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As filed with the Securities and Exchange Commission on September 27, 2013

Registration No. 333-            

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

DEVON MIDSTREAM PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

 

Delaware		4922		80-0952247
(State or Other Jurisdiction of Incorporation or Organization)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification Number)

333 West Sheridan Avenue

Oklahoma City, Oklahoma 73102

(405) 235-3611

(Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)

 

 

Lyndon C. Taylor

Executive Vice President, General Counsel and Corporate Secretary

333 West Sheridan Avenue

Oklahoma City, Oklahoma 73102

(405) 235-3611

(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)

 

 

Copies to:

 

David P. Oelman Alan Beck Vinson & Elkins L.L.P. 1001 Fannin Street, Suite 2500 Houston, Texas 77002 (713) 758-2222		William N. Finnegan, IV Ryan J. Maierson Latham & Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400

 

 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer		¨		Accelerated filer		¨
Non-accelerated filer		x  (Do not check if a smaller reporting company)		Smaller reporting company		¨

 

 

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of Securities to be Registered		Proposed Maximum Aggregate Offering Price (1)(2)		Amount of Registration Fee
Common units representing limited partner interests		$400,000,000		$54,560

(1)	Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2)	Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

 

 

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

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The information in this preliminary prospectus is not complete and may be changed. The securities described herein may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy such securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to Completion, dated September 27, 2013

PROSPECTUS

 

Common Units

Representing Limited Partner Interests

Devon Midstream Partners, L.P.

 

 

This is the initial public offering of our common units representing limited partner interests of Devon Midstream Partners, L.P. We were recently formed by Devon Energy Corporation. We are offering              common units in this offering. Prior to this offering, there has been no public market for our common units. We currently expect the initial public offering price to be between $             and $             per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “DVNM.”

 

 

Investing in our common units involves risks. See “Risk Factors” on page 19.

 

 

These risks include the following:

 

•

We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to our unitholders.

 

•

We are dependent on Devon Energy Corporation, or Devon, for substantially all of the natural gas that Devon Midstream Holdings, L.P., which we refer to as Devon Midstream Holdings, gathers, processes and transports. After Devon Midstream Holdings’ five-year minimum volume commitments from Devon, a material decline in the volumes of natural gas that Devon Midstream Holdings gathers, processes and transports for Devon would result in a material decline in our operating results and cash available for distribution.

 

•

Our only asset is a 20% interest in Devon Midstream Holdings, over which we have operating control. Because our interest in Devon Midstream Holdings represents our only cash-generating asset, our cash flow will depend entirely on the performance of Devon Midstream Holdings and its ability to distribute cash to us.

 

•

Any decrease in the volumes of natural gas that Devon Midstream Holdings gathers, processes or transports or in the volumes of NGLs that it fractionates would adversely affect our financial condition, results of operations and cash flows to the extent not protected by minimum volume commitments.

 

•

Devon will own an 80% interest in Devon Midstream Holdings and will control our general partner, which has sole responsibility for conducting our business and managing our operations, and we will own the general partner of Devon Midstream Holdings which is responsible for managing the operations of Devon Midstream Holdings. Our general partner and its affiliates, including Devon, have conflicts of interest with, and defined fiduciary duties with respect to, us and our unitholders, and may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over Devon’s business decisions and operations, and Devon is under no obligation to adopt a business strategy that favors us.

 

•

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units with contractual standards governing its duties.

 

•

Unitholders have very limited voting rights and are not entitled to appoint or remove our general partner or elect the board of directors of our general partner.

 

•

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as Devon Midstream Holdings and us not being subject to material incremental entity-level taxation. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, or if we or Devon Midstream Holdings become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

 

 

		Per Common Unit				Total
Initial public offering price		$				$
Underwriting discount (1)		$				$
Proceeds to Devon Midstream Partners, L.P. (before expenses)		$				$

 

(1)	Excludes a fixed aggregate structuring fee of $1,200,000 payable to Merrill Lynch, Pierce, Fenner & Smith Incorporated and Barclays Capital Inc. Please read “Underwriting.”

The underwriters may purchase up to an additional              common units from Devon Midstream Partners, L.P. at the public offering price, less the underwriting discount, within 30 days from the date of this prospectus.

The underwriters expect to deliver the common units to purchasers on or about                                  through the book-entry facilities of The Depository Trust Company.

 

 

Joint Book-Running Managers

 

BofA Merrill Lynch		Barclays

 

 

The date of this prospectus is                                              .

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TABLE OF CONTENTS

 

SUMMARY			1
Overview			1
Business Strategies			3
Competitive Strengths			4
Our Contractual Relationship with Devon			5
Risk Factors			5
Formation Transactions and Partnership Structure			6
Ownership of Devon Midstream Partners, L.P.			7
Management of Our Partnership			8
Principal Executive Offices and Internet Address			8
Conflicts of Interest and Fiduciary Duties			9
The Offering			10
Summary Historical and Pro Forma Financial and Operating Data			14
Non-GAAP Financial Measure			17
RISK FACTORS			19
Risks Related to Our Business			19
Risks Inherent in an Investment in Us			32
Tax Risks to Common Unitholders			41
USE OF PROCEEDS			46
CAPITALIZATION			47
DILUTION			48
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS			49
General			49
Our Minimum Quarterly Distribution			51
Unaudited Pro Forma Distributable Cash Flow for the Twelve Months Ended June 30, 2013 and the Year Ended December 31, 2012			52
Unaudited Estimated Distributable Cash Flow for the Twelve Months Ending September 30, 2014			56
Assumptions and Considerations			59
HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS			64
Distributions of Available Cash			64
Operating Surplus and Capital Surplus			65
Capital Expenditures			67
Subordination Period			68
Distributions of Available Cash From Operating Surplus During the Subordination Period			70
Distributions of Available Cash From Operating Surplus After the Subordination Period			70
General Partner Interest			70
Incentive Distribution Rights			71
Percentage Allocations of Available Cash From Operating Surplus			71
Devon’s Right to Reset Incentive Distribution Levels			72
Distributions From Capital Surplus			74
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels			75
Distributions of Cash Upon Liquidation			75
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND OPERATING DATA			78
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			80
Overview			80
Our Operations			81
How We Evaluate Our Operations			82
Items Affecting Comparability of Our Financial Results			83
General Trends and Outlook			84
Results of Our Predecessor’s Operations			86
Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012			87
Year Ended December 31, 2012 Compared to Year Ended December 31, 2011			89
Year Ended December 31, 2011 Compared to Year Ended December 31, 2010			90
Our Liquidity and Capital Resources			92
Our Critical Accounting Policies and Estimates			94

 

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Quantitative Disclosures About Market Risk			96
INDUSTRY OVERVIEW			97
General			97
Natural Gas Midstream Services			98
Crude Oil Gathering and Transportation			101
U.S. Natural Gas Market Fundamentals			101
Key Basins in Which We Operate			104
BUSINESS			106
Overview			106
Business Strategies			108
Competitive Strengths			109
Our Contractual Relationship with Devon			110
Devon Midstream Holdings’ Assets			110
Competition			119
Safety and Maintenance Regulation			120
Regulation of Operations			122
Environmental Matters			124
Title to Properties and Rights-of-Way			128
Employees			128
Legal Proceedings			128
MANAGEMENT			129
Management of Devon Midstream Partners, L.P.			129
Director Independence			129
Committees of the Board of Directors			129
Directors and Executive Officers			130
Reimbursement of Expenses of Our General Partner			131
Compensation of Our Directors			131
Executive Compensation			131
Equity Plan			133
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			136
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			137
Distributions and Payments to Our General Partner and its Affiliates			137
Agreements Governing the Transactions			138
Competition			140
Contracts with Affiliates			140
Procedures for Review, Approval and Ratification of Transactions with Related Persons			142
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES			143
Conflicts of Interest			143
Fiduciary Duties			147
DESCRIPTION OF THE COMMON UNITS			150
The Units			150
Transfer Agent and Registrar			150
Transfer of Common Units			150
THE PARTNERSHIP AGREEMENT			152
Organization and Duration			152
Purpose			152
Cash Distributions			152
Capital Contributions			152
Voting Rights			153
Applicable Law; Forum, Venue and Jurisdiction			154
Limited Liability			154
Issuance of Additional Interests			155

 

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Amendment of the Partnership Agreement			156
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets			158
Dissolution			158
Liquidation and Distribution of Proceeds			159
Withdrawal or Removal of Our General Partner			159
Transfer of General Partner Interest			160
Transfer of Ownership Interests in the General Partner			160
Transfer of Subordinated Units and Incentive Distribution Rights			160
Change of Management Provisions			161
Limited Call Right			161
Non-Taxpaying Holders; Redemption			161
Non-Citizen Assignees; Redemption			162
Meetings; Voting			162
Voting Rights of Incentive Distribution Rights			163
Status as Limited Partner			163
Indemnification			163
Reimbursement of Expenses			164
Books and Reports			164
Right to Inspect Our Books and Records			164
Registration Rights			165
UNITS ELIGIBLE FOR FUTURE SALE			166
Issuance of Additional Interests			166
Registration Rights			166
Lock-up Agreement			167
MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES			168
Taxation of the Partnership			168
Tax Consequences of Unit Ownership			170
Tax Treatment of Operations			174
Disposition of Units			175
Uniformity of Units			177
Tax-Exempt Organizations and Other Investors			177
Administrative Matters			178
State, Local and Other Tax Considerations			180
INVESTMENT BY EMPLOYEE BENEFIT PLANS			181
UNDERWRITING			182
VALIDITY OF OUR COMMON UNITS			188
EXPERTS			188
WHERE YOU CAN FIND MORE INFORMATION			188
FORWARD-LOOKING STATEMENTS			189
INDEX TO FINANCIAL STATEMENTS			F-1
APPENDIX A – AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF DEVON MIDSTREAM PARTNERS, L.P.			A-1
APPENDIX B – GLOSSARY OF TERMS			B-1

 

 

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

 

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This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read “Risk Factors” and “Forward-Looking Statements.”

Industry and Market Data

This prospectus includes industry data and forecasts that we obtained from industry publications and surveys, public filings and internal company sources. Industry publications and surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable, but there can be no assurance as to the accuracy or completeness of the included information. Statements as to our market position and market estimates are based on independent industry publications, government publications, third-party forecasts, management’s estimates and assumptions about our markets and our internal research. While we are not aware of any misstatements regarding the market, industry or similar data presented herein, such data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Forward-Looking Statements” and “Risk Factors” in this prospectus.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and should not be read to, imply a relationship with or endorsement or sponsorship of us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

 

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RISK FACTORS

Limited partner interests are inherently different from 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 similar businesses. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment.

Risks Related to Our Business

We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution to our unitholders.

In order to make our minimum quarterly distribution of $             per common unit and subordinated unit per quarter, or $             per unit per year, we will require available cash of approximately $             million per quarter, or approximately $             million per year, based on the common units and subordinated units outstanding immediately after completion of this offering. We may not generate sufficient cash flow each quarter to support the payment of the minimum quarterly distribution or to increase our quarterly distributions in the future.

Our ability to distribute cash to our unitholders is or may be limited by a number of factors, including, among others:

 

•

the level and timing of capital expenditures we make;

 

•

our debt service requirements and other liabilities;

 

•

our ability to make borrowings under our debt agreements to pay distributions;

 

•

fluctuations in our working capital needs;

 

•

restrictions on distributions contained in any of our debt agreements;

 

•

the cost of acquisitions, if any;

 

•

fees and expenses of our general partner and its affiliates we are required to reimburse;

 

•

the amount of cash reserves established by our general partner; and

 

•

other business risks affecting our cash levels.

The assumptions underlying the forecast of cash available for distribution, as set forth in “Our Cash Distribution Policy and Restrictions on Distributions,” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions on Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the twelve months ending September 30, 2014. Our ability to pay the full minimum quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in “Our Cash Distribution Policy and Restrictions on Distributions.” Management has prepared the financial

 

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forecast and has not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

We are dependent on Devon for substantially all of the natural gas that Devon Midstream Holdings gathers, processes and transports. After Devon Midstream Holdings’ five-year minimum volume commitments from Devon, a material decline in the volumes of natural gas that Devon Midstream Holdings gathers, processes and transports for Devon would result in a material decline in our operating results and cash available for distribution.

We rely on Devon for substantially all of Devon Midstream Holdings’ natural gas supply and do not expect to materially increase volumes from third-party producers in the near term. For the year ended December 31, 2012, Devon accounted for approximately 94% of Devon Midstream Holdings’ natural gas supply. For the foreseeable future, we expect our profitability to remain substantially dependent on the volume of natural gas that Devon Midstream Holdings gathers, processes and transports on its systems. In order to minimize volumetric exposure, Devon Midstream Holdings will receive five-year minimum volume commitments from Devon at the Bridgeport processing facility, Bridgeport and East Johnson County gathering systems and the Cana and Northridge systems. These minimum volume commitments represent 88% of the total projected volumes for these assets for the twelve months ending September 30, 2014. After the expiration of these five-year minimum volume commitments, a material decline in the volume of natural gas that Devon Midstream Holdings gathers and transports on its systems would result in a material decline in our total operating revenues and cash available for distribution. In addition, Devon may determine in the future that drilling activity in other areas of operation is strategically more attractive. A shift in Devon’s focus away from Devon Midstream Holdings’ areas of operation could result in reduced throughput on Devon Midstream Holdings’ systems after the five-year minimum volume commitments expire and cause a material decline in our total operating revenues and cash available for distribution.

Our only asset is a 20% interest in Devon Midstream Holdings, over which we have operating control. Because our interest in Devon Midstream Holdings represents our only cash-generating asset, our cash flow will depend entirely on the performance of Devon Midstream Holdings and its ability to distribute cash to us.

We are a holding company with no material operations and only limited assets, and the source of our earnings and cash flow will consist exclusively of cash distributions from Devon Midstream Holdings. Therefore, our ability to make quarterly distributions to our unitholders will be completely dependent on the performance of Devon Midstream Holdings and its ability to distribute funds to us.

Devon Midstream Holdings’ limited partnership agreement requires it to distribute all of its available cash each quarter, less the amounts of cash reserves that the board of directors of its general partner determines are necessary or appropriate in its reasonable discretion to provide for the proper conduct of Devon Midstream Holdings’ business, to enable it to make distributions to us so that we can make timely distributions, or to comply with applicable law or any of Devon Midstream Holdings’ debt or other agreements. For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The amount of cash Devon Midstream Holdings generates from its operations will fluctuate from quarter to quarter based on, among other things:

 

•

the volume of natural gas it gathers, processes and transports, and the volume of NGLs it fractionates;

 

•

the fees it charges and the margins it realizes for its services;

 

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•

regulatory action affecting the supply of or demand for natural gas, its operations, the rates it can charge, how it contracts for services, its existing contracts, its operating costs or its operating flexibility;

 

•

the level of its operating, maintenance and general and administrative costs; and

 

•

prevailing economic conditions.

In addition, the actual amount of cash Devon Midstream Holdings will have available for distribution to its partners, including us, also will depend on other factors, such as:

 

•

the level of capital expenditures it makes;

 

•

its debt service requirements and other liabilities;

 

•

restrictions contained in its debt agreements;

 

•

its ability to borrow funds;

 

•

fluctuations in its working capital needs;

 

•

the cost of acquisitions, if any; and

 

•

the amount of cash reserves established by it.

Any decrease in the volumes of natural gas that Devon Midstream Holdings gathers, processes or transports or in the volumes of NGLs that it fractionates would adversely affect our financial condition, results of operations and cash flows to the extent not protected by minimum volume commitments.

Our financial performance depends to a large extent on the volumes of natural gas gathered, processed and transported and the volumes of NGLs fractionated on Devon Midstream Holdings’ assets. To the extent not protected by the minimum volume commitments, decreases in the volumes of natural gas gathered, processed or transported or in the volumes of NGLs fractionated by Devon Midstream Holdings’ assets would directly and adversely affect our revenues and results of operations. These volumes can be influenced by factors beyond our control, including:

 

•

environmental or other governmental regulations;

 

•

weather conditions;

 

•

increases in storage levels of natural gas and NGLs;

 

•

increased use of alternative energy sources;

 

•

decreased demand for natural gas and NGLs;

 

•

fluctuations in commodity prices, including the prices of natural gas and NGLs;

 

•

economic conditions;

 

•

supply disruptions;

 

•

availability of supply connected to Devon Midstream Holdings’ systems; and

 

•

availability and adequacy of infrastructure to gather and process supply into and out of Devon Midstream Holdings’ systems.

