets. We were in compliance with these covenants as of December 31, 2014.

On January 15, 2015, TRP announced tender offers to redeem any and all of our outstanding Senior Notes in connection with, and conditioned upon, the consummation of the Merger. The Merger, however, is not conditioned on the consummation of the tender offers (see “–Subsequent Events”).

8.75% Senior Notes:

On January 28, 2013, we commenced a cash tender offer for any and all of our outstanding 8.75% Senior Notes and a solicitation of consents to eliminate most of the restrictive covenants and certain of the events of default contained in the indenture governing the 8.75% Senior Notes (“8.75% Senior Notes Indenture”). Approximately $268.4 million aggregate principal amount of the 8.75% Senior Notes, were validly tendered as of the expiration date of the consent solicitation. In February 2013, we accepted for purchase all 8.75% Senior Notes validly tendered as of the expiration of the consent solicitation and paid $291.4 million to redeem the $268.4 million principal plus $11.2 million make-whole premium, $3.7 million accrued interest and $8.0 million consent payment. We entered into a supplemental indenture amending and supplementing the 8.75% Senior Notes Indenture. On March 12, 2013, we paid $105.6 million to redeem the remaining $97.3 million 8.75% Senior Notes not purchased in connection with the tender offer, plus a $6.3 million make-whole premium and $2.0 million in accrued interest. We funded the redemption with a portion of the net proceeds from the issuance of the 5.875% Senior Notes.

6.625% Senior Notes:

On September 28, 2012, we issued $325.0 million of the 6.625% Senior Notes in a private placement transaction, at par. We received net proceeds of $318.9 million after underwriting commissions and other transaction costs and utilized the proceeds to reduce the outstanding balance on our revolving credit facility.

On December 20, 2012, we issued $175.0 million of the 6.625% Senior Notes in a private placement transaction. The 6.625% Senior Notes were issued at a premium of 103.0% of the principal amount for a yield of 6.0%. We received net proceeds of $176.1 million after underwriting commissions and other transaction costs and utilized the proceeds to partially finance the Cardinal Acquisition (see –Acquisitions). Of the $176.1 million net proceeds, $176.5 million were received during the year ended December 31, 2012, while additional expenses of $0.4 million were incurred during the year ended December 31, 2013.

The 6.625% Senior Notes are presented combined with a net $3.9 million unamortized premium as of December 31, 2014. Interest on the 6.625% Senior Notes is payable semi-annually in arrears on April 1 and October 1. The 6.625% Senior Notes are due on October 1, 2020 and are redeemable at any time after October 1, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption (see “Item 8: Financial Statements and Supplementary Data –Note 14 –Senior Notes”).

 

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5.875% Senior Notes:

On February 11, 2013, we issued $650.0 million of the 5.875% Senior Notes in a private placement transaction. The 5.875% Senior Notes were issued at par. We received net proceeds of $637.3 million and utilized the proceeds to redeem the 8.75% Senior Notes and repay a portion of the outstanding indebtedness under the revolving credit facility. Interest on the 5.875% Senior Notes is payable semi-annually in arrears on February 1 and August 1. The 5.875% Senior Notes are due on August 1, 2023, and redeemable at any time after February 1, 2018, at certain redemption prices, together with accrued and unpaid interest to the date of redemption (See “Item 8: Financial Statements and Supplementary Data –Note 14 –Senior Notes”).

4.75% Senior Notes:

On May 10, 2013, we issued $400.0 million of the 4.75% Senior Notes in a private placement transaction. The 4.75% Senior Notes were issued at par. We received net proceeds of $391.2 million and utilized the proceeds repay a portion of the outstanding indebtedness under the revolving credit agreement as part of the TEAK Acquisition. Interest on the 4.75% Senior Notes is payable semi-annually in arrears on May 15 and November 15. The 4.75% Senior Notes are due on November 15, 2021 and are redeemable any time after March 15, 2016, at certain redemption prices, together with accrued and unpaid interest to the date of redemption (See “Item 8: Financial Statements and Supplementary Data –Note 14 –Senior Notes”).