The volumes of natural gas gathered, processed, and transported and volumes of NGLs fractionated on Devon Midstream Holdings’ assets also depend on the production of natural gas and NGLs from the regions that supply these systems. Supply of natural gas and NGLs can be affected by many of the factors listed above, including commodity prices and weather. In order to maintain or increase throughput levels on Devon Midstream Holdings’ systems, it must obtain new sources of natural gas. The primary factors affecting Devon Midstream Holdings’ ability to obtain non-dedicated sources of natural gas include (i) the level of successful leasing, permitting and drilling activity in its areas of operation, (ii) its ability to compete for volumes from new wells

 

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and (iii) its ability to compete successfully for volumes from sources connected to other pipelines. Devon Midstream Holdings has no control over the level of drilling activity in its areas of operation, the amount of reserves associated with wells connected to its systems or the rate at which production from a well declines. In addition, it has no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, levels of reserves, availability of drilling rigs and other costs of production and equipment.

We may not be able to increase Devon Midstream Holdings’ third-party gathering, processing and transportation volumes and resulting revenue due to competition and other factors, which could limit our ability to grow and increase our dependence on Devon.

Part of our growth strategy includes diversifying our customer base by identifying opportunities to offer services to third parties. For both the six months ended June 30, 2013 and the year ended December 31, 2012, Devon accounted for approximately 91% of our total operating revenues. Our ability to increase our third-party throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which we have available capacity when third-party shippers require it. To the extent that we lack available capacity on Devon Midstream Holdings’ systems for third-party volumes, we may not be able to compete effectively with third-party systems for additional oil and natural gas production in Devon Midstream Holdings’ areas of operation. Some of our natural gas and NGL marketing competitors have greater financial resources and access to larger supplies of natural gas than those available to us, which could allow those competitors to price their services more aggressively than we do.

Our efforts to attract new unaffiliated customers may be adversely affected by (i) our relationship with Devon and (ii) our desire to provide services pursuant to fee-based contracts. Our potential customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

We depend on Devon Midstream Holdings’ natural gas processing facilities, gathering systems and fractionation facilities located in the Barnett, Cana-Woodford and Arkoma-Woodford Shales as well as the Gulf Coast for all of our revenues. If the utilization of these assets was reduced significantly, there would be a material adverse effect on our ability to make distributions to our unitholders.

All of Devon Midstream Holdings’ assets are located in the Barnett, Cana-Woodford and Arkoma-Woodford Shales as well as the Gulf Coast, and we intend to focus our future capital expenditures largely on developing our business in these areas. As a result, our operations lack diversification and any significant decline in utilization of these systems would result in materially lower levels of revenues and cash flow. Operations at Devon Midstream Holdings’ processing facilities and related assets in the Barnett, Cana-Woodford and Arkoma-Woodford Shales as well as the Gulf Coast could be partially curtailed or completely shut down, temporarily or permanently, as a result of:

 

•

operational problems, labor difficulties or environmental proceedings or other litigation that compel cessation of all or a portion of our operations;

 

•

leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;

 

•

damage to pipelines, facilities, plants, related equipment and surrounding properties caused by hurricanes, earthquakes, floods, fires, severe weather, explosions and other natural disasters and acts of terrorism including damage to third-party pipelines or facilities upon which we rely for transportation services;

 

•

sustained reductions in exploration or production activity by producers in the Barnett, Cana-Woodford and Arkoma-Woodford Shales as well as the Gulf Coast, primarily Devon;

 

•

an inability to obtain sufficient quantities of natural gas for Devon Midstream Holdings’ systems; or

 

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force majeure or similar events affecting natural gas or NGL take-away pipelines or market outlets connected to Devon Midstream Holdings’ systems.

The magnitude of the effect on us of any curtailment of operations will depend on the length of the curtailment and the extent of the operations affected by such curtailment. We have no control over many of the factors that may lead to a curtailment of operations.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow and not solely on profitability, which may prevent us from making distributions, even during periods in which we record net income.

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss for financial accounting purposes, and conversely, we might fail to make cash distributions during periods when we record net income for financial accounting purposes.

Our construction or purchase of new assets may not result in revenue increases and may be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our cash flows, results of operations and financial condition and, as a result, our ability to distribute cash to our unitholders.

The construction of additions or modifications to Devon Midstream Holdings’ existing systems and the construction or purchase of new midstream assets involves numerous regulatory, environmental, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. Financing may not be available on economically acceptable terms or at all. If we undertake these projects, we may not be able to complete them 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 pipeline or construct a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues until the project is completed. Moreover, we may construct facilities to capture anticipated future production growth in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering and processing assets will generally require us to obtain new rights-of-way prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

We may be unable to grow by acquiring the interest in Devon Midstream Holdings owned by Devon, which could limit our ability to increase our cash available for distribution.

A portion of our strategy to grow our business and increase distributions to our unitholders is dependent on our ability to make acquisitions that result in an increase in cash available for distribution. The acquisition component of our growth strategy is based, in large part, on our expectation of ongoing divestitures by Devon of portions of its remaining ownership interest in Devon Midstream Holdings to us. We have only a right of first offer pursuant to an agreement to purchase the 80% interest in Devon Midstream Holdings being retained by Devon at the closing of this offering. Devon is not obligated to offer us the opportunity to purchase this interest. We may never purchase all or a portion of this interest for several reasons, including the following:

 

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Devon may choose not to sell the interest.

 

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We may decide not to make an offer for the interest.

 

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We may be unable to agree on acceptable purchase terms with Devon.

 

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•

We may be unable to obtain financing for the purchase on acceptable terms or at all.

 

•

We may be prohibited by the terms of credit facilities, indentures or other contracts from purchasing some or all of the interest, and Devon may be prohibited by the terms of its credit facilities, indentures or other contracts from selling some or all of such interest. If we or Devon must seek waivers of such provisions or refinance debt governed by such provisions in order to consummate a sale of the interest, we or Devon may be unable to do so in a timely manner or at all.

We do not know when or if any such interest will be offered to us to purchase, and we can offer no assurance that we will be able to successfully consummate any future acquisition of such interest in Devon Midstream Holdings. Furthermore, if Devon reduces its ownership interest in us, it may be less willing to sell its remaining ownership interest in Devon Midstream Holdings to us. In addition, there are no restrictions on Devon’s ability to transfer its ownership interest in Devon Midstream Holdings to a third party. If we do not acquire a significant portion of Devon’s remaining 80% interest in Devon Midstream Holdings, our ability to grow our business and increase our distributions to unitholders may be limited.

If third-party pipelines or other midstream facilities interconnected to Devon Midstream Holdings’ gathering or transportation systems become partially or fully unavailable, or if the volumes Devon Midstream Holdings gathers, processes or transports does not meet the natural gas quality requirements of such pipelines or facilities, our operating margin and cash flow and our ability to make distributions to our unitholders could be adversely affected.

Devon Midstream Holdings’ gathering, processing and transportation assets connect to other pipelines or facilities owned and operated by unaffiliated third parties, such as Atmos Energy, Enogex, ONEOK Partners and others. The continuing operation of such third-party pipelines, processing facilities and other midstream facilities is not within our control. These pipelines, plants and other midstream facilities may become unavailable because of testing, turnarounds, line repair, maintenance, reduced operating pressure, lack of operating capacity, regulatory requirements and curtailments of receipt or deliveries due to insufficient capacity or because of damage from severe weather conditions or other operational issues. In addition, if the costs to us to access and transport on these third-party pipelines significantly increase, our profitability could be reduced. If any such increase in costs occurs, if any of these pipelines or other midstream facilities become unable to receive, transport or process natural gas, or if the volumes Devon Midstream Holdings gathers or transports do not meet the natural gas quality requirements of such pipelines or facilities, our operating margin and ability to make cash distributions to our unitholders could be adversely affected.

Because of the natural decline in production from existing wells in Devon Midstream Holdings’ areas of operation, our success depends, in part, on producers replacing declining production and also on our ability to secure new sources of natural gas. Any decrease in the volumes of natural gas that Devon Midstream Holdings gathers and processes could adversely affect our business and operating results.

The natural gas volumes that support our business depend on the level of production from natural gas wells connected to Devon Midstream Holdings’ systems, which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on Devon Midstream Holdings’ systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity in Devon Midstream Holdings’ areas of operation, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.

We have no control over the level of drilling activity in Devon Midstream Holdings’ areas of operation, the amount of reserves associated with wells connected to Devon Midstream Holdings’ systems or the rate at which production from a well declines. In addition, we have no control over Devon or other producers or their drilling or production decisions, which are affected by, among other things:

 

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the availability and cost of capital;

 

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prevailing and projected natural gas and NGL prices;

 

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demand for natural gas and NGLs;

 

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levels of reserves;

 

•

geologic considerations;

 

•

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

 

•

the costs of producing the gas, the availability and costs of drilling rigs and other equipment.

Fluctuations in energy prices can also greatly affect the development of natural gas reserves. Drilling and production activity generally decreases as natural gas prices decrease. Declines in natural gas prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in Devon Midstream Holdings’ areas of operation could lead to reduced utilization of Devon Midstream Holdings’ assets.

Due to these and other factors, even if oil and natural gas reserves are known to exist in areas served by Devon Midstream Holdings’ assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on Devon Midstream Holdings’ systems, those reductions could reduce our revenue and cash flow and adversely affect our ability to make cash distributions to our unitholders.

Our exposure to commodity price risk may vary over time.

We currently generate all of our revenues pursuant to fee-based contracts under which we are paid based on the volumes of oil and natural gas that Devon Midstream Holdings gathers, processes and transports, rather than the underlying value of the oil or natural gas. Consequently, our existing operations and cash flows have no direct exposure to commodity price risk. Although we intend to enter into similar fee-based contracts with new customers in the future, our efforts to negotiate such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of oil, natural gas and NGL prices could have a material adverse effect on our business, results of operations and financial condition.

A change in the jurisdictional characterization of some of Devon Midstream Holdings’ assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of such assets, which may cause our revenues to decline and our operating expenses to increase.

Most of Devon Midstream Holdings’ natural gas gathering and transportation operations are exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA. Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from regulation by FERC under the NGA. Although the FERC has not made any formal determinations with respect to any of Devon Midstream Holdings’ facilities, we believe that the natural gas pipelines in its gathering systems meet the traditional tests FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. However, the classification and regulation of some of its natural gas gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress. If the FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the Natural Gas Policy Act of 1978, or NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows.

 

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Other FERC regulations may indirectly impact our businesses and the markets for products derived from these businesses. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, gas quality, capacity release and market center promotion, may indirectly affect the intrastate natural gas market. Should Devon Midstream Holdings fail to comply with all applicable FERC administered statutes, rules, regulations and orders, Devon Midstream Holdings could be subject to substantial penalties and fines, which could have a material adverse effect on our results of operations and cash flows. FERC has civil penalty authority under the NGA and NGPA to impose penalties for current violations of up to $1,000,000 per day for each violation and disgorgement of profits associated with any violation.

State regulation of natural gas gathering facilities and intrastate transportation pipelines generally includes various safety, environmental and, in some circumstances, nondiscriminatory take and common purchaser requirements, as well as complaint-based rate regulation. Texas has adopted regulations that generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering and intrastate transportation pipeline access and rate discrimination. Other state regulations may not directly apply to our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including Texas’ regulation of production rates and maximum daily production allowable from natural gas wells.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. Devon Midstream Holdings’ gathering and intrastate transportation operations could be adversely affected in the future should they become subject to the application of state or federal regulation of rates and services. These operations may also be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of such facilities. 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. For more information regarding federal and state regulation of our operations, please read “Business—Regulation of Operations.”

The Acacia transmission system is subject to regulation by the FERC pursuant to Section 311 of the NGPA, which could have an adverse impact on Devon Midstream Holdings’ ability to establish transportation rates that would allow it to recover the full cost of operating the Acacia transmission system, including a reasonable return, and cash available for distribution.

FERC has jurisdiction over transportation rates charged by the Acacia transmission system for transporting natural gas in interstate commerce under Section 311 of the NGPA. Rates to provide such services must be “fair and equitable” under the NGPA and are subject to review and approval by the FERC at least once every five years. Accordingly, such regulation may have an adverse impact on Devon Midstream Holdings’ ability to establish transportation rates that would allow us to recover the full cost of operating its Acacia transmission system, including a reasonable return, and cash available for distribution. For more information regarding regulation of Devon Midstream Holdings’ operations, please read “Business—Regulation of Operations.”

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

An increasing percentage of our customers’ oil and gas production is being developed from unconventional sources, such as deep gas shales. These reservoirs require hydraulic fracturing completion processes to release the gas from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate production. The U.S. Environmental Protection Agency, or the EPA, has commenced a study of the potential environmental impacts of hydraulic fracturing activities. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such

 

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legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenues and results of operations.

We may incur significant costs and liabilities in complying with, or as a result of a failure to comply with, new or existing environmental laws and regulations, and changes in environmental laws or regulations, could adversely impact our customers’ production and operations, which could have a material adverse effect on our results of operations and cash flows.

As an owner, lessee or operator of natural gas gathering, processing and transportation operations, Devon Midstream Holdings is subject to various stringent federal, state, provincial, tribal and local laws and regulations relating to the discharge of materials into, and protection of, the environment. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in joint and several, strict liability and the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which Devon Midstream Holdings’ gathering systems pass and facilities where its wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, Devon Midstream Holdings may experience a delay in obtaining or be unable to obtain required permits, which may cause it to lose potential and current customers, interrupt its operations and limit its growth and revenues, which in turn could affect our profitability. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability. Please read “Business—Environmental Matters” for more information.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the services we provide.

Policymakers in the U.S. are increasingly focusing on whether the emissions of greenhouse gases, or GHGs, such as carbon dioxide and methane, are contributing to harmful climatic changes. Policymakers at both the U.S. federal and state levels have introduced legislation and proposed new regulations that are designed to quantify and limit the emission of GHGs through inventories, limitations and/or taxes on GHG emissions. Legislative initiatives and discussions to date have focused on the development of cap-and-trade and/or carbon tax programs. A cap-and-trade program generally would cap overall GHG emissions on an economy-wide basis and require major sources of GHG emissions or major fuel producers to acquire and surrender emission allowances. Cap-and-trade programs could be relevant to us and our operations in several ways. First, the equipment we use to process and transport oil and natural gas emits GHGs. We could therefore be subject to caps and penalties if emissions exceeded the caps. Second, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other GHGs. Therefore, demand for our products could be reduced by the imposition of caps and penalties on our customers. Carbon taxes could likewise affect us to the extent they apply to emissions from our equipment and/or emissions resulting from use of our products by our customers. Of overriding significance would be the point of regulation or taxation. Application of caps or taxes on companies such as Devon Midstream Holdings, based on carbon content of produced oil and gas volumes rather than on consumer emissions, could lead to penalties, fees or tax assessments for which there are no mechanisms to pass them through the distribution and consumption chain where fuel use or conservation choices are made. Although it presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. Independent of Congress, the EPA has begun to regulate the emission of GHGs under the Clean

 

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Air Act. These regulations include monitoring and reporting obligations as well as pre-construction permitting requirements. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily the planned development of emission inventories or GHG cap and trade programs as described above. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. We cannot predict with any certainty at this time how these possibilities may affect our operations.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair or preventative or remedial measures.

The United States Department of Transportation, or DOT, has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

 

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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 preventive and mitigating actions.

The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. On August 13, 2012, the Pipelines and Hazardous Materials Safety Administration, or PHMSA, published a proposed rulemaking consistent with the signed act that, once finalized, will increase the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a related series of violations. Should Devon Midstream Holdings fail to comply with DOT or comparable state regulations, it could be subject to substantial penalties and fines. PHMSA published a final rule in May 2011 expanding pipeline safety requirements including added reporting obligations and integrity management standards to certain rural low-stress hazardous liquid pipelines that were not previously regulated in such manner.

PHMSA has also published advanced notices of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to extend the integrity management requirements to additional types of facilities pipelines, such as gathering pipelines and related facilities. In addition, PHMSA recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure, which could result in additional pressure testing of pipelines or the reduction of maximum operating pressures. The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards could require Devon Midstream Holdings to install new or modified safety controls, pursue new capital projects, or conduct maintenance programs on an accelerated basis, all of which could require Devon Midstream Holdings to incur increased operational costs that could be significant. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our cash flow. Please read “Business—Safety and Maintenance Regulation” for more information.

 

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We will be required to make substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished or our financial leverage could increase.

In order to increase our asset base, we will need to make expansion capital expenditures. If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and, as a result, we will be unable to raise the level of our future cash distributions. To fund our expansion capital expenditures and investment capital expenditures, we will be required to use cash from our operations or incur borrowings. Alternatively, we may sell additional common units or other securities to fund our capital expenditures. Such uses of cash from our operations will reduce cash available for distribution to our unitholders. Our ability to obtain bank financing or our ability to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering and the covenants in our or Devon Midstream Holdings’ existing debt agreements, as well as by general economic conditions, contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to distribute cash and, accordingly, the market price for our common units.

Devon Midstream Holdings’ operations are subject to all of the hazards inherent in the gathering, processing and transporting of natural gas and the fractionation of NGLs, including:

 

•

damage to pipelines and processing facilities, related equipment and surrounding properties caused by natural disasters, acts of terrorism and acts of third parties;

 

•

damage from construction, farm and utility equipment as well as other subsurface activity;

 

•

leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;

 

•

fires, ruptures and explosions; and

 

•

other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage, and they may result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations.

To mitigate financial losses resulting from these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage against certain losses resulting from physical damages, business interruption and pollution events that are considered sudden and accidental. However, we are not fully insured against all risks inherent to our business and our insurance coverage does not provide 100 percent reimbursement of potential losses resulting from these hazards. Insurance coverage is generally not available to us for pollution events that are considered gradual, and we have limited or no insurance coverage for certain risks such as political risk, war and terrorism. Our insurance coverage does not cover penalties or fines assessed by governmental authorities. If a significant accident or event occurs that is not fully insured, it could adversely affect our revenues, earnings and cash flows.

 

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In addition, we may not be able to maintain or obtain insurance of the type and amount we desire at acceptable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may increase substantially. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage.

Some of Devon Midstream Holdings’ facilities may be subject to claims by neighbors that the facilities interfere with the use or enjoyment of their property.

Although Devon Midstream Holdings’ facilities are generally in rural areas, some may be in proximity to residences or other inhabited tracts. These neighbors may claim that Devon Midstream Holdings’ gathering, processing, transportation and fractionation assets interfere with their use or enjoyment of such property and its resale value. We may not be able to recover the costs to defend, settle or litigate these claims through insurance or increased revenues, which may materially reduce our net earnings and Adjusted EBITDA and have a material adverse effect on our ability to make cash distributions to you.

Devon Midstream Holdings does not own all of the land on which its pipelines and facilities are located, which could result in disruptions to its operations.

Devon Midstream Holdings does not own all of the land on which its pipelines and facilities have been constructed, and it is, therefore, subject to the possibility of more onerous terms or increased costs to retain necessary land use if it does not have valid rights-of-way or if such rights-of-way lapse or terminate. Devon Midstream Holdings obtains the rights to construct and operate its pipelines on land owned by third parties and governmental agencies for a specific period of time. Devon Midstream Holdings’ loss of these rights, through its inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to you.

Our costs may increase if Devon elects not to guarantee Devon Midstream Holdings’ credit obligations under contractual arrangements.

Devon may elect not to provide credit support for Devon Midstream Holdings’ obligations under commercial contracts governing its business or operations. Consequently, Devon Midstream Holdings may need to provide its own credit support arrangements for commercial contracts, which may result in higher costs than currently anticipated.

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

We depend on the leadership, involvement and services of a relatively small group of our general partner’s key management personnel, including its Chief Executive Officer and other executive officers and key technical and commercial personnel. The services of these individuals may not be available to us in the future. Because competition for experienced personnel in the midstream industry is intense, we may not be able to find acceptable replacements with comparable skills and experience. Accordingly, the loss of the services of one or more of these individuals could have a material adverse effect on our ability to operate our business.

We do not have any officers or employees and rely solely on officers of our general partner and employees of Devon.

We are managed and operated by the board of directors and officers of our general partner. Affiliates of Devon conduct businesses and activities of their own in which we have no economic interest, including businesses and activities relating to Devon. As a result, there could be material competition for the time and effort of the officers and employees who provide services to our general partner and Devon. If the officers of our general partner and the employees of Devon do not devote sufficient attention to the management and operation of our business, our financial results may suffer, and our ability to make distributions to our unitholders may be reduced.

 

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Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future level of debt could have important consequences to us, including the following:

 

•

our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required drilling pad connections and well connections pursuant to our gas gathering agreements as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

 

•

our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

 

•

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

•

our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.

Increases in interest rates could adversely affect our business.

We will have significant exposure to increases in interest rates. After the consummation of this offering on a pro forma basis, we do not expect to have any outstanding indebtedness. However, in connection with this offering we will enter into a $         million revolving credit facility. Assuming our average debt level of $         million, comprised of funds drawn on our revolving credit facility, an increase of one percentage point in the interest rates will result in an increase in annual interest expense of $         million. As a result, our results of operations, cash flows and financial condition could be materially adversely affected by significant increases in interest rates.

Our industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in the Barnett, Cana-Woodford and Arkoma-Woodford Shales for production other than from Devon. Some of our competitors may expand or construct gathering, processing and transportation systems or NGL fractionation facilities that would create additional competition for the activities we perform. In addition, our customers who are significant producers of natural gas may develop their own gathering, processing and transportation systems or NGL fractionation facilities in lieu of using Devon Midstream Holdings’ systems. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and, as a result, our ability to make cash distributions to our unitholders.

 

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Risks Inherent in an Investment in Us

Devon will own an 80% interest in Devon Midstream Holdings and will control our general partner, which has sole responsibility for conducting our business and managing our operations, and we will own the general partner of Devon Midstream Holdings, which is responsible for managing the operations of Devon Midstream Holdings. Our general partner and its affiliates, including Devon, have conflicts of interest with, and defined fiduciary duties with respect to, us and our unitholders, and may favor their own interests to our detriment and that of our unitholders. Additionally we have no control over Devon’s business decisions and operations, and Devon is under no obligation to adopt a business strategy that favors us.

Following the offering, Devon will own and control our general partner. Some of the directors and all of the executive officers of our general partner are officers of Devon. Although our general partner has a duty to manage us in a manner it believes to be in our best interests, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Devon. Conflicts of interest may arise between Devon and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

•

neither our partnership agreement nor any other agreement requires Devon to pursue a business strategy that favors us. Devon’s directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of Devon and affiliated entities, which may be contrary to our interests;

 

•

our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest;

 

•

except as provided in the dedication arrangements contained in our gas gathering agreements, Devon is not limited in its ability to compete with us;

 

•

Devon may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to Devon’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations;

 

•

Devon is under no obligation to offer us any additional interest in Devon Midstream Holdings;

 

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some officers of Devon who provide services to us also will devote significant time to the business of Devon, and will be compensated by Devon for the services rendered to it;

 

•

our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty. By purchasing common units, unitholders will be deemed to have consented to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable law;

 

•

our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

 

•

our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and the ability of the subordinated units to convert to common units;

 

•

our general partner determines which costs incurred by it and its affiliates are reimbursable by us;

 

•

our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

 

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•

our partnership agreement permits us to distribute up to $         million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or the incentive distribution rights;

 

•

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

 

•

our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

 

•

our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units;

 

•

our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates; and

 

•

our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Please read “Conflicts of Interest and Fiduciary Duties.”

Ongoing cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to our unitholders.

Prior to making distributions on our common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Because we distribute all of our available cash to our unitholders, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our share of Devon Midstream Holdings’ expansion capital expenditures and acquisitions. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. Furthermore, we anticipate using the net proceeds of this offering to make a $         million distribution to Devon as reimbursement of certain capital expenditures incurred with respect to the assets contributed to us, as well as partial consideration for the 20% limited partner interest in Devon Midstream Holdings, pay approximately $         million of expenses associated with this offering and related formation transactions, pay a fixed aggregate structuring fee of $1,200,000 to Merrill Lynch, Pierce, Fenner & Smith Incorporated and Barclays Capital Inc. and retain the balance, if any, for general partnership purposes. As a result, the net proceeds of this offering will not be used to grow our business.

 

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In addition, because we distribute all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

We will be required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.

Our partnership agreement requires us to deduct estimated, rather than actual, maintenance capital expenditures from our operating surplus. The amount of estimated maintenance capital expenditures deducted from operating surplus will be subject to review and change by our conflicts committee at least once a year. In years when our estimated maintenance capital expenditures are higher than actual maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from our operating surplus. If we underestimate the appropriate level of estimated maintenance capital expenditures, we may have less cash available for distribution in future periods when actual capital expenditures begin to exceed our previous estimates. Over time, if we do not set aside sufficient cash reserves or have available sufficient sources of financing and make sufficient expenditures to maintain our asset base, we will be unable to pay distributions at the anticipated level and could be required to reduce our distributions.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions, in its individual capacity, as opposed to in its capacity as our general partner, or otherwise, free of fiduciary duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the parties where the language in our partnership agreement does not provide for a clear course of action. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

•

how to allocate business opportunities among us and its other affiliates;

 

•

whether to exercise its call right;

 

•

how to exercise its voting rights with respect to the units it owns;

 

•

whether to exercise its registration rights;

 

•

whether to elect to reset target distribution levels; and

 

•

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

 

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Unitholders have very limited voting rights and are not entitled to appoint or remove our general partner or elect the board of directors of our general partner.

Unitholders have only limited voting rights and, therefore, limited ability to influence management’s decisions regarding our business. Unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The directors of our general partner are chosen by Devon. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

The unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon the closing of this offering to prevent its removal. The vote of the holders of at least 66 ²⁄₃% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. At the closing of this offering, our general partner and its affiliates will own approximately         % of the total outstanding common units and subordinated units on an aggregate basis (or         % of our total outstanding common units and subordinated units on an aggregate basis if the underwriters’ option to purchase additional common units is exercised in full). Also, if our general partner is removed without cause (as defined under our partnership agreement) during the subordination period and common units and subordinated units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically be converted into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

“Cause” is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders’ dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units into common units.

Our partnership agreement restricts the remedies available to holders of our units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

 

•

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

•

our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning that it subjectively believed that it was acting in the best interests of the partnership;

 

•

our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

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•

our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

 

(i)

approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

 

(ii)

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Fiduciary Duties.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements between us and third parties so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Devon may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of our general partner’s board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Devon has the right, as the initial holder of our incentive distribution rights, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (50.0%) for the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by Devon, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If Devon elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to Devon will equal the number of common units that would have entitled Devon to an aggregate quarterly cash distribution in the quarter prior to the reset election equal to the distribution to Devon on the incentive distribution rights in the quarter prior to the reset election. We anticipate that Devon would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that Devon could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of

 

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cash distributions that our common unitholders would have otherwise received had we not issued new common units to Devon in connection with resetting the target distribution levels. Please read “How We Make Distributions to Our Partners—Devon’s Right to Reset Incentive Distribution Levels.”

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity, to incur debt to capture growth opportunities or for other purposes, or to make cash distributions at our intended levels.

If interest rates rise, the interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. 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, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity, to incur debt to expand or for other purposes, or to make cash distributions at our intended levels.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

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 our 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 board of directors and officers of our general partner with its own choices and thereby exert significant control over the decisions made by the board of directors and officers. This effectively permits a “change of control” without the vote or consent of the unitholders.

The incentive distribution rights may be transferred by Devon to a third party without unitholder consent.

Devon may transfer all or a portion of its incentive distribution rights to a third party at any time without the consent of our unitholders. If Devon transfers the incentive distribution rights to a third party but retains its ownership interest in our general partner, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if Devon had retained ownership of the incentive distribution rights. For example, a transfer of incentive distribution rights by Devon could reduce the likelihood of Devon accepting offers made by us relating to assets owned by it, as it would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

Immediately effective upon closing, you will experience substantial dilution of $         in tangible net book value per common unit.

The assumed initial public offering price of $         per unit exceeds our pro forma net tangible book value of $         per unit. Based on the assumed initial public offering price of $         per unit, you will incur immediate and substantial dilution of $         per common unit after giving effect to the offering of common units and the

 

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application of the related net proceeds. Dilution results primarily because the assets being contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost and not their fair value. Please read “Dilution.”

We may issue additional units, including units that are senior to the common units, without your approval, which would dilute your 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. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

•

each unitholder’s proportionate ownership interest in us will decrease;

 

•

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

 

•

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

•

the ratio of taxable income to distributions may increase;

 

•

the relative voting strength of each previously outstanding unit may be diminished; and

 

•

the market price of the common units may decline.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may, among other adverse effects, (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

Devon may sell common units in the public markets or otherwise, which sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered hereby, Devon will indirectly hold              common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier. Additionally, we have agreed to provide Devon with certain registration rights. Please read “Units Eligible for Future Sale.” The sale of these units in public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability

 

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upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act. Upon consummation of this offering, and assuming the underwriters do not exercise their option to purchase additional common units, our general partner and its affiliates will own an aggregate of     % of our common and subordinated units. At the end of the subordination period, assuming no additional issuances of units (other than upon the conversion of the subordinated units), our general partner and its affiliates will own     % of our common units. For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we will initially own assets and conduct business in Texas and Oklahoma. You could be liable for any and all of our obligations as if you were a general partner if:

 

•

a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

•

your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act the (“Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, which could cause you to lose all or part of your investment.

Prior to the offering, there has been no public market for the common units. After the offering, there will be only              publicly-traded common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, a lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

 

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The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

•

our quarterly distributions;

 

•

our quarterly or annual earnings or those of other companies in our industry;

 

•

events affecting Devon;

 

•

announcements by us or our competitors of significant contracts or acquisitions;

 

•

changes in accounting standards, policies, guidance, interpretations or principles;

 

•

general economic conditions;

 

•

the failure of securities analysts to cover our common units after the consummation of this offering or changes in financial estimates by analysts;

 

•

future sales of our common units; and

 

•

other factors described in these “Risk Factors.”

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

The New York Stock Exchange does not require a publicly-traded partnership like us to comply with certain of its corporate governance requirements.

We intend to apply to list our common units on the NYSE. Because we will be a publicly-traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read “Management—Management of Devon Midstream Partners, L.P.”

We will incur increased costs as a result of being a publicly-traded partnership.

We have no history operating as a publicly-traded partnership. As a publicly-traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act of 2002, as well as rules implemented by the SEC and the NYSE, require publicly-traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to make distributions to our unitholders, we must first pay or reserve cash for our expenses, including the costs of being a publicly-traded partnership. As a result, the amount of cash we have available for distribution to our unitholders will be affected by the costs associated with being a publicly-traded partnership.

 

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Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Exchange Act. We expect these rules and regulations to increase certain of our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly-traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our SEC reporting requirements.

We also expect to incur significant expense in order to obtain director and officer liability insurance. Because of the limitations in coverage for directors, it may be more difficult for us to attract and retain qualified persons to serve on our board or as executive officers.

We estimate that we will incur approximately $3.5 million of incremental costs per year associated with being a publicly-traded partnership; however, it is possible that our actual incremental costs of being a publicly-traded partnership will be higher than we currently estimate.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material U.S. Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as Devon Midstream Holdings and us not being subject to material incremental entity-level taxation. If the IRS were to treat us as a corporation for federal income tax purposes, or if we or Devon Midstream Holdings become subject to entity-level taxation for state tax purposes, our cash available for distribution to you would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we or Devon Midstream Holdings were treated as a corporation for federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us or Devon Midstream Holdings as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us or Devon Midstream Holdings as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us or Devon Midstream Holdings to entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the

 

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imposition of state income, franchise or other forms of taxation. Specifically, we and Devon Midstream Holdings will initially own assets and conduct business in Texas, which imposes a margin tax at a maximum effective rate of 0.7% of our gross income apportioned to Texas. In the future, we or Devon Midstream Holdings may expand our operations. Imposition of a similar tax on us or Devon Midstream Holdings in other jurisdictions that we may expand to could substantially reduce our cash available for distribution to you.