Off Balance Sheet Arrangements

As of December 31, 2014, our off balance sheet arrangements include our letters of credit, issued under the provisions of our revolving credit facility, totaling $4.2 million, and surety bonds under which our maximum liability is $10.7 million. These are in place to support various performance obligations as required by (i) statutes within the regulatory jurisdictions where we operate, (ii) surety, and (iii) counterparty support.

We have certain long-term unconditional purchase obligations and commitments, primarily throughput contracts. These agreements provide transportation services to be used in the ordinary course of our operations.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual obligations and commercial commitments at December 31, 2014 (in thousands):

 

            Payments Due by Period (in thousands)  
     Total      Less than
1 Year
     1 - 3
Years
     4 - 5
Years
     After 5
Years
 

Contractual cash obligations:

              

Debt principal

   $ 1,935,000      $ —         $ —         $ 385,000      $ 1,550,000  

Interest on total debt(1)

     696,783        100,537        201,074        197,666        197,506  

Capital leases

     229        224        5        —           —     

Operating leases

     31,792        12,621        13,736        5,113        322  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual cash obligations(2)

$ 2,663,804   $ 113,382   $ 214,815   $ 587,779   $ 1,747,828  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) Based on the interest rates of our respective debt components as of December 31, 2014.
(2) Excludes non-current deferred tax liabilities of $48.2 million due to uncertainty of the timing of future cash flows for such liabilities.

 

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            Amount of Commitment Expiration Per Period (in thousands)  
     Total      Less than
1 Year
     1 - 3
Years
     4 - 5
Years
     After 5
Years
 

Other commercial commitments:

              

Standby letters of credit

   $ 4,177      $ 4,177      $ —         $ —         $ —     

Surety bonds

     10,727        3,502        7,223        2        —     

Purchase commitments

     179,135        179,135        —           —           —     

Throughput contracts

     191,403        20,717        47,732        38,640        84,314  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total commercial commitments

$ 385,442   $ 207,531   $ 54,955   $ 38,642   $ 84,314  
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Environmental Regulation

Our operations are subject to federal, state and local laws and regulations governing the release of regulated materials into the environment or otherwise relating to environmental protection or human health or safety. We believe our operations and facilities are in substantial compliance with applicable environmental laws and regulations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, imposition of remedial requirements, issuance of injunctions affecting our operations, or other measures. Risks of accidental leaks or spills are associated with the gathering of natural gas. There can be no assurance we will not incur significant costs and liabilities relating to claims for damages to property, the environment, natural resources, or persons resulting from the operation of our business. Moreover, it is possible other developments, such as increasingly stringent environmental laws and regulations and enforcement policies, could result in increased costs and liabilities to us.

Environmental laws and regulations have changed substantially and rapidly over the last 25 years, and we anticipate there will be continuing changes. Trends in environmental regulation include increased reporting obligations and placing more restrictions and limitations on activities, such as emissions of greenhouse gases and other pollutants, generation and disposal of wastes and use, storage and handling of chemical substances, that may impact human health, the environment and/or endangered species.

Other increasingly stringent environmental restrictions and limitations have resulted in increased operating costs for us and other similar businesses throughout the United States. It is possible the costs of compliance with environmental laws and regulations may continue to increase. We will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly, but there can be no assurance we will identify and properly anticipate each such charge, or that our efforts will prevent material costs, if any, from rising.

Inflation and Changes in Prices

Inflation affects the operating expenses of our operations due to the increase in costs of labor and supplies. Inflation did not have a material impact on our results of operations for the years ended December 31, 2014, 2013 and 2012. While we anticipate inflation may affect our future operating costs, we cannot predict the timing or amounts of any such effects.