The tax treatment of publicly-traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly-traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly-traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. Any modification to U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income requirement to be treated as a partnership for U.S. federal income tax purposes. For a discussion of the importance of our treatment as a partnership for federal income purposes, please read “Material U.S. Federal Income Tax Consequences—Taxation of the Partnership—Partnership Status” for a further discussion.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

Even if you do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

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

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost.

 

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Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

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

Investment in common units by tax-exempt entities, such as 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 that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Allocations and/or distributions to non-U.S. persons will be subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file United States federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units. Please read “Material U.S. Federal Income Tax Consequences—Tax Exempt Organizations and Other Investors.”

We will treat each purchaser of common units as having the same tax benefits without regard to the common units actually 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 our common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Our counsel is unable to opine as to the validity of this approach. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material U.S. Federal Income Tax Consequences —Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopted.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will 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. The use of this proration method may not be permitted under existing Treasury regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration 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. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units—Allocations Between Transferors and Transferees.”

 

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A unitholder whose units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of units) may be considered to have 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 could recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, 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, 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 securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. 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 the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of 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 the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the 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 from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Immediately following this offering, Devon will indirectly own              of the total interests in our capital and profits. Therefore, a transfer by Devon of all or a portion of its interests in us could, in conjunction with the trading of common units held by the public, result in a termination of our partnership for federal income tax purposes. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once.

Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in taxable income for the unitholder’s taxable year that includes our termination. Our termination would not affect our classification as a partnership for federal income

 

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tax purposes, but it would result in our being treated as a new partnership for U.S. federal income tax purposes following the termination. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS recently announced a relief procedure whereby if a publicly-traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the two short tax periods included in the year in which the termination occurs. Please read “Material U.S. Federal Income Tax Consequences —Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

You will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where you do not live as a result of investing in our common units.

In addition to U.S. federal income taxes, you may be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements.

We will initially own assets and conduct business in Texas and Oklahoma. Texas currently does not impose a personal income tax on individuals, but does impose an income tax on corporations and other entities. However, Oklahoma imposes a personal income tax on individuals as well as corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

 

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USE OF PROCEEDS

We intend to use the estimated net proceeds of approximately $             million from this offering, based upon the assumed initial public offering price of $             per common unit (the midpoint of the price range set forth on the cover of this prospectus), after deducting underwriting discounts, structuring fees and offering expenses, to:

 

•

distribute $             million to Devon as reimbursement of certain capital expenditures incurred with respect to the assets contributed to us, as well as partial consideration for the 20% limited partner interest in Devon Midstream Holdings;

 

•

pay approximately $             million of expenses associated with this offering and the transactions described under “—Formation Transactions and Partnership Structure”;

 

•

pay a fixed aggregate structuring fee of $1,200,000 to Merrill Lynch, Pierce, Fenner & Smith Incorporated and Barclays Capital Inc.; and

 

•

retain the balance, if any, for general partnership purposes.

The following table sets forth the estimated sources and uses of the funds we expect to receive from the sale of the common units in this offering.

 

Sources of Funds (in millions):
Sale of                  common units		$
Total sources of funds		$
Uses of Funds (in millions):
Distribution to Devon		$
Payment of structuring fee
Payment of expenses associated with the offering
Total uses of funds		$

The net proceeds from any exercise of the underwriters’ option to purchase additional common units (approximately $         million based on an assumed initial offering price of $         per common unit, if exercised in full) will be used to make a distribution to Devon. If the underwriters do not exercise their option to purchase additional common units, we will issue                  common units to Devon at the expiration of the option period for no additional consideration to us. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be issued to the public and the remainder, if any, will be issued to Devon at the expiration of the option exercise period. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding. Please read “Underwriting.”

An increase or decrease in the assumed initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, commissions and structuring fees, to increase or decrease by approximately $         million.

 

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CAPITALIZATION

The following table shows:

 

•

the historical cash and cash equivalents and capitalization of Devon Midstream Holdings Predecessor as of June 30, 2013; and

 

•

our pro forma capitalization as of June 30, 2013, as adjusted to reflect this offering, the other transactions described under “Summary—Formation Transactions and Partnership Structure,” and the application of the net proceeds from this offering as described under “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with, and is qualified in its entirety by reference to, the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

		As of June 30, 2013
		Historical				Pro Forma, as adjusted (1)
		(in millions)
Cash and cash equivalents		$	—			$	—
Long-term debt		$	—			$	—
Owner/Partners’ equity:
Devon Midstream Holdings Predecessor equity			2,009.5				—
Common units—Public			—				—
General partner, common and subordinated units—Devon			—				428.0
Total owner/partners’ equity attributable to Devon Midstream Partners, L.P.			2,009.5				428.0
Non-controlling interest			47.6				1,712.2
Total owner/partners’ equity			2,057.1				2,140.2
Total capitalization		$	2,057.1			$	2,140.2

 

(1)

Assumes the mid-point of the price range set forth on the cover of this prospectus. Additionally, does not reflect the issuance of up to                  common units that may be sold to the underwriters upon exercise of their option to purchase additional common units. Each $1.00 increase or decrease in the assumed initial public offering price of would cause the net proceeds from the offering, after deducting underwriting discounts and commissions and structuring fees to increase or decrease by approximately $        .

 

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of June 30, 2013, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $         million, or $         per unit. Net tangible book value excludes $         million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

 

Assumed initial public offering price per common unit						$
Pro forma net tangible book value per unit before the offering (1)		$
Increase in net tangible book value per unit attributable to purchasers in the offering
Less: Pro forma net tangible book value per unit after the offering (2)
Immediate dilution in tangible net book value per common unit to new investors (3)(4)						$

 

(1)	Determined by dividing the number of common and subordinated units to be issued to Devon for its contribution of assets and liabilities to Devon Midstream Partners, L.P. into the net tangible book value of the contributed assets and liabilities.

(2)

Determined by dividing the total number of units to be outstanding after the offering (                 common units and                  subordinated units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.

(3)	If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $         and $        , respectively.

(4)

Because the total number of units outstanding after this offering will not be impacted by any exercise of the underwriters’ option to purchase additional common units and we will not retain any proceeds from such exercise, there will be no change to dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by affiliates of our general partner and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus (assuming the underwriters do not exercise their option to purchase additional common units):

 

		Units Acquired						Total Consideration
		Number		Percent				Amount				Percent
General partner and affiliates (1)(2)						%		$						%
New investors						%								%
Total					100.0	%		$					100.0	%

 

(1)	The units to be acquired by our general partner and its affiliates consist of                  common units and                  subordinated units.

(2)

The assets being contributed by our general partner and its affiliates were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of June 30, 2013, after giving effect to the application of the net proceeds of this offering is as follows (in millions):

 

Book value of net assets contributed		$
Less: Distribution to our general partner and affiliates from net proceeds of this offering
Total consideration		$

 

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “Assumptions and Considerations” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma operating results, you should refer to our historical and pro forma financial statements included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our cash available after expenses and reserves rather than retaining it. Because we believe we will generally finance capital investments from external financing sources, we believe that our investors are best served by our distributing all of our available cash. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case were we subject to such tax. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly.

Available Cash. Available cash, for any quarter, consists of all cash on hand at the end of that quarter:

 

•

less the amount of cash reserves established by our general partner to:

 

•

provide for the proper conduct of our business;

 

•

comply with applicable law, any of our debt instruments or other agreements; or

 

•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters;

 

•

plus, if our general partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy. There is no guarantee that unitholders will receive quarterly distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

 

•

Our cash flow initially will depend completely on Devon Midstream Holdings’ distributions to us as one of its partners. Because we control Devon Midstream Holdings’ general partner, we have the authority to determine the amount of Devon Midstream Holdings’ distributions, including the amount of cash reserved by Devon Midstream Holdings and not distributed. We have a fiduciary duty to make decisions with respect to Devon Midstream Holdings in the best interest of all of its partners, including Devon. Our decision to make distributions, if any, and the amount of those distributions, if any, could result in a reduction in cash distributions to our unitholders from levels we currently anticipate pursuant to our stated distribution policy.

 

•

Our distribution policy may be affected by restrictions on distributions under the revolving credit facility that we will enter into at the closing of this offering. One such restriction would prohibit us from making cash distributions while an event of default has occurred and is continuing under the revolving credit facility. The revolving credit facility will contain covenants requiring us to maintain certain financial ratios and tests. Should we be unable to satisfy these restrictions or otherwise be in default under the revolving credit facility, we would be prohibited from making cash distributions to our unitholders, notwithstanding our stated cash distribution policy.

 

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•

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period, our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. For a description of these limited circumstances, please read “The Partnership Agreement—Amendment of the Partnership Agreement—No Unitholder Approval.” However, after the subordination period has ended, our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. At the closing of this offering, Devon will own our general partner and will own approximately     % of our total outstanding common units and subordinated units on an aggregate basis (or     % of our total outstanding common units and subordinated units on an aggregate basis if the underwriters’ option to purchase additional common units is exercised in full). Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

 

•

If, and to the extent, our available cash materially declines from quarter to quarter, we may elect to change our current cash distribution policy and reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.

 

•

Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, the establishment of which could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated distribution policy.

 

•

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

 

•

Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

 

•

We may lack sufficient cash to pay distributions to our unitholders due to increases in our general and administrative expense, principal and interest payments on our outstanding debt, tax expenses, working capital requirements and anticipated cash needs. Our available cash is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such expenses increase. Please read “How We Make Distributions to Our Partners—Distributions of Available Cash.”

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital. Devon Midstream Holdings will distribute all of its cash after reserves and expenses to its partners, including us. Accordingly, we expect Devon Midstream Holdings to fund its expansion capital expenditures or acquisitions through capital contributions from us and from Devon. We will distribute all of our available cash to our unitholders. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our capital contributions to Devon Midstream Holdings. To the extent we are unable to finance capital contributions to Devon Midstream Holdings externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we and Devon Midstream Holdings distribute substantially all of our available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute on each unit. Our partnership agreement does not limit our ability to issue additional units, including units ranking senior to the common units. Commercial borrowings or other debt by us or Devon Midstream Holdings to finance our growth strategy will result in increased interest expense, which in turn may impact the available cash that Devon Midstream Holdings has to distribute to its partners, including us, and that we have to distribute to our unitholders.

 

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Our Minimum Quarterly Distribution

Upon completion of this offering, the board of directors of our general partner will adopt a policy pursuant to which we will declare a minimum quarterly distribution of $             per unit per whole quarter, or $             per unit per whole year, to be paid no later than 45 days after the end of each fiscal quarter. This equates to an aggregate cash distribution of approximately $             million per whole quarter or approximately $             million per whole year, in each case based on the number of common units and subordinated units outstanding immediately after completion of this offering. If the underwriters exercise their option to purchase additional common units, the net proceeds will be used to pay a distribution to Devon. Our ability to make cash distributions at the minimum quarterly distribution rate pursuant to this policy will be subject to the factors described above under the caption “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

The subordination period will terminate automatically if (i) we have earned and paid at least $             per quarter on each outstanding common unit and subordinated unit for any three consecutive, non-overlapping four-quarter periods ending on or after                     , 2016 or (ii) we have earned and paid at least $             per quarter (150% of the minimum quarterly distribution) on each outstanding common and subordinated unit for any four-quarter period on or after                     , 2014. Upon the termination of the subordination period, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. Please see “How We Make Distributions to Our Partners—Subordination Period.”

If distributions on our common units are not paid with respect to any fiscal quarter at the minimum quarterly distribution rate, our unitholders will not be entitled to receive such payments in the future except that, to the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to make cash distributions to holders of our common units at the minimum quarterly distribution rate, we will use this excess available cash to pay these deficiencies related to prior quarters before any cash distribution is made to holders of our subordinated units. Please read “How We Make Distributions to Our Partners—Subordination Period.”

We do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement. Our distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly. Under our partnership agreement, available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount of reserves our general partner determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements, or to provide for future distributions to our unitholders for any one or more of the upcoming four quarters.

Our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by our partnership agreement, the Delaware limited partnership statute or any other law, rule or regulation or at equity. Holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described above. However, our partnership agreement provides that our general partner is entitled to make the determinations described above without regard to any standard other than the requirement to act in good faith. Our partnership agreement provides that, in order for a determination by our general partner to be made in “good faith,” our general partner must subjectively believe that the determination is in our best interests. Please read “How We Make Distributions to Our Partners.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. However, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of

 

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reserves our general partner establishes in accordance with our partnership agreement as described above. Our partnership agreement may be amended with the approval of our general partner and holders of a majority of our outstanding common units and any units issued upon the reset of the incentive distribution rights, voting together as a class.

We will pay our distributions on or about the 15th of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through                     , 2013 based on the actual length of the period.

In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $         per unit each quarter through the quarter ending September 30, 2014. In those sections, we present two schedules, consisting of:

 

•

“Unaudited Pro Forma Distributable Cash Flow for the Twelve Months Ended June 30, 2013 and the Year Ended December 31, 2012,” in which we present the amount of cash we would have had available for distribution for the twelve months ended June 30, 2013 and for our fiscal year ended December 31, 2012. This schedule is derived from our unaudited pro forma financial statements that are included in this prospectus beginning on page F-2. The unaudited pro forma financial statements are based on our historical financial statements for the six months ended June 30, 2013 and the year ended December 31, 2012, as adjusted to give pro forma effect to:

 

•

the transactions to be completed as of the closing of this offering as described under “Summary—Formation Transactions and Partnership Structure”; and

 

•

the application of the net proceeds of this offering as described under “Use of Proceeds.”

 

•

“Unaudited Estimated Distributable Cash Flow for the Twelve Months Ending September 30, 2014,” in which we present our financial forecast of our results of operations and the estimated Adjusted EBITDA necessary for us to pay the full minimum quarterly distribution on all units for the twelve months ending September 30, 2014, and the significant assumptions upon which that forecast is based.

Unless otherwise specifically noted, the following discussion refers to 100% of Devon Midstream Holdings, of which Devon Midstream Partners, L.P. will own a 20% interest upon the consummation of this offering. References to “non-controlling interest” describes the portion of income that is attributable to the 80% interest in Devon Midstream Holdings retained by Devon. All comparisons below are made to historical periods which have been adjusted on a pro forma basis.

Unaudited Pro Forma Distributable Cash Flow for the Twelve Months Ended June 30, 2013 and the Year Ended December 31, 2012

If we had completed the transactions contemplated in this prospectus on July 1, 2012, our pro forma distributable cash flow generated for the twelve months ended June 30, 2013 would have been approximately $62.9 million. This amount would have been sufficient to make cash distributions at the minimum quarterly distribution rate of $             per unit per quarter (or $             per unit on an annualized basis) on all of the common units and subordinated units. Our unaudited pro forma distributable cash flow assumes that the underwriters do not exercise their option to purchase additional common units. Assuming the underwriters exercise in full their option to purchase additional common units, our pro forma distributable cash flow for the twelve months ended June 30, 2013 would have been sufficient to make the full minimum quarterly distribution on all the common units and subordinated units.

If we had completed the transactions contemplated in this prospectus on January 1, 2012, our pro forma distributable cash flow generated for the year ended December 31, 2012 would have been $64.0 million. This

 

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amount would have been sufficient to make cash distributions at the minimum quarterly distribution rate of $             per unit per quarter (or $             per unit on an annualized basis) on all of the common units and subordinated units. Our unaudited pro forma distributable cash flow assumes that the underwriters do not exercise their option to purchase additional common units. Assuming the underwriters exercise in full their option to purchase additional common units, our pro forma distributable cash flow for the year ended December 31, 2012 would have been sufficient to the full minimum quarterly distribution on all the common units and subordinated units.

Unaudited pro forma distributable cash flow from operating surplus includes an incremental general and administrative expense we will incur as a result of being a separate publicly-traded limited partnership, including compensation and benefit expenses of corporate administrative employees, costs associated with annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We expect these general and administrative expenses will initially total approximately $3.5 million per year.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma distributable cash flow only as a general indication of the amount of distributable cash flow that we might have generated had we been formed in the periods set forth herein.

 

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The following schedule illustrates, on a pro forma basis, for the twelve months ended June 30, 2013 and the year ended December 31, 2012, the amount of distributable cash flow, assuming that the transactions contemplated by this prospectus had been consummated at the beginning of such periods and that the underwriters did not exercise their option to purchase additional common units in this offering.