 

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Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires making estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of actual revenue and expenses during the reporting period. Although we base our estimates on historical experience and various other assumptions we believe to be reasonable under the circumstances, actual results may differ from the estimates on which our financial statements are prepared at any given point of time. Changes in these estimates could materially affect our financial position, results of operations or cash flows. Significant items subject to such estimates and assumptions include revenue and expense accruals, depreciation and amortization, asset impairment, fair value of derivative instruments, the probability of forecasted transactions and the allocation of purchase price to the fair value of assets acquired. We summarize our significant accounting policies within our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data – Note 2.” The following table evaluates the potential impact of estimates utilized during the year ended December 31, 2014:

 

Description

  

Judgments and Uncertainties

  

Effect if

Actual Results Differ
from Estimates and
Assumptions

Revenue and Cost of Sales Recognition   
Revenue primarily consists of the sale of natural gas and NGLs along with the fees earned from gathering, processing, treating and transportation. Costs of sales primarily consists of purchases of natural gas at the wellhead and POP settlements with producers.    Revenues are estimated and accrued due to timing differences between the delivery of natural gas, NGLs, and condensate and the receipt of a delivery statement. This revenue is recorded based upon estimated volumetric data and management estimates of the related gathering and compression fees and product prices. Costs of goods sold are estimated based upon the estimated revenues.    As of December 31, 2014, there were $175.3 million accrued unbilled revenues. A 10% change in the estimated revenues would change gross margin by approximately $3.3 million.
Impairment of Long-Lived Assets      
Management evaluates our long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A long-lived asset is considered impaired when the estimated undiscounted cash flow from such asset is less than the asset’s carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset.    In evaluating impairment, management considers the use or disposition of an asset, the estimated remaining life of an asset, and future expenditures to maintain an asset’s existing service potential. In order to determine the cash flow, management must make certain estimates and assumptions, which include, but are not limited to, changes in general economic conditions in regions in which we operate, our ability to negotiate favorable contracts, the risks that natural gas exploration and production activities will not occur or be successful, competition from other midstream companies, our dependence on certain significant customers and producers of natural gas, and the volume of reserves behind an asset and future NGL product and natural gas prices.    As of December 31, 2014, there were no indicators of impairment for our long-lived assets. A significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset.

 

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Description

  

Judgments and Uncertainties

  

Effect if

Actual Results Differ
from Estimates and
Assumptions

Acquisitions – Purchase Price Allocation

     

We allocate the purchase price of an acquired business to its identifiable assets and liabilities, including identifiable intangible assets, based upon estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities is recorded as goodwill.

 

For significant acquisitions, we engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as customer relationships and contracts. We adjust the preliminary purchase price allocation, as necessary, after the acquisition closing date through the end of the measurement period of up to one year as we finalize valuations for the assets acquired and liabilities assumed.

   Purchase price allocation methodology requires management to make assumptions and apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities primarily using a market approach, income approach, or cost approach, as appropriate. Key inputs into the fair value determinations include estimates and assumptions related to future volumes, commodity prices, operating costs, replacement costs and construction costs, as well as an estimate of the expected term and profits of the related customer contracts.    If estimates or assumptions used to complete the purchase price allocation and estimate the fair value of acquired assets and liabilities significantly differs from assumptions made during the preliminary purchase price allocation, the allocation of purchase price between goodwill, intangibles and property plant and equipment could significantly differ. Such a difference would impact future earnings through depreciation and amortization expense. In addition, if forecasts supporting the valuation of the intangibles or goodwill are not achieved, impairments could arise.

 

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Description

  

Judgments and Uncertainties

  

Effect if

Actual Results Differ
from Estimates and
Assumptions

Impairment of Goodwill

     
Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The first step of the evaluation is a qualitative analysis to determine if it is “more likely than not” that the carrying value of a reporting unit with goodwill exceeds its fair value. The additional quantitative steps in the goodwill impairment test are only performed if we determine that it is more likely than not that the carrying value is greater than the fair value.   

Management is required to make certain assumptions when determining the amount of goodwill allocated to each reporting unit. The method of allocating goodwill resulting from acquisitions involves estimating the fair value of the reporting units and allocating the purchase price for each acquisition to each reporting unit. Goodwill is then calculated for each reporting unit as the excess of the allocated purchase price over the estimated fair value of the net assets.

 

If a quantitative analysis is deemed to be required to evaluate goodwill for impairment, management determines the fair value of reporting units using the income and market approaches. These approaches are also used when allocating the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors such as relevant commodity prices and production volumes. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.

  

Management performed qualitative analyses for all reporting units at December 31, 2014, including SouthTX, which is normally evaluated at April 30, 2014. SouthTX was evaluated at December 31, 2014 due to the significant decline in commodity prices during 2014, which management considered to be a triggering event. Based upon qualitative analyses, it was determined it was more likely than not that the carrying values of our reporting units exceeded their fair values and no impairments were recognized for the year ended December 31, 2014 (See “Item 8: Financial Statements and Supplementary Data ‒ Note 8”).

Depreciation and Amortization

     
Depreciation and amortization expense is generally computed using the straight-line method over the estimated useful life of the assets.    Determination of depreciation and amortization expense requires judgment regarding the estimated useful lives. For property, plant and equipment, judgment is required to estimate salvage values. As circumstances warrant, depreciation and amortization estimates are reviewed to determine if any changes in the underlying assumptions are necessary.    The life of our long-lived tangible assets ranges from 2 – 40 years, and the life of our definite-lived intangible assets ranges from 2 – 15 years. If the useful lives of our assets were decreased by 10%, we estimate that annual depreciation and amortization expense would increase by approximately $12.0 million, which would result in a corresponding change in our net income.

 

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Description

  

Judgments and Uncertainties

  

Effect if

Actual Results Differ
from Estimates and
Assumptions

Variable Interest Entities

     
We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity is a VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the VIE’s assets. When we conclude that we hold an interest in a VIE we must determine if we are the entity’s primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. We are required to consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any interests in a VIE that is not consolidated.   

Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for continuing financial support; the equity holder’s lack of a controlling financial interest; and/or if an equity holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns.

 

We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE.

 

We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions.

   The T2 Joint Ventures we have equity interests in are considered to be VIEs. However, we have determined we are not the primary beneficiary of any of the T2 Joint Ventures, and thus do not consolidate these joint ventures. Changes in the design or nature of the activities of the T2 Joint Ventures, or our involvement with the T2 Joint Ventures may require us to reconsider our conclusions on the joint venture’s statuses as VIEs and/or our status as not being the primary beneficiary. Such reconsideration requires significant judgment and understanding of the organization. This could result in the consolidation of the T2 Joint Ventures, which would have a significant impact on our financial statements.

Impairment of Equity Investments

     
We evaluate our equity method investments in the T2 Joint Ventures for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of an other-than-temporary loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred.    Our impairment assessment requires us to apply judgment in estimating future cash flows from the T2 Joint Ventures; the primary estimate is the operating costs expected to be incurred. We determined there were no material events or changes in circumstances that would indicate an other-than-temporary loss in value has occurred.    We determined there were no material events or changes in circumstances that would indicate an other-than-temporary loss in value has occurred. An impairment of our equity investments could have a significant impact on our financial statements.