Devon Midstream Partners, L.P.

Unaudited Pro Forma Distributable Cash Flow

 

		Pro Forma
		Twelve Months Ended June 30, 2013				Year Ended December 31, 2012
		(in millions)
Operating revenues (1)		$	594.6			$	581.7
Operating costs and expenses:
Operations and maintenance			143.4				141.5
Depreciation and amortization			165.3				145.4
General and administrative			38.7				38.2
Non-income taxes			12.1				11.9
Asset impairments			16.4				16.4
Other, net			3.4				(3.5	)
Total operating costs and expenses			379.3				349.9
Operating income			215.3				231.8
Income from equity investment			6.9				2.0
Income before income taxes			222.2				233.8
Income tax expense			(1.7	)			(1.7	)
Net income			220.5				232.1
Net income attributable to non-controlling interest (2)			(176.4	)			(185.7	)
Net income attributable to Devon Midstream Partners, L.P.			44.1				46.4
Net income attributable to non-controlling interest (2)			176.4				185.7
Net income			220.5				232.1
Add:
Depreciation and amortization			165.3				145.4
Asset impairments			16.4				16.4
Income tax expense (3)			1.7				1.7
Equity investment depreciation			2.9				2.1
Equity investment income tax expense			0.1				0.1
Adjusted EBITDA (4)			406.9				397.8
Adjusted EBITDA attributable to non-controlling interest (2)			(325.5	)			(318.2	)
Adjusted EBITDA attributable to Devon Midstream Partners, L.P. (4)			81.4				79.6
Deduct:
Income taxes paid			0.3				0.4
Maintenance capital expenditures (5)			14.7				11.7
Expansion capital expenditures (6)			56.9				58.9
Incremental general and administrative expenses (7)			3.5				3.5
Add:
Contributions from Devon to fund expansion capital expenditures (6)			56.9				58.9
Distributable cash flow attributable to Devon Midstream Partners, L.P. (4)		$	62.9			$	64.0
Cash distributions:
Distributions to public common unitholders (8)		$				$
Distributions to Devon:
Common units
Subordinated units (8)
Total distributions (8)		$				$
Excess

 

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(1)	Operating revenues include affiliate transactions with Devon that total $555.4 million and $543.9 million for the twelve months ended June 30, 2013 and the year ended December 31, 2012, respectively.

(2)	Represents Devon’s 80% ownership of Devon Midstream Holdings.

(3)	Represents the Texas margin tax, which is classified as income tax for reporting purposes.

(4)

Adjusted EBITDA is defined as income from continuing operations before interest expense, income taxes, depreciation and amortization expense and asset impairments. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated in accordance with GAAP, please see “Summary—Non-GAAP Financial Measure.” We define distributable cash flow as Adjusted EBITDA less net interest and income taxes paid and maintenance capital expenditures.

(5)

Represents maintenance capital expenditures attributable to our 20% interest in Devon Midstream Holdings. For purposes of determining our pro forma distributable cash for the twelve months ended June 30, 2013 and the year ended December 31, 2012, we have assumed that Devon Midstream Holdings has paid maintenance capital expenditures from operating cash flow. On an aggregate basis Devon Midstream Holdings’ total maintenance capital expenditures would have been $73.5 million and $58.5 million for the twelve months ended June 30, 2013 and December 31, 2012, respectively. Our partnership agreement requires that we subtract from operating surplus each quarter the capital contribution we estimate we will need to make to Devon Midstream Holdings to fund our portion of the maintenance capital it needs to maintain its distributable cash flow. Following the closing of this offering, we expect that Devon Midstream Holdings will continue to fund maintenance capital expenditures through operating cash flow, and we and Devon will each bear our respective share of such maintenance capital expenditures based on our respective interests in Devon Midstream Holdings. For a further discussion of maintenance capital expenditures, please read “—Assumptions and Considerations—Costs and Expenses—Capital Expenditures.”

(6)

Reflects pro forma expansion capital expenditures attributable to our 20% interest in Devon Midstream Holdings. Expansion capital expenditures are those capital expenditures that we expect will expand Devon Midstream Holdings’ operating capacity or operating income over the long term. For purposes of determining our pro forma distributable cash flow for the twelve months ended June 30, 2013 and the year ended December 31, 2012, we have assumed that Devon made capital contributions of $56.9 million and $58.9 million, respectively, to fund our portion of the total cost of the expansion capital expenditures for such periods. The substantial majority of these expansion capital expenditures are related to expansions at the Bridgeport processing facility, the Cana processing facility and Gulf Coast Fractionators, all of which are complete. On an aggregate basis, total expansion capital expenditures for Devon Midstream Holdings were $284.5 million and $294.7 million for the twelve months ended June 30, 2013 and the year ended December 31, 2012, respectively. For a further discussion of expansion capital expenditures, please read “—Assumptions and Considerations—General Assumptions and Considerations” and “—Assumptions and Considerations—Costs and Expenses—Capital Expenditures.”

(7)	We expect to incur additional general and administrative costs of approximately $3.5 million as a result of being a separate publicly-traded partnership.

(8)

The table below sets forth the assumed number of outstanding common units (assuming the underwriters do not exercise their option to purchase additional common units) and subordinated units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution rate of $             per unit per quarter ($             per unit on an annualized basis).

 

No Exercise of the Underwriters’ Option to Purchase Additional Common Units

Full Exercise of the Underwriters’ Option to Purchase Additional Common Units

Number of Units

Distributions

Number of Units

Distributions

One Quarter

Annualized

One Quarter

Annualized

Publicly held common units

Common units held by Devon

Subordinated units held by Devon

Total

 

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Unaudited Estimated Distributable Cash Flow for the Twelve Months Ending September 30, 2014

Set forth below is a schedule of unaudited estimated distributable cash flow that reflects our ability to generate sufficient cash flow to pay the minimum quarterly distribution on all of our outstanding units for each quarter in the twelve months ending September 30, 2014. The financial forecast presents, to the best of our knowledge and belief, the expected results of operations, Adjusted EBITDA and distributable cash flow for the forecast period.

Our financial forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending September 30, 2014. The assumptions disclosed below under “Assumptions and Considerations” are those we believe are significant to our financial forecast. We believe our actual results of operations and cash flows will approximate those reflected in our financial forecast. However, we can give you no assurance that our forecast results will be achieved. There will likely be differences between our forecast and the actual results, and those differences could be material. If the forecast is not achieved, we may not be able to pay the minimum quarterly distribution on all our units. In order to fund distributions to our unitholders at the minimum quarterly distribution rate of $         per unit for the twelve months ending September 30, 2014, our unaudited estimated distributable cash flow for the twelve months ending September 30, 2014, must be at least $         million.

We do not as a routine matter make public projections as to future operations, earnings, or other results. However, we have prepared the schedule of unaudited estimated distributable cash flow and related assumptions set forth below to substantiate our belief that we will have sufficient available cash to pay the minimum quarterly distribution to all our unitholders for each quarter in the twelve months ending September 30, 2014. This forecast is a forward-looking statement and should be read together with the historical and pro forma combined financial statements and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in our view, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of our knowledge and belief, the expected course of action and the expected future financial performance. However, this information is not presented as fact and should not be relied upon as being necessarily indicative of future results. Readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent auditors, nor any other independent accountants, have compiled, examined, or performed any procedures with respect to the prospective financial information, and neither has expressed any opinion or any other form of assurance on such information or its achievability, and assume no responsibility for, and disclaim any association with, the prospective financial information.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those which would enable us to generate the unaudited estimated distributable cash flow.

We are providing the unaudited estimated distributable cash flow calculation to supplement our pro forma and historical combined financial statements in support of our belief that we will have sufficient available cash to allow us to fully fund the minimum quarterly distribution on all of our outstanding common and subordinated units for each quarter in the twelve-month period ending September 30, 2014 at our stated initial distribution rate. Please read below under “Assumptions and Considerations” for further information as to the assumptions we have made for the financial forecast.

Actual payments of distributions on our common units and subordinated units are expected to be approximately $             million for the twelve-month period ending September 30, 2014. This is the expected aggregate amount of cash distributions of approximately $             million per quarter for this period. Quarterly distributions will be paid within 45 days after the close of each quarter.

 

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We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. Therefore, you are cautioned not to place undue reliance on this information.

Devon Midstream Partners, L.P.

Unaudited Estimated Distributable Cash Flow

 

		Estimated
		Twelve Months Ending September 30, 2014
		(in millions)
Operating revenues (1)		$	608.0
Operating costs and expenses:
Operations and maintenance			141.0
Depreciation and amortization			176.0
General and administrative			42.0
Non-income taxes			15.0
Other, net			0.5
Total operating costs and expenses			374.5
Operating income			233.5
Income from equity investment			12.0
Interest expense			(0.2	)
Income before income taxes			245.3
Income tax expense			(2.5	)
Net income			242.8
Net income attributable to non-controlling interest (2)			(194.4	)
Net income attributable to Devon Midstream Partners, L.P.			48.4
Net income attributable to non-controlling interest (2)			194.4
Net income			242.8
Add:
Depreciation and amortization			176.0
Income tax expense			2.5
Equity investment depreciation			3.0
Interest expense			0.2
Adjusted EBITDA (3)			424.5
Adjusted EBITDA attributable to non-controlling interest (2)			(339.6	)
Adjusted EBITDA attributable to Devon Midstream Partners, L.P. (3)			84.9
Deduct:
Income taxes paid			0.5
Interest expense paid			0.2
Maintenance capital expenditures (4)			19.0
Expansion capital expenditures (5)			7.4
Incremental general and administrative expenses (6)			3.5
Add:
Borrowings to fund expansion capital expenditures (5)			7.4
Distributable cash flow attributable to Devon Midstream Partners, L.P. (3)		$	61.7
Annualized minimum quarterly distributions:
Distributions to public common unitholders		$
Distributions to Devon:
Common units
Subordinated units
Total minimum annual cash distributions		$

 

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(1)	Operating revenues include affiliate transactions with Devon that total $568.0 million.

(2)	Represents Devon’s 80% interest in Devon Midstream Holdings.

(3)

We define estimated Adjusted EBITDA as earnings from continuing operations before non-controlling interest, interest expense, income taxes and depreciation and amortization expense, less cash reserves. We define distributable cash flow as Adjusted EBITDA less net interest and income taxes paid and maintenance capital expenditures. We have provided Adjusted EBITDA and distributable cash flow in this prospectus because we believe external users of our financial statements, such as investors, commercial banks and others, benefit from having access to the same financial measures we use in evaluating our operating results. We use Adjusted EBITDA and distributable cash flow as supplemental financial measures to assess (i) the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; (ii) our operating performance and return on capital as compared to other companies in the marketing and midstream energy sector, without regard to financing or capital structure; and (iii) the viability of acquisitions and capital expenditure projects.

Estimated Adjusted EBITDA is also used as a supplemental liquidity measure to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to our unitholders.

Estimated Adjusted EBITDA and distributable cash flow are not presentations made in accordance with GAAP and have important limitations as analytical tools because they include some, but not all, items that affect net cash provided by operating activities and income from continuing operations, the GAAP measures most directly comparable to estimated Adjusted EBITDA and distributable cash flow. The non-GAAP financial measures of estimated Adjusted EBITDA and distributable cash flow should not be considered as alternatives to the GAAP measures of net cash provided by operating activities and income from continuing operations. Because estimated Adjusted EBITDA and distributable cash flow exclude some, but not all, items that affect net cash provided by operating activities and income from continuing operations and are defined differently by companies in our industry, our definitions of estimated Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies.

 

(4)

Represents maintenance capital expenditures attributable to our 20% interest in Devon Midstream Holdings. For purposes of determining our pro forma distributable cash for the twelve months ending September 30, 2014, we have assumed that Devon Midstream Holdings has paid maintenance capital expenditures from operating cash flow. On an aggregate basis, Devon Midstream Holdings’ total maintenance capital expenditures would have been $95.0 million for the twelve months ending September 30, 2014. The $95.0 million of total maintenance capital expenditures includes approximately $21.0 million related to certain extraordinary maintenance capital expenses described in more detail under “—Assumptions and Considerations—Costs and Expenses—Capital Expenditures.” Our proportionate share of the $95.0 million would be approximately $19.0 million, which would be approximately $14.8 million excluding the extraordinary expenditures. Our partnership agreement requires that we subtract from operating surplus each quarter the capital contribution we estimate we will need to make to Devon Midstream Holdings to fund our portion of the maintenance capital it needs to maintain its distributable cash. Following the closing of this offering, we expect that Devon Midstream Holdings will continue to fund maintenance capital expenditures through operating cash flow, and we and Devon will each bear our respective share of such maintenance capital expenditures based on our respective interests in Devon Midstream Holdings. For a further discussion of maintenance capital expenditures, please read “—Assumptions and Considerations—Costs and Expenses—Capital Expenditures.”

(5)

Represents estimated expansion capital expenditures attributable to our 20% interest in Devon Midstream Holdings. We intend to fund these expenditures with borrowings under our revolving credit facility. Following the closing of this offering, we and Devon will each have the right to contribute capital to fund our respective share of Devon Midstream Holdings’ expansion capital expenditures based on our respective interest in Devon Midstream Holdings. For the purposes of this forecast, we have assumed that Devon will fund its 80% share of expansion capital expenditures during the forecast period. If Devon elects not to fund any such expansion capital expenditures, we will have the opportunity to fund all or a portion of Devon’s proportionate share of such expansion capital expenditures in exchange for additional interests in Devon Midstream Holdings. For a further discussion of expansion capital expenditures, please read “—Assumptions and Considerations—Costs and Expenses—Capital Expenditures.”

(6)	We expect to incur incremental general and administrative costs of approximately $3.5 million as a result of being a separate publicly-traded partnership.

 

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Assumptions and Considerations

The forecast has been prepared by and is the responsibility of management. The forecast reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending September 30, 2014. While the assumptions discussed below are not all-inclusive, they include those that we believe are material to our forecasted results of operations, and any assumptions not discussed below were not deemed to be material. We believe we have a reasonable, objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and our actual results and those differences could be material. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the minimum quarterly distribution rate or at all.

General Assumptions and Considerations

 

•

As discussed further below, substantially all of our revenues and a significant portion of our expenses will be determined by contractual arrangements between Devon Midstream Holdings and Devon that were not in place during the historical periods, and accordingly, our forecasted results are not directly comparable with historical periods. Please read “Certain Relationships and Related Party Transactions—Contracts with Affiliates.”

 

•

Because we will generate substantially all of our revenues pursuant to long-term contracts that include fee-based rates, annual rate escalators and minimum volume commitments, we have not made any assumptions regarding future commodity price levels in developing our forecast for the twelve months ending September 30, 2014.

Total Operating Revenues

Volumes. The following tables compare forecasted throughput on our gathering and transmission pipelines and at the inlet of our processing facilities.

 

		Gathering and Transmission Pipelines
		Forecasted				Pro Forma
		Twelve Months Ending September 30, 2014				Twelve Months Ended June 30, 2013				Year Ended December 31, 2012
Natural Gas (thousands of MMBtu/d)
Bridgeport rich gathering system			850.0				833.7				818.4
Bridgeport lean gathering system			230.0				288.7				298.0
Acacia transmission system			740.0				739.8				732.7
East Johnson County gathering system			185.0				258.6				277.8
Cana gathering system			370.0				274.3				265.7
Northridge gathering system			60.0				81.1				85.0
Total throughput			2,435.0				2,476.2				2,477.6

 

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We estimate our aggregate gathering volumes will slightly decline compared to historical periods. As natural gas prices remain depressed, many producers, including Devon, have focused on growing their oil and liquids-rich natural gas production rather than dry natural gas. Consequently, systems serving liquids-rich natural gas regions in the Cana-Woodford and Barnett Shales have higher estimated throughput in the forecast period, while Devon Midstream Holdings’ systems serving dry natural gas regions have estimated throughput declines.

 

		Processing Facilities
		Forecasted				Pro Forma
		Twelve Months Ending September 30, 2014				Twelve Months Ended June 30, 2013				Year Ended December 31, 2012
Natural Gas (thousands of MMBtu/d)
Bridgeport processing facility			834.0				769.2				753.2
Cana processing facility			370.0				235.9				233.9
Northridge processing facility			80.0				116.1				106.4
Total inlet			1,284.0				1,121.2				1,093.5

We estimate inlet volumes at our processing facilities will increase 15% and 17% compared to the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. The increase is driven by our Bridgeport and Cana processing facilities which both underwent upgrades and plant expansions in 2013 resulting in additional processing capacity necessary to accommodate increased production of liquids-rich natural gas. We do not expect to trigger any minimum volume deficiency payments in the forecast period.