 

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Description

  

Judgments and Uncertainties

  

Effect if

Actual Results Differ
from Estimates and
Assumptions

Derivative Instruments

     
Our derivative financial instruments are recorded at fair value in the consolidated balance sheets. Changes in fair value and settlements are reflected in our earnings in the consolidated statements of operations as gains and losses related to NGLs sales, interest expense and/or derivative loss, net. See “Item 8. “Financial Statements and Supplementary Data – Note 12” for further discussion.    When available, quoted market prices or prices obtained through external sources are used to determine a financial instrument’s fair value. The valuation of Level 2 financial instruments is based on quoted market prices for similar assets and liabilities in active markets and other inputs that are observable. However, for other financial instruments for which quoted market prices are not available, the fair value is based upon inputs that are largely unobservable. These instruments are classified as Level 3 under the fair value hierarchy. The fair value of these instruments are determined based on pricing models developed primarily from historical and expected correlations with quoted market prices. At December 31, 2014, approximately 53% of our net derivative assets are classified as Level 3 with the difference classified as Level 2.    If the assumptions used in the pricing models for our financial instruments are inaccurate or if we had used an alternative valuation methodology, the estimated fair value may have been different, and we may be exposed to unrealized losses or gains that could be material. Of the $125.4 million net derivative assets and the $9.1 million net derivative liabilities at December 31, 2014 and 2013, respectively, we had $66.0 million net derivative assets and $11.8 million net derivative liabilities, respectively, that were classified as Level 3 fair value measurements, which rely on subjective forward developed price curves. Holding all other variables constant, a 10% change in the prices utilized in calculating the Level 3 fair value of derivatives at December 31, 2014 would have resulted in approximately a $6.5 million noncash change to net income for the year ended December 31, 2014.

Income Taxes

     
Our corporate subsidiary, APL Arkoma, Inc., accounts for income taxes under the asset and liability method. See “Item 8. Financial Statements and Supplementary Data –Note 10” for further discussion.    Deferred income taxes are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realization of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to write down the deferred tax assets to their net realizable value.    As of December 31, 2014, we have recorded deferred tax assets of $17.3 million. A 10% adjustment due to a valuation allowance related to the realization of deferred assets could result in an approximately $1.7 million impact on net earnings.

 

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Recently Adopted Accounting Standard Updates

See “Item 8: Financial Statements and Supplementary Data – Note 2 –Recently Adopted Accounting Standard Updates” for information regarding recently adopted accounting pronouncements.

Recently Issued Accounting Standard Updates

See “Item 8: Financial Statements and Supplementary Data – Note 2 –Recently Issued Accounting Standard Updates” for information regarding recently issued accounting pronouncements.

 

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and natural gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All our market risk sensitive instruments were entered into for purposes other than trading.

General

All our assets and liabilities are denominated in U.S. dollars, and as a result, we do not have exposure to currency exchange risks.

We are exposed to various market risks, principally fluctuating interest rates and changes in commodity prices. These risks can impact our results of operations, cash flows and financial position. We manage these risks through regular operating and financing activities and periodic use of derivative instruments. The following analysis presents the effect on our results of operations, cash flows and financial position as if the hypothetical changes in market risk factors occurred on December 31, 2014. Only the potential impact of hypothetical assumptions is analyzed. The analysis does not consider other possible effects that could impact our business.

Current market conditions elevate our concern over counterparty risks and may adversely affect the ability of these counterparties to fulfill their obligations to us, if any. The counterparties to our commodity-based derivatives are banking institutions, or their affiliates, currently participating in our revolving credit facility. The creditworthiness of our counterparties is constantly monitored, and we are not aware of any inability on the part of our counterparties to perform under our contracts.

Interest Rate Risk. At December 31, 2014, we had an $800.0 million senior secured revolving credit facility with $385.0 million in outstanding borrowings. Borrowings under the revolving credit facility bear interest, at our option, at either (1) the higher of (a) the prime rate, (b) the federal funds rate plus 0.50% and (c) the LIBOR rate plus 1.0%; or (2) the LIBOR rate for the applicable period (each plus the applicable margin). The weighted average interest rate for the revolving credit facility borrowings was 2.7% at December 31, 2014. Based upon the outstanding borrowings on the senior secured revolving credit facility and holding all other variables constant, a 100 basis-point, or 1%, change in interest rates would change our annual interest expense by approximately $3.9 million.