Processing and gathering fees. In connection with this offering, we will enter into new contracts with Devon pursuant to which we will provide all our services under fixed-fee arrangements and will not take title to the natural gas we gather and process. We believe this change will provide us with a relatively steady revenue stream that is not subject to direct commodity price risk. We will nevertheless continue to have indirect exposure to commodity price risk because persistently low commodity prices may cause our current or potential customers to delay drilling or shut in production, which would reduce the throughput on Devon Midstream Holdings’ systems. Our operating revenues are entirely dependent on the throughput volumes and fixed-fee arrangements we have entered into.

Based on the volumes in the tables above, we estimate that our operating revenues for the twelve months ending September 30, 2014 will be $608.0 million, compared to $594.6 million for the twelve months ended June 30, 2013 and $581.7 million for the year ended December 31, 2012, on a pro forma basis. We have not assumed that any rate escalator provision applies during the forecast period. Although our aggregate volumes decreased in the forecast period due to lower dry natural gas production, higher liquids-rich production contributes to the total increase in operating revenues because we earn both gathering and processing fees on such volumes.

Impact of volume declines. If all other assumptions are held constant, a 5% decrease in volumes below forecasted levels would result in a $2.7 million decrease in cash available for distribution. A decrease of over $             million in our cash available for distribution would result in our generating less than the minimum cash necessary to pay distributions.

Costs and Expenses

Operations and maintenance expenses. We estimate that operations and maintenance expense for the twelve months ending September 30, 2014 will be $141.0 million, compared to $143.4 million and $141.5 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. Operations and maintenance expense is comprised primarily of direct labor costs, insurance costs, repair and maintenance costs, integrity management costs, utilities and contract services. As such costs are primarily fixed, operating and

 

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maintenance expense will not vary significantly with increases or decreases in revenue and gross margin. The estimated decrease in operations and maintenance expense during the forecast period is due to expenses incurred during the historical comparative periods related to voluntary regulatory testing and related records documentation, partially offset by an assumed 2.5% inflation rate on base operations and maintenance expenses.

Depreciation and amortization expense. We estimate that depreciation and amortization expense for the twelve months ending September 30, 2014 will be $176.0 million, compared to $165.3 million and $145.4 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. Estimated depreciation expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation and amortization expense is primarily attributable to additional capital projects that have been or will be placed in service. Depreciation expenses are derived from capitalized costs and useful lives and will not vary with increases or decreases in revenue and gross margin.

General and administrative expenses. We estimate that general and administrative expense for the twelve months ending September 30, 2014 will be $42.0 million, compared to $38.7 million and $38.2 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. The estimated increase is primarily due to assumed inflation and an estimated increase in compensation subject to allocation from Devon.

Non-income taxes. We estimate that non-income taxes for the twelve months ending September 30, 2014 will be $15.0 million, compared to $12.1 million and $11.9 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. Non-income taxes are comprised primarily of ad valorem and property taxes. The estimated increase in non-income taxes during the forecast period is due to processing facility expansions that are expected to increase property value assessments.

Other, net. We estimate that other expenses, net for the twelve months ending September 30, 2014 will be $0.5 million, compared to other expenses, net of $3.4 million and other income, net of $3.5 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. Other, net is comprised primarily of accretion expense on our discounted asset retirement obligations and other miscellaneous items. The estimate only considers the accretion expense.

Income from equity investment. We estimate that income from equity investment for the twelve months ending September 30, 2014 will be $12.0 million, compared to $6.9 million and $2.0 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. Income from equity investment is comprised entirely of our 38.75% non-operating equity interest in Gulf Coast Fractionator, an NGL fractionator located on the Texas Gulf Coast at the Mont Belvieu hub. The estimated increase in income from equity investment during the forecast period is due to turnaround downtime experienced during the historical comparative periods.

Income tax expense. We estimate our payments of the income-based Texas margin tax will be $0.5 million for the twelve months ending September 30, 2014.

Capital expenditures. Estimated capital expenditures for the twelve months ending September 30, 2014 are based on the following assumptions:

Maintenance capital expenditures. For the twelve months ending September 30, 2014, we estimate that total maintenance capital expenditures for Devon Midstream Holdings will be approximately $95.0 million. These expenditures primarily consist of planned maintenance on existing systems, as well as additional well connects for natural gas volumes that will offset expected production declines from wells already connected to Devon Midstream Holdings’ gathering systems in the forecast period. Devon Midstream Holdings’ $95.0 million of total maintenance capital expenditures includes approximately $21.0 million related to certain extraordinary maintenance capital expenditures, consisting of approximately $15.0 million for the installation of fire control equipment at the Bridgeport processing facility that is being installed to facilitate our continued ability to obtain casualty insurance and $6.0 million for standby residue compression at the Bridgeport processing

 

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facility. We do not anticipate similar expenditures in future periods. Excluding these extraordinary expenditures, total maintenance capital expenditures would have been approximately $74.0 million on a 100% basis for the twelve months ending September 30, 2014. This compares to aggregate maintenance capital expenditures of $73.5 million and $58.5 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively.

For the twelve months ending September 30, 2014, we estimate that the amount of maintenance capital expenditures attributable to our 20% interest will be approximately $19.0 million, or $14.8 million excluding approximately $4.2 million related to the extraordinary expenditures. The $14.8 million is comparable to $14.7 million and $11.7 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. We expect ongoing maintenance capital expenditures of similar magnitudes. Following the closing of this offering, we expect that all maintenance capital expenditures attributable to our interest in Devon Midstream Holdings will be funded through our operating cash flows.

Expansion Capital Expenditures. These expenditures include construction of additional assets to increase operations, to expand and upgrade existing systems and facilities or to acquire additional assets which increase operations. For the twelve months ending September 30, 2014, we estimate that expansion capital expenditures for Devon Midstream Holdings will be approximately $37.0 million on a 100% basis. These expenditures primarily consist of planned construction of well connects, trunklines and lateral extensions for natural gas volumes to the extent they increase aggregate throughput volumes on each system. This compares to aggregate expansion capital expenditures of $284.5 million and $294.7 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. The higher expansion capital expenditures in the historical twelve-month periods relate to three large expansion projects, which incurred the following capital expenditures:

 

•

approximately $133.4 million and $91.2 million of construction costs associated with the expansion of the Bridgeport processing facility for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively;

 

•

approximately $149.2 million and $187.9 million of construction costs associated with the expansion of the Cana processing facility for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively; and

 

•

approximately $1.9 million and $15.6 million of construction costs associated with the expansion of Gulf Coast Fractionators for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively.

We do not expect to have significant additional expansion capital expenditures at the Bridgeport and Cana processing facilities for the next few years.

For the twelve months ending September 30, 2014, we estimate that the amount of expansion capital expenditures attributable to our 20% interest will be approximately $7.4 million. The amount of expansion capital expenditures attributable to our 20% interest in Devon Midstream Holdings was $56.9 million and $58.9 million for the twelve month periods ended June 30, 2013 and December 31, 2012, respectively. Following the closing of this offering, we expect that all expansion capital expenditures attributable to our interest in Devon Midstream Holdings will be funded with borrowings under our revolving credit facility.

Financing. Our estimate for the twelve months ending September 30, 2014 is based on the following significant financing assumptions:

Indebtedness. Our average debt level will be $3.7 million, comprised of funds drawn on our $         million revolving credit facility to fund expansion capital expenditures attributable to us.

Interest expense. Borrowings under our new revolving credit facility are estimated to bear an annual interest rate of 5.0% through September 30, 2014. Assuming an outstanding balance of $7.4 million as of September 30, 2014, an increase or decrease of 1% in the interest rate will result in increased or decreased, respectively, annual interest expense of approximately $0.1 million.

 

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Covenant compliance. We will remain in compliance with the financial and other covenants in our new revolving credit facility.

Regulatory, industry and economic factors. Our estimate for the twelve months ending September 30, 2014 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

•

There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.

 

•

There will not be any major adverse change in the midstream energy sector or in market, insurance or general economic conditions.

 

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HOW WE MAKE DISTRIBUTIONS TO OUR PARTNERS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending                     , 2013 we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the completion of the offering through                     , 2013 based on the actual length of that period.

Definition of Available Cash

Available cash, for any quarter, generally consists of all cash and cash equivalents on hand at the end of that quarter:

 

•

less, the amount of cash reserves established by our general partner to:

 

•

provide for the proper conduct of our business;

 

•

comply with applicable law, any of our debt instruments or other agreements or any other obligation; or

 

•

provide funds for distributions to our partners for any one or more of the next four quarters;

 

•

plus, if our general partner so determines, all or any portion of the cash on hand immediately prior to the date of distribution of available cash for the quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter.

The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash received by us after the end of the quarter but on or before the date of distribution of available cash for that quarter, including cash on hand resulting from working capital borrowings made after the end of the quarter, to pay distributions to partners. Under our partnership agreement, working capital borrowings are borrowings that are made under a credit agreement, commercial paper facility or similar financing arrangement with the intent to repay such borrowings within twelve months from sources, and that are used solely for working capital purposes or to pay distributions to partners.

Intent to Distribute the Minimum Quarterly Distribution

Within 45 days after the end of each quarter, beginning with the quarter ending                     , 2013, we intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $         per unit, or $         on an annualized basis, to the extent we have sufficient cash after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our general partner, taking into consideration the terms of our partnership agreement. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Liquidity and Capital Resources.”

General Partner Interest and Incentive Distribution Rights

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity securities in us and will be entitled to receive distributions on any such interests.

 

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Devon currently indirectly holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $         per unit per quarter. The maximum distribution of 50.0% does not include any distributions that Devon may receive on any limited partner units that it owns.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as being paid from either “operating surplus” or “capital surplus.” Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Operating Surplus

We define operating surplus as:

 

•

$         million (as described below); plus

 

•

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below) provided that cash receipts from the termination of a commodity hedge or interest rate hedge not related to the financing of an expansion capital expenditure prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge related to the financing of an expansion capital expenditure; plus

 

•

working capital borrowings made after the end of a period but on or before the date of determination of operating surplus for the period; plus

 

•

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights), other than equity issued on the closing date of this offering, to finance all or a portion of expansion capital expenditures in respect of the period from such financing until the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; plus

 

•

cash distributions paid in respect of equity issued (including incremental distributions on incentive distribution rights) to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the expansion capital expenditures referred to above, in each case, in respect of the period from such financing until the earlier to occur of the date the capital asset is placed in service and the date that it is abandoned or disposed of; less

 

•

all of our operating expenditures (as defined below) after the closing of this offering; less

 

•

the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

 

•

all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such twelve-month period with the proceeds of additional working capital borrowings; less

 

•

any loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $         million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash

 

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distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

We define operating expenditures in our partnership agreement, which generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner or its affiliates, payments made under interest rate hedge agreements or commodity hedge agreements (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments and maintenance and replacement capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

 

•

repayment of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

 

•

payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness, other than working capital borrowings;

 

•

expansion capital expenditures;

 

•

actual maintenance and replacement capital expenditures (as discussed in further detail below);

 

•

investment capital expenditures;

 

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payment of transaction expenses (including taxes) relating to interim capital transactions;

 

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payments made in connection with the initial purchase or termination of, or in the ordinary course under, an interest rate hedge contract related to the financing of an expansion capital expenditure;

 

•

distributions to our partners (including distributions in respect of our incentive distribution rights);

 

•

repurchases of equity interests except to fund obligations under employee benefit plans; or

 

•

any other expenditures or payments using the proceeds of this offering that are described in “Use of Proceeds.”

Capital Surplus

Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

 

•

borrowings other than working capital borrowings;

 

•

sales of our equity and debt securities; and

 

•

sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets.

 

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Characterization of Cash Distributions

Our partnership agreement requires that we treat all available cash distributed by us as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As described above, operating surplus includes a basket of $         million, and therefore does not reflect actual cash on hand that is available for distribution to our unitholders. Rather, this provision will enable us, if we choose, to distribute as operating surplus up to that amount of cash we receive in the future from interim capital transactions that would otherwise be distributed as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

Estimated maintenance and replacement capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance and replacement capital expenditures and investment capital expenditures do not. Maintenance and replacement capital expenditures are those capital expenditures required to maintain our operating capacity or operating income over the long-term, the replacement of equipment and well connections, or the construction, development or acquisition of other facilities to replace expected reductions in hydrocarbons available for gathering, processing, transporting or otherwise handled by our facilities (which we refer to as operating capacity). Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction, improvement or replacement of an asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date of any such replacement asset commences commercial service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance and replacement capital expenditures.

Because our maintenance and replacement capital expenditures can be irregular, the amount of our actual maintenance and replacement capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus and adjusted operating surplus if we subtracted actual maintenance and replacement capital expenditures from operating surplus.

Our partnership agreement requires that an estimate of the average quarterly maintenance and replacement capital expenditures necessary to maintain our operating capacity over the long-term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus for those periods will be subject to review and change by our general partner at least once a year. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance and replacement capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. Our partnership agreement does not set a limit on the amount of maintenance and replacement capital expenditures that our general partner may estimate. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance and replacement capital expenditures, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The use of estimated maintenance and replacement capital expenditures in calculating operating surplus will have the following effects:

 

•

the amount of actual maintenance and replacement capital expenditures in any quarter will not directly reduce operating surplus but will instead be factored into the estimate of the average quarterly maintenance and replacement capital expenditures. This may result in the subordinated units

 

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converting into common units when the use of actual maintenance and replacement capital expenditures would result in lower operating surplus during the subordination period and potentially result in the tests for conversion of the subordinated units not being satisfied;

 

•

it may increase our ability to distribute as operating surplus cash we receive from non-operating sources; and

 

•

it may be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income over the long term. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or processing capacity, to the extent such capital expenditures are expected to expand, over the long term, either our operating capacity or operating income. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction of such capital improvement in respect of the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital improvement commences commercial service and the date that it is disposed of or abandoned. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment capital expenditures are those capital expenditures that are neither maintenance and replacement capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of assets that are in excess of the maintenance of our existing operating capacity or operating income, but which are not expected to expand, for more than the short term, our operating capacity or operating income.

As described below, neither investment capital expenditures nor expansion capital expenditures are included in operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction, replacement or improvement of a capital asset in respect of a period that begins when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial service and the date that it is abandoned or disposed of, such interest payments also do not reduce operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized, and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

Capital expenditures that are made in part for maintenance and replacement capital purposes, investment capital purposes or expansion capital purposes will be allocated as maintenance and replacement capital expenditures, investment capital expenditures or expansion capital expenditures by our general partner.

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $         per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the

 

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common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions from operating surplus until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be sufficient available cash from operating surplus to pay the minimum quarterly distribution on the common units.

Determination of Subordination Period

Devon will initially indirectly own all of our subordinated units. Except as described below, the subordination period will begin on the closing date of this offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending                     , 2016 if each of the following has occurred:

 

•

distributions of available cash from operating surplus on each of the outstanding common and subordinated units equaled or exceeded the annualized minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

 

•

the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of the annualized minimum quarterly distribution on all of the outstanding common and subordinated units during those periods on a fully-diluted weighted-average basis; and

 

•

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate, and all of the subordinated units will convert into common units on a one-for-one basis, on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending                     , 2014 if each of the following has occurred:

 

•

distributions of available cash from operating surplus on each of the outstanding common and subordinated units exceeded $         (150.0% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

 

•

the “adjusted operating surplus” (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of $         (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common and subordinated units during that period on a fully diluted weighted average basis, plus the related distribution on the incentive distribution rights; and

 

•

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Expiration Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause:

 

•

the subordinated units held by any person will immediately and automatically convert into a new class of common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner; and

 

•

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

 

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Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro rata with the other common units in distributions of available cash.

Adjusted Operating Surplus

Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods if not utilized to pay expenses. Adjusted operating surplus consists of:

 

•

operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

 

•

any net increase in working capital borrowings with respect to that period; less

 

•

any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

 

•

any net decrease in working capital borrowings with respect to that period; plus

 

•

any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium; plus

 

•

any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

Distributions of Available Cash From Operating Surplus During the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

•

first, to the common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter and any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters;

 

•

second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

•

thereafter, in the manner described in “—Incentive Distribution Rights” below.

Distributions of Available Cash From Operating Surplus After the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

•

first, to all common unitholders, pro rata, until we distribute for each common unit an amount equal to the minimum quarterly distribution for that quarter; and

 

•

thereafter, in the manner described in “—Incentive Distribution Rights” below.

General Partner Interest

Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity securities in us and will be entitled to receive distributions on any such interests.

 

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Incentive Distribution Rights

Incentive distribution rights represent the right to receive increasing percentages (15.0%, 25.0% and 50.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Devon currently indirectly holds the incentive distribution rights, but may transfer these rights at any time.

If for any quarter:

 

•

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

•

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the holders of our incentive distribution rights in the following manner:

 

•

first, to all unitholders, pro rata, until each unitholder receives a total of $         per unit for that quarter (the “first target distribution”);

 

•

second, 85.0% to all common unitholders and subordinated unitholders, pro rata, and 15.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $         per unit for that quarter (the “second target distribution”);

 

•

third, 75.0% to all common unitholders and subordinated unitholders, pro rata, and 25.0% to the holders of our incentive distribution rights, until each unitholder receives a total of $         per unit for that quarter (the “third target distribution”); and

 

•

thereafter, 50.0% to all common unitholders and subordinated unitholders, pro rata, and 50.0% to the holders of our incentive distribution rights.

Percentage Allocations of Available Cash From Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and Devon based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of Devon and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit Target Amount.” The percentage interests shown for our unitholders and Devon for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below assume Devon has not transferred its incentive distribution rights and there are no arrearages on common units.

 

		Total Quarterly Distribution per Unit Target Amount				Marginal Percentage Interest in Distributions
						Unitholders				Incentive Distribution Rights
Minimum Quarterly Distribution		$					100.0	%			—
First Target Distribution		above $	up to $				100.0	%			—
Second Target Distribution		above $	up to $				85.0	%			15.0	%
Third Target Distribution		above $	up to $				75.0	%			25.0	%
Thereafter		above $					50.0	%			50.0	%

 

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Devon’s Right to Reset Incentive Distribution Levels

Devon, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the target distribution levels upon which the incentive distribution payments would be set. If Devon transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that Devon holds all of the incentive distribution rights at the time that a reset election is made. The right to reset the target distribution levels upon which the incentive distributions are based may be exercised, without approval of our unitholders or the conflicts committee of Devon, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for the prior four consecutive fiscal quarters. The reset target distribution levels will be higher than the target distribution levels prior to the reset such that there will be no incentive distributions paid under the reset target distribution levels until cash distributions per unit following the reset event increase as described below. We anticipate that Devon would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made.

In connection with the resetting of the target distribution levels and the corresponding relinquishment by Devon of incentive distribution payments based on the target cash distributions prior to the reset, Devon will be entitled to receive a number of newly issued common units based on the formula described below that takes into account the “cash parity” value of the cash distributions related to the incentive distribution rights for the quarter prior to the reset event as compared to the cash distribution per common unit in such quarter.

The number of common units to be issued in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels would be equal to the quotient determined by dividing (x) the amount of cash distributions received in respect of the incentive distribution rights for the fiscal quarter ended immediately prior to the date of such reset election by (y) the amount of cash distributed per common unit with respect to such quarter. Devon would be entitled to receive distributions in respect of these common units in subsequent periods.

Following a reset election, a baseline minimum quarterly distribution amount will be calculated as an amount equal to the cash distribution amount per unit for the fiscal quarter immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would make distributions from operating surplus for each quarter thereafter as follows:

 

•

first, to all common unitholders, pro rata, until each unitholder receives an amount per unit equal to 115.0% of the reset minimum quarterly distribution for that quarter;

 

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second, 85.0% to all unitholders, pro rata, and 15.0% to Devon, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

 

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third, 75.0% to all unitholders, pro rata, and 25.0% to Devon, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

 

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to Devon.

Because a reset election can only occur after the subordination period expires, the reset minimum quarterly distribution will have no significance except as a baseline for the target distribution levels.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and Devon at various cash distribution levels (i) pursuant to the cash distribution provisions of

 

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our partnership agreement in effect at the completion of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the fiscal quarter immediately preceding the reset election was $        .

 

		Quarterly Distribution per Unit Prior to Reset				Marginal Percentage Interest in Distributions								Quarterly Distribution Per Unit Following Hypothetical Reset
						Unitholders				Incentive Distribution Rights
Minimum Quarterly Distribution		$					100.0	%			—			$                  (1)
First Target Distribution		above $	up to $				100.0	%			—			above $        (1) up to $    (2)
Second Target Distribution		above $	up to $				85.0	%			15.0	%		above $        (2) up to $    (3)
Third Target Distribution		above $	up to $				75.0	%			25.0	%		above $        (3) up to $    (4)
Thereafter		above $					50.0	%			50.0	%		above $        (4)

 

(1)	This amount is equal to the hypothetical reset minimum quarterly distribution.

(2)	This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

(3)	This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

(4)	This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and Devon, including in respect of incentive distribution rights, based on an amount distributed for the quarter immediately prior to the reset. The table assumes that immediately prior to the reset there would be              common units outstanding and the average distribution to each common unit would be $         per quarter for the quarter prior to the reset.

 

Quarterly Distribution Per Unit Prior to Reset

Cash Distributions to Common Unitholders Prior to Reset

Cash Distributions to the Holder of Our Incentive Distribution Rights Prior to Reset

Total Distributions

Minimum Quarterly Distribution

$

$

$

$

First Target Distribution

above $

up to $

Second Target Distribution

above $

up to $

Third Target Distribution

above $

up to $

Thereafter

above $

$

$

$

 

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the holder of our incentive distribution rights in respect of its incentive distribution rights, for the quarter immediately after the reset occurs. The table reflects that as a result of the reset there would be common units outstanding and the distribution to each common unit would be $        . The number of common units to be indirectly issued to Devon upon the reset was calculated by dividing (x) the amount received by Devon in respect of its incentive distribution rights for the quarter prior to the reset as shown in the table above, or $        , by (y) the cash distributed on each common unit for the quarter prior to the reset as shown in the table above, or $        .

 

Quarterly Distribution Per Unit After Reset

Cash Distributions to Common Unitholders

Cash Distributions to Holder of Our Incentive Distribution Rights After Reset

After Reset

Common Units (1)

Incentive Distribution Rights

Total

Total Distributions

Minimum Quarterly Distribution

$

$

$

$

$

$

First Target Distribution

above $

up to $

Second Target Distribution

above $

up to $

Third Target Distribution

above $

up to $

Thereafter

above $

$

$

$

$

$

 

(1)	Represents distributions in respect of the common units indirectly issued to Devon upon the reset.

The holder of our incentive distribution rights will be entitled to cause the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

 

•

first, to all common unitholders and subordinated unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below;

 

•

second, to the common unitholders, pro rata, until we distribute for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

 

•

thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a Distribution From Capital Surplus

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in relation to the fair market value of the common units prior to the announcement of the

 

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distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for Devon to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we reduce the minimum quarterly distribution and target distribution levels to zero, all future distributions will be made such that 50.0% is paid to all unitholders, pro rata, and 50.0% is paid to the holder or holders of incentive distribution rights, pro rata.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, our partnership agreement specifies that the following items will be proportionately adjusted:

 

•

the minimum quarterly distribution;

 

•

the target distribution levels;

 

•

the initial unit price, as described below under “—Distributions of Cash Upon Liquidation”;

 

•

the per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution on the common units; and

 

•

the number of subordinated units.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50.0% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if as a result of a change in law or interpretation thereof, we or any of our subsidiaries are treated as an association taxable as a corporation or are otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, Devon may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting Devon’s estimate of our additional aggregate liability for the quarter for such income and withholdings taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (x) available cash for that quarter, plus (y) Devon’s estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in distributions with respect to subsequent quarters.

Distributions of Cash Upon Liquidation

General

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

 

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The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by unitholders for their units in this offering, which we refer to as the “initial unit price” for each unit. The allocations of gain and loss upon liquidation are also intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the common unitholders to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of Devon.

Manner of Adjustments for Gain

The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will generally allocate any gain to the partners in the following manner:

 

•

first, to our general partner to the extent of certain prior losses specially allocated to our general partner;

 

•

second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of: (i) the initial unit price; (ii) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (iii) any unpaid arrearages in payment of the minimum quarterly distribution;

 

•

third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of: (i) the initial unit price; and (ii) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

•

fourth, to all unitholders, pro rata, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed to the unitholders, pro rata, for each quarter of our existence;

 

•

fifth, 85.0% to all unitholders, pro rata, and 15.0% to the holder of our incentive distribution rights, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to Devon for each quarter of our existence;

 

•

sixth, 75.0% to all unitholders, pro rata, and 25.0% to the holder of our incentive distribution rights, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to the holder of our incentive distribution rights for each quarter of our existence; and

 

•

thereafter, 50.0% to all unitholders, pro rata, and 50.0% to the holder of our incentive distribution rights.

The percentage interests set forth above for Devon assume Devon has not transferred the incentive distribution rights.

 

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If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (iii) of the second bullet point above and all of the third bullet point above will no longer be applicable.

We may make special allocations of gain among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Manner of Adjustments for Losses

If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

 

•

first, to holders of subordinated units in proportion to the positive balances in their capital accounts until the capital accounts of the subordinated unitholders have been reduced to zero;

 

•

second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero; and

 

•

thereafter, 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

We may make special allocations of loss among the partners in a manner to create economic uniformity among the common units into which the subordinated units convert and the common units held by public unitholders.

Adjustments to Capital Accounts

Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for federal income tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holder of our incentive distribution rights in the same manner as we allocate gain upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we generally allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner that results, to the extent possible, in the partners’ capital account balances equaling the amount that they would have been if no earlier positive adjustments to the capital accounts had been made. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders and our general partner based on their respective percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. If we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders’ capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

 

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SELECTED HISTORICAL AND PRO FORMA

FINANCIAL AND OPERATING DATA

Devon Midstream Partners, L.P. was formed in September 2013 by Devon to own, operate, develop and acquire midstream assets in North America. The selected historical financial and operating data presented in this section is derived from and should be read in conjunction with the financial statements included in this prospectus beginning on page F-2 which consist of the following:

 

•

unaudited pro forma consolidated financial statements of Devon Midstream Partners, L.P. as of June 30, 2013, for the six months ended June 30, 2013 and for the year ended December 31, 2012;

 

•

audited combined financial statements of Devon Midstream Holdings, L.P. Predecessor as of December 31, 2012 and 2011 and for each year in the three-year period ended December 31, 2012; and

 

•

unaudited combined financial statements of Devon Midstream Holdings, L.P. Predecessor as of June 30, 2013 and for the six-month periods ended June 30, 2013 and 2012.

The selected historical financial and operating data reflect 100% of the Predecessor’s operations. The Predecessor’s assets comprise all of Devon’s U.S. midstream assets and operations, including its 38.75% interest in Gulf Coast Fractionators. However, in connection with this offering, only the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma, as well as the 38.75% interest in Gulf Coast Fractionators, will be contributed to Devon Midstream Holdings. These contributed assets represent 90% of the Predecessor’s net income from continuing operations for the six months ended June 30, 2013. Also, upon consummation of the transactions described under the caption “Summary—Formation Transactions and Partnership Structure,” as reflected in the pro forma financial data below, we will own only a 20% interest in Devon Midstream Holdings.

We will control Devon Midstream Holdings’ assets and operations through our ownership of Devon Midstream Holdings’ general partner. Consequently, our future consolidated financial statements will include Devon Midstream Holdings as a consolidated subsidiary, and Devon’s 80% interest will be reflected as a non-controlling interest.

The following table presents the selected historical financial and operating data of Devon Midstream Holdings Predecessor and our selected unaudited pro forma financial data for the periods indicated:

 

		Devon Midstream Partners, L.P. Pro Forma								Devon Midstream Holdings, L.P. Predecessor
		Six Months Ended June 30,				Year Ended December 31,				Six Months Ended June 30,								Year Ended December 31,
		2013				2012				2013				2012				2012				2011				2010				2009				2008
		(unaudited)								(unaudited)																				(unaudited)
		(in millions, except per unit and operating data)
Key Performance Measures
Operating margin (1)		$	227.6			$	440.2			$	217.6			$	179.6			$	365.3			$	453.8			$	427.6			$	366.8			$	559.2
Adjusted EBITDA attributable to Devon Midstream Holdings and our Predecessor (100%) (2)		$	202.8			$	397.8			$	190.7			$	153.0			$	315.7			$	467.4			$	380.6			$	315.6			$	516.4
Adjusted EBITDA attributable to Devon Midstream Partners, L.P. (20%) (2)		$	40.6			$	79.6
Operating Data
Throughput (thousands of MMBtu/d)											2,734.4				2,702.6				2,720.6				2,637.4				2,470.0				2,294.2				2,146.1
NGL production (MBbls/d)											81.9				65.9				71.0				69.7				62.1				59.3				51.5
Residue natural gas production (thousands of MMBtu/d)											942.1				875.0				895.7				838.9				636.5				618.1				547.5

 

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		Devon Midstream Partners, L.P. Pro Forma								Devon Midstream Holdings, L.P. Predecessor
		Six Months Ended June 30,				Year Ended December 31,				Six Months Ended June 30,								Year Ended December 31,
		2013				2012				2013				2012				2012				2011				2010				2009				2008
		(unaudited)								(unaudited)																				(unaudited)
		(in millions, except per unit and operating data)
Statement of Income Data
Operating revenues		$	296.5			$	581.7			$	1,162.4			$	958.9			$	2,000.8			$	2,623.4			$	2,016.0			$	1,609.1			$	2,709.7
Operating expenses			(190.3	)			(349.9	)			(1,074.5	)			(884.5	)			(1,899.2	)			(2,311.8	)			(1,766.9	)			(1,436.7	)			(2,315.1	)
Operating income			106.2				231.8				87.9				74.4				101.6				311.6				249.1				172.4				394.6
Income (loss) from equity investment			4.4				2.0				4.4				(0.5	)			2.0				9.3				5.1				5.0				3.7
Income tax expense			(1.1	)			(1.7	)			(33.2	)			(26.6	)			(37.3	)			(115.5	)			(91.5	)			(63.8	)			(143.4	)
Net income from continuing operations			109.5				232.1				59.1				47.3				66.3				205.4				162.7				113.6				254.9
Net income from discontinued operations			—				—				3.1				2.5				9.5				10.7				16.0				11.6				28.0
Net income			109.5				232.1			$	62.2			$	49.8			$	75.8			$	216.1			$	178.7			$	125.2			$	282.9
Net income attributable to non-controlling interest			(87.6	)			(185.7	)
Net income attributable to Devon Midstream Partners, L.P.		$	21.9			$	46.4
Net income attributable to Devon Midstream Partners, L.P.:
General partner interest		$				$
Limited partner interests:
Common units
Subordinated units
Total		$				$
Net income per limited partner unit (basic and diluted):
Common units		$				$
Subordinated units
Total		$				$
Balance Sheet Data
Net property, plant and equipment		$	1,786.2							$	1,885.2			$	1,755.8			$	1,843.2			$	1,687.0			$	1,574.6			$	1,499.2			$	1,362.3
Total assets		$	2,223.9							$	2,576.7			$	2,526.0			$	2,535.2			$	2,446.3			$	2,336.0			$	2,276.6			$	2,130.0
Total long-term liabilities		$	17.4							$	446.2			$	456.2			$	449.8			$	461.0			$	418.0			$	318.1			$	271.5
Total equity		$	2,140.2							$	2,057.1			$	1,989.2			$	2,002.0			$	1,901.3			$	1,849.0			$	1,869.7			$	1,750.3
Cash Flow Data
Net cash flows provided by (used in):
Operating activities										$	164.1			$	127.7			$	254.4			$	401.2			$	391.5
Investing activities										$	(160.6	)		$	(161.9	)		$	(368.5	)		$	(268.6	)		$	(220.4	)
Financing activities										$	(3.5	)		$	34.2			$	114.1			$	(132.6	)		$	(171.1	)
Capital expenditures										$	(160.6	)		$	(148.2	)		$	(351.7	)		$	(247.6	)		$	(224.0	)

 

(1)	Operating margin is defined as total operating revenues less the cost of product purchases and operations and maintenance expenses.