Commodity Price Risk. We are exposed to commodity prices as a result of being paid for certain services in the form of natural gas, NGLs and condensate rather than cash; or purchasing natural gas from certain producers at the wellhead. We sell natural gas, NGLs and condensate from our gathering and processing operations, which causes us to be in a long position on these transactions. We purchase natural gas at the wellhead from certain producers, which causes us to be in a short position on these transactions. We use a number of different derivative instruments in connection with our commodity price risk management activities. We enter into financial swap and option instruments to hedge our forecasted natural gas, NGLs and condensate sales against the variability in expected future cash flows attributable to changes in market prices. Swap instruments are contractual agreements between counterparties to exchange obligations of money as the underlying natural gas, NGLs and condensate are sold. Under swap agreements, we receive a fixed price and remit a floating price based on certain indices for the relevant contract period. Commodity-based option instruments are contractual agreements that grant the right to receive the difference between a fixed price and a floating price based on certain indices for the relevant contract period, if the floating price is lower than the fixed price. See “Item 8. Financial Statements and Supplementary Data –Note 12” for further discussion of our derivative instruments. Average estimated market prices for NGLs, natural gas and condensate, based upon twelve-month forward price curves as of December 16, 2014, were $0.53 per gallon, $3.58 per million BTU and $58.19 per barrel, respectively. A 10% change in these prices would change our forecasted net income for the twelve-month period ended December 31, 2015 by approximately $14.5 million.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Unitholders

Atlas Pipeline Partners, L.P.

We have audited the accompanying consolidated balance sheets of Atlas Pipeline Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Atlas Pipeline Partners, L.P. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 27, 2015 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

February 27, 2015

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

 

     December 31,
2014
     December 31,
2013
 
ASSETS      

Current assets:

     

Cash and cash equivalents

   $ 8,103       $ 4,914   

Accounts receivable

     240,576         219,297   

Current portion of derivative assets

     88,007         174   

Prepaid expenses and other

     17,368         17,393   
  

 

 

    

 

 

 

Total current assets

  354,054      241,778   

Property, plant and equipment, net

  3,249,973      2,724,192   

Goodwill

  365,763      368,572   

Intangible assets, net

  596,261      696,271   

Equity method investment in joint ventures

  177,212      248,301   

Long-term portion of derivative assets

  37,398      2,270   

Other assets, net

  44,072      46,461   
  

 

 

    

 

 

 

Total assets

$ 4,824,733    $ 4,327,845   
  

 

 

    

 

 

 
LIABILITIES AND EQUITY

Current liabilities:

Current portion of long-term debt

$ 224    $ 524   

Accounts payable – affiliates

  4,438      2,912   

Accounts payable

  87,076      79,051   

Accrued liabilities

  49,729      47,449   

Accrued interest payable

  26,924      26,737   

Current portion of derivative liabilities

  —        11,244   

Accrued producer liabilities

  161,208      152,309   
  

 

 

    

 

 

 

Total current liabilities

  329,599      320,226   

Long-term portion of derivative liabilities

  —        320   

Long-term debt, less current portion

  1,938,886      1,706,786   

Deferred income taxes, net

  30,914      33,290   

Other long-term liabilities

  6,867      7,318   

Commitments and contingencies

Equity:

Class D convertible preferred limited partners’ interests

  538,814      450,749   

Class E preferred limited partners’ interests

  121,852      —     

Common limited partners’ interests

  1,731,764      1,703,778   

General Partner’s interest

  47,775      46,118   
  

 

 

    

 

 

 

Total partners’ capital

  2,440,205      2,200,645   

Non-controlling interest

  78,262      59,260   
  

 

 

    

 

 

 

Total equity

  2,518,467      2,259,905   
  

 

 

    

 

 

 

Total liabilities and equity

$ 4,824,733    $ 4,327,845   
  

 

 

    

 

 

 

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit data)

 

     Years Ended December 31,  
     2014     2013     2012  

Revenue:

      

Natural gas and liquids sales

   $ 2,621,428      $ 1,959,144      $ 1,137,261   

Transportation, processing and other fees – third parties

     200,787        164,874        66,287   

Transportation, processing and other fees – affiliates

     286        303        435   

Derivative gain (loss), net

     131,064        (28,764     31,940   

Other income, net

     21,555        11,292        10,097   
  

 

 

   

 

 

   

 

 

 

Total revenues

  2,975,120      2,106,849      1,246,020   
  

 

 

   

 

 

   

 

 

 

Costs and expenses:

Natural gas and liquids cost of sales

  2,291,914      1,690,382      927,946   

Operating expenses

  113,606      94,527      62,098   

General and administrative

  68,893      55,856      43,406   

Compensation reimbursement – affiliates

  5,050      5,000      3,800   

Other expenses

  6,073      20,005      15,069   

Depreciation and amortization

  202,543      168,617      90,029   

Interest

  93,147      89,637      41,760   
  

 

 

   

 

 

   

 

 

 

Total costs and expenses

  2,781,226      2,124,024      1,184,108   
  

 

 

   

 

 

   

 

 

 

Equity income (loss) in joint ventures

  (14,007   (4,736   6,323   

Gain (loss) on asset dispositions

  47,381      (1,519   —     

Goodwill impairment loss

  —        (43,866   —     

Loss on early extinguishment of debt

  —        (26,601   —     
  

 

 

   

 

 

   

 

 

 

Income (loss) before tax

  227,268      (93,897   68,235   

Income tax expense (benefit)

  (2,376   (2,260   176   
  

 

 

   

 

 

   

 

 

 

Net income (loss)

  229,644      (91,637   68,059   

Income attributable to non-controlling interests

  (13,164   (6,975   (6,010

Preferred unit imputed dividend effect

  (45,513   (29,485   —     

Preferred unit dividends in kind

  (42,552   (23,583   —     

Preferred unit dividends

  (8,233   —        —     
  

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners and the General Partner

$ 120,182    $ (151,680 $ 62,049   
  

 

 

   

 

 

   

 

 

 

Allocation of net income (loss) attributable to:

Common limited partner interest

$ 93,684      (165,923   52,391   

General Partner interest

  26,498      14,243      9,658   
  

 

 

   

 

 

   

 

 

 
$ 120,182    $ (151,680 $ 62,049   
  

 

 

   

 

 

   

 

 

 

Net income (loss) attributable to common limited partners per unit:

Basic

$ 0.95    $ (2.23 $ 0.95   
  

 

 

   

 

 

   

 

 

 

Weighted average common limited partner units (basic)

  82,257      74,364      54,326   
  

 

 

   

 

 

   

 

 

 

Diluted

$ 0.95    $ (2.23 $ 0.95   
  

 

 

   

 

 

   

 

 

 

Weighted average common limited partner units (diluted)

  98,384      74,364      55,138   
  

 

 

   

 

 

   

 

 

 

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

 

     Years Ended December 31,  
     2014      2013     2012  

Net income (loss)

   $ 229,644       $ (91,637   $ 68,059   

Other comprehensive income:

       

Adjustment for realized losses on cash flow hedges reclassified to net income (loss)

     —           —          4,390   
  

 

 

    

 

 

   

 

 

 

Total other comprehensive income

  —        —        4,390   
  

 

 

    

 

 

   

 

 

 

Comprehensive income (loss)

$ 229,644    $ (91,637 $ 72,449   
  

 

 

    

 

 

   

 

 

 

Comprehensive income attributable to non-controlling interests

$ 13,164    $ 6,975    $ 6,010   

Preferred unit imputed dividend effect

  45,513      29,485      —     

Preferred unit dividends in kind

  42,552      23,583      —     

Preferred unit dividends

  8,233      —        —     

Comprehensive income (loss) attributable to common limited partners and the General Partner

  120,182      (151,680   66,439   
  

 

 

    

 

 

   

 

 

 

Comprehensive income (loss)

$ 229,644    $ (91,637 $ 72,449   
  

 

 

    

 

 

   

 

 

 

See accompanying notes to consolidated financial statements

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

(in thousands, except unit data)

 

    Class D
Preferred
Limited
Partner
Units
    Class E
Preferred
Limited
Partner
Units
    Common
Limited
Partner
Units
    Class D
Preferred
Limited
Partners
    Class E
Preferred
Limited
Partners
    Common
Limited
Partners
    General
Partner
    Accumulated
Other
Comprehensive
Loss
    Non-controlling
Interest
    Total  

Balance at January 1, 2012

    —          —          53,617,183     $ —        $ —        $ 1,245,163     $ 23,856     $ (4,390   $ (28,401   $ 1,236,228  

Issuance of units and General Partner capital contribution

    —          —          10,782,462       —          —          321,491       6,865       —          —          328,356  

Equity compensation under incentive plans

    —          —          180,417       —          —          11,549       —          —          —          11,549  

Purchase and retirement of treasury units

    —          —          (24,052     —          —          (695     —          —          —          (695

Distributions paid

    —          —          —          —          —          (122,223     (8,878     —          —          (131,101

Contributions from non-controlling interests

    —          —          —          —          —          —          —          —          182       182  

Other comprehensive income

    —          —          —          —          —          —          —          4,390       —          4,390  

Increase in non-controlling interest related to business combination

    —          —          —          —          —          —          —          —          89,440       89,440  

Net income

    —          —          —          —          —          52,391       9,658       —          6,010       68,059  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2012

    —          —          64,556,010     $ —        $ —        $ 1,507,676     $ 31,501     $ —        $ 67,231     $ 1,606,408  

 

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ATLAS PIPELINE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY CONTINUED

(in thousands, except unit data)

 

    Class D
Preferred
Limited
Partner
Units
    Class E
Preferred
Limited
Partner
Units
    Common
Limited
Partner
Units
    Class D
Preferred
Limited
Partners
    Class E
Preferred
Limited
Partners
    Common
Limited
Partners
    General
Partner
    Accumulated
Other
Comprehensive
Loss
    Non-controlling
Interest
    Total  

Balance at January 1, 2013

    —          —          64,556,010     $ —        $ —        $ 1,507,676     $ 31,501     $ —        $ 67,231     $ 1,606,408  

Issuance of units and General Partner capital contribution

    13,445,383       —          15,740,679       397,681       —          526,263       19,359       —          —          943,303  

Equity compensation under incentive plans

    —          —          288,459       —          —          19,143       —          —          —          19,143  

Distributions paid in kind units

    378,486       —          —          —          —          —          —          —          —          —     

Distributions paid

    —          —          —          —          —          (183,381     (18,985     —          —          (202,366

Contributions from non-controlling interests

    —          —          —          —          —          —          —          —          17,021       17,021  

Distributions to non-controlling interests

    —          —          —          —          —          —          —          —          (1,432     (1,432

Decrease in non-controlling interest related to business combination

    —          —          —          —          —          —          —          —          (30,535     (30,535

Net income (loss)

    —          —          —          53,068       —          (165,923     14,243       —          6,975       (91,637
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Balance at December 31, 2013

    13,823,869       —          80,585,148     $ 450,749     $ —        $ 1,703,778     $ 46,118     $ —        $ 59,260     $ 2,259,905  

Issuance of units and General Partner capital contributions

    —          5,060,000       3,558,005       —          122,258       121,583       2,523       —          —          246,364  

Equity compensation under incentive plans

    —          —          459,232       —          —          25,005       —          —          —          25,005  

Purchase and retirement of treasury units

    —          —          (66,321     —          —          (2,210     —            —          (2,210

Distributions paid in kind units

    1,195,581       —          —          —          —          —          —          —