(2)	Adjusted EBITDA is a non-GAAP financial measure. For additional information, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Summary—Non-GAAP Financial Measure.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The historical financial statements included in this prospectus reflect the assets, liabilities and operations of Devon Midstream Holdings, L.P. Predecessor (the “Predecessor”), the predecessor to Devon Midstream Holdings, L.P. (“Devon Midstream Holdings”). The Predecessor is comprised of all of Devon’s U.S. midstream assets and operations, including its 38.75% interest in Gulf Coast Fractionators. However, in connection with this offering, only the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma, as well as the 38.75% interest in Gulf Coast Fractionators, will be contributed to Devon Midstream Holdings. These contributed assets represent 90% of the Predecessor’s net income from continuing operations for the six months ended June 30, 2013. After the consummation of this offering, we will own a 20% interest in Devon Midstream Holdings.

The following discussion analyzes the results of operations and financial condition of the Predecessor, including the less significant assets that will not be contributed to Devon Midstream Holdings in conjunction with this offering. You should read this discussion in conjunction with the historical and pro forma financial statements and accompanying notes included in this prospectus. All references in this section to “we,” “our,” “us” or similar terms refer to Devon Midstream Partners, L.P. when used in the present or future tense and refer to our Predecessor when used in historical context.

Overview

We are a limited partnership recently formed by Devon to own, operate, develop and acquire midstream assets in North America. We gather, process and transport natural gas, primarily for Devon, pursuant to long-term contracts that include fee-based rates, annual rate escalators and primary terms of 10 years. We also fractionate NGLs into component NGL products. Under our gathering and processing agreements, we do not have direct exposure to natural gas and NGL prices because we do not take title to the natural gas that we gather, process and transport or the NGLs that we fractionate. Our midstream assets are integral to the success of Devon’s oil and natural gas exploration and production operations, and Devon intends for us to be the primary growth vehicle for its midstream operations in North America.

Our initial asset is a 20% interest in Devon Midstream Holdings, over which we have operating control and which owns substantially all of Devon’s U.S. midstream assets, consisting of natural gas gathering and transportation systems, natural gas processing facilities and NGL fractionation facilities located in Texas and Oklahoma. Our general partner is responsible for managing our operations. As of the date of this offering, Devon will own an 80% interest in Devon Midstream Holdings. We expect to acquire this 80% interest in Devon Midstream Holdings over time pursuant to our right of first offer.

Devon Midstream Holdings’ primary assets consist of three processing facilities with 1.3 Bcf/d of natural gas processing capacity, approximately 3,660 miles of pipelines with aggregate capacity of 2.9 Bcf/d and fractionation facilities with up to 160 MBbls/d of aggregate NGL fractionation capacity. These assets include the following systems and facilities.

 

•

Barnett assets—Devon Midstream Holdings will own the following midstream assets in the Barnett Shale, where Devon is currently the largest natural gas and NGL producer:

 

•

Bridgeport processing facility—This natural gas processing facility is one of the largest processing plants in the U.S. with 790 MMcf/d of processing capacity, 63 MBbls/d of NGL production capacity and 15 MBbls/d of NGL fractionation capacity.

 

•

Bridgeport rich gathering system—This rich natural gas gathering system consists of approximately 2,420 miles of low- and intermediate-pressure pipeline segments with approximately 145,000 horsepower of compression.

 

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•

Bridgeport lean gathering system—This lean natural gas gathering system consists of approximately 300 miles of low-, intermediate- and high-pressure pipeline segments with approximately 59,000 horsepower of compression.

 

•

Acacia transmission system—This transmission system consists of approximately 120 miles of pipeline, associated storage and approximately 17,000 horsepower of compression and interconnects the tailgate of the Bridgeport processing facility and the Bridgeport lean gathering system to intrastate pipelines as well as two local power plants.

 

•

East Johnson County gathering system—This natural gas gathering system consists of approximately 270 miles of low-, intermediate- and high-pressure pipeline segments with approximately 41,000 horsepower of compression.

 

•

Cana system—Devon is currently the largest natural gas producer and one of the largest NGL producers in the Cana-Woodford Shale in West Central Oklahoma. This natural gas gathering and processing system consists of a 350 MMcf/d processing facility, 30 MBbls/d of NGL production capacity and approximately 410 miles of associated low-, intermediate- and high-pressure pipeline segments with approximately 92,500 horsepower of compression.

 

•

Northridge system—This natural gas gathering and processing system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma and consists of a 200 MMcf/d processing facility, 17 MBbls/d of NGL production capacity and approximately 140 miles of associated low-, intermediate- and high-pressure pipeline segments with approximately 18,000 horsepower of compression.

 

•

Gulf Coast Fractionators—Devon Midstream Holdings will own a 38.75% non-operating equity interest in Gulf Coast Fractionators, an NGL fractionator located on the Texas Gulf Coast at the Mont Belvieu hub. This facility has a capacity of approximately 120 MBbls/d to 145 MBbls/d depending on the composition of the inlet NGL stream.

Our Operations

Our results are driven primarily by the volumes of natural gas Devon Midstream Holdings gathers, processes and transports through its systems. This volume throughput is substantially dependent on Devon’s success in the regions where we operate. Devon is a leading independent energy company engaged primarily in the exploration, development and production of oil, natural gas and NGLs. Devon is the largest natural gas producer in the Barnett and Cana-Woodford Shales, the largest NGL producer in the Barnett Shale and one of the largest NGL producers in the Cana-Woodford Shale. For the six months ended June 30, 2013, 91% of our operating revenues were generated by transactions with Devon.

In Devon Midstream Holdings’ gathering operations, it contracts with producers to gather natural gas from individual wells located near its gathering systems. Devon Midstream Holdings connects wells to gathering lines through which natural gas is compressed and may be delivered to a processing plant or downstream pipeline, and ultimately to end-users.

Devon’s operations are concentrated in various onshore areas in the U.S. and Canada. Devon has dedicated to Devon Midstream Holdings natural gas production for 10 years from 795,000 net acres in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. We expect all of these dedications to result in associated deliveries to Devon Midstream Holdings’ Bridgeport, Cana, East Johnson County and Northridge systems. Devon has provided five-year minimum natural gas volume commitments to Devon Midstream Holdings of 850 MMcf/d to the Bridgeport gathering systems, 650 MMcf/d to the Bridgeport processing facility, 125 MMcf/d to the East Johnson County gathering system, 330 MMcf/d to the Cana system and 40 MMcf/d to the Northridge system, representing 88% of the total projected volumes for these assets for the twelve months ended September 30, 2014.

Our Predecessor historically provided services pursuant to fixed-fee and percent-of-proceeds contracts. Under the recently entered into fixed-fee arrangements, Devon Midstream Holdings will receive a fixed fee

 

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based on the volume and thermal content of the natural gas gathered, processed and transported. Our Predecessor’s percent-of- proceeds arrangements were based on the sales value of extracted NGLs and residue natural gas that resulted from natural gas processing. Additionally, our Predecessor historically took title to the natural gas it gathered and processed.

In connection with this offering, Devon Midstream Holdings will enter into new contracts with Devon pursuant to which it will provide services under fixed-fee arrangements and will not take title to the natural gas gathered, processed and transported. We believe this change will provide us with a relatively steady revenue stream that is not subject to direct commodity price risk. We will nevertheless continue to have indirect exposure to commodity price risk in that persistently low commodity prices may cause Devon to delay drilling or shut in production, which would reduce the throughput on Devon Midstream Holdings’ assets. Please read “—Quantitative Disclosures About Market Risk” for a discussion of our exposure to commodity price risk.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to evaluate our performance. These metrics help us identify factors and trends that impact our operating results, profitability and financial condition. The key metrics we use to evaluate our business are provided below.

Operating Margin

We use operating margin as a performance measure of the core profitability of our operations. We define operating margin as total operating revenues, which consist of revenues generated from the sale of natural gas and NGLs plus service fee revenues, less the cost of product purchases, consisting primarily of producer payments and other natural gas purchases, and operations and maintenance expenses. We use operating margin to assess:

 

•

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

 

•

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

 

•

the viability of acquisitions and capital expenditure projects.

Adjusted EBITDA and Distributable Cash Flow

We use Adjusted EBITDA and distributable cash flow as performance and liquidity measures to assess the ability of our assets to generate cash sufficient to pay interest costs, support indebtedness and make distributions to our unitholders. Although we have not quantified distributable cash flow historically, we intend to use distributable cash flow and Adjusted EBITDA to assess our performance after the closing of this offering. We expect that Adjusted EBITDA will be a financial measure reported to our lenders and used as a gauge for compliance with some of our anticipated financial covenants under our new revolving credit facility. We define Adjusted EBITDA as income from continuing operations before interest expense, income taxes and depreciation and amortization expense. We define distributable cash flow as Adjusted EBITDA less net interest and income taxes paid and maintenance capital expenditures. We use Adjusted EBITDA and distributable cash flow to assess:

 

•

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

 

•

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

 

•

the viability of acquisitions and capital expenditure projects.

 

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Adjusted EBITDA and distributable cash flow are non-GAAP financial measures. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net cash provided by operating activities and income from continuing operations. The non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as alternatives to the GAAP measures of net cash provided by operating activities and income from continuing operations. Adjusted EBITDA and distributable cash flow are not presentations made in accordance with GAAP and have important limitations as analytical tools because they include some, but not all, items that affect net cash provided by operating activities and income from continuing operations. You should not consider Adjusted EBITDA and distributable cash flow in isolation or as substitutes for analysis of results as reported under GAAP. Our and our Predecessor’s definition of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies. For more information regarding Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Summary—Non-GAAP Financial Measure.”

Natural Gas Throughput

We must continually obtain additional supplies of natural gas to maintain or increase throughput on Devon Midstream Holdings’ systems. Our ability to maintain existing supplies of natural gas and obtain additional supplies is primarily impacted by our acreage dedication and the level of successful drilling activity by Devon and, to a lesser extent, the acreage dedications with and successful drilling by other producers.

Items Affecting Comparability of Our Financial Results

The historical financial results of our Predecessor discussed below may not be comparable to our future financial results for the following reasons:

 

•

Our Predecessor’s historical assets comprised all of Devon’s U.S. midstream assets and operations. However, only its assets serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as the 38.75% interest in Gulf Coast Fractionators, will be contributed to Devon Midstream Holdings in connection with this offering. These assets generated approximately 90% of our Predecessor’s net income from continuing operations for the six months ended June 30, 2013.

 

•

After the consummation of this offering, we will own a 20% interest in Devon Midstream Holdings rather than the 100% ownership reflected as part of our Predecessor’s historical financial results. We will control Devon Midstream Holdings through our ownership of its general partner. Our pro forma financial statements consolidate, and our financial statements after the closing of this offering will consolidate, all of Devon Midstream Holdings’ financial results with ours in accordance with GAAP. Consequently, our future consolidated financial statements will include Devon Midstream Holdings as a consolidated subsidiary, and Devon’s 80% interest will be reflected as a non-controlling interest.

 

•

Devon Midstream Holdings will enter into new agreements with Devon pursuant to which Devon Midstream Holdings will provide services under fixed-fee arrangements and will no longer take title to the natural gas gathered and processed or the NGLs it fractionates.

 

•

We expect to incur approximately $3.5 million in incremental, annual general and administrative expenses as a result of becoming a separate, publicly-traded partnership. These costs include fees associated with annual and quarterly reports to unitholders, tax returns and Schedule K-1 preparation and distribution, investor relations, registrar and transfer agent fees, incremental insurance costs, accounting, auditing and legal services and independent director compensation.

 

•

Our Predecessor’s historical combined financial statements include U.S. federal and state income tax expense. Due to our status as a partnership, we will not be subject to U.S. federal income tax and certain state income taxes in the future. However, we will make payments to Devon pursuant to a tax sharing agreement for our share of state and local income and other taxes that are included in combined or consolidated tax returns filed by Devon.

 

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•

All historical affiliated transactions related to our continuing operations were net settled within our combined financial statements because these transactions related to Devon and were funded by Devon’s working capital. In the future, all our transactions will be funded by our working capital. This will impact the comparability of our cash flow statements, working capital analysis and liquidity discussion.

 

•

Following the closing of this offering, we intend to make cash distributions to our unitholders and Devon at an initial distribution rate of $         per unit per quarter ($         per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and Devon most of the cash generated by our operations. As a result, we expect that we will rely upon external financing sources, including commercial bank borrowings and debt and equity issuances, to fund our acquisition and expansion capital expenditures. Historically, our Predecessor largely relied on internally generated cash flows and capital contributions from Devon to satisfy its capital expenditure requirements.

 

•

Upon the closing of this offering, we will enter into a $         million revolving credit facility agreement that we expect will incur interest expense at customary short-term interest rates.

General Trends and Outlook

Natural Gas and NGL Supply and Demand

Devon Midstream Holdings’ gathering and processing operations are generally dependent upon natural gas production from Devon’s upstream activity in its areas of operation. The significant decline in natural gas prices as a result of significant new supplies of domestic natural gas production has caused a related decrease in dry natural gas drilling by many producers in the United States. Depressed oil and natural gas prices could affect production rates over time and levels of investment by Devon and third parties in exploration for and development of new oil and natural gas reserves. In addition, there is a natural decline in production from existing wells that are connected to our gathering systems. We believe Devon’s five-year minimum volume commitments substantially reduce our volumetric risk over that period of time. Although we expect that Devon will continue to devote substantial resources to the development of the Barnett and Cana-Woodford Shales, we have no control over this activity and Devon has the ability to reduce or curtail such development at its discretion. Please read “Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations.”

Rising Operating Costs and Inflation

The current level of exploration, development and production activities across the United States has resulted in increased competition for personnel and equipment. This competition has caused, and we believe will continue to cause, increases in the prices we pay for labor, supplies and property, plant and equipment. An increase in the general level of prices in the economy could have a similar effect on the operating costs we incur. We attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

Impact of Interest Rates

Interest rates have been volatile in recent periods. If interest rates rise, our future financing costs under our revolving credit facility and any other debt instruments will increase accordingly. In addition, because our common units are yield-based securities, rising market interest rates could impact the relative attractiveness of our common units to investors, which could limit our ability to raise funds, or increase the price of raising funds, in the capital markets and may limit our ability to expand our operations or make future acquisitions.

 

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Regulatory Compliance

The regulation of natural gas gathering and transportation activities by FERC and other federal and state regulatory agencies, including the DOT, has a significant impact on our business. For example, the DOT’s Pipeline and Hazardous Materials Safety Administration, or PHMSA, has established pipeline integrity management programs that require more frequent inspections of pipeline facilities and other preventative measures, which may increase our compliance costs and increase the time it takes to obtain required permits. Additionally, increased regulation of oil and natural gas producers, including regulation associated with hydraulic fracturing, could reduce regional supply of oil and natural gas and therefore throughput on our gathering systems. For more information see “Business—Regulation of Operations.”

Growth Opportunities

We expect to acquire Devon’s 80% retained interest in Devon Midstream Holdings over time, and we have a right of first offer with respect to acquiring that interest from Devon. In addition, because of its participation in any increases to our cash distributions through the incentive distribution rights, as well as its         % limited partner interest in us, Devon is positioned to directly benefit from growth in the volumes on Devon Midstream Holdings’ systems from both Devon and third parties and our accretive acquisition of other midstream assets from Devon and third parties. However, Devon is under no obligation to offer us the opportunity to purchase their retained interest in Devon Midstream Holdings.

 

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Results of Our Predecessor’s Operations

The following schedule presents our Predecessor’s historical combined key operating and financial metrics.

 

		Six Months Ended June 30,								Year Ended December 31,
		2013				2012				2012				2011				2010
		($ in millions, except prices)
Operating revenues		$	1,162.4			$	958.9			$	2,000.8			$	2,623.4			$	2,016.0
Product purchases			(862.1	)			(695.7	)			(1,464.5	)			(2,014.1	)			(1,468.9	)
Operations and maintenance expenses			(82.7	)			(83.6	)			(171.0	)			(155.5	)			(119.5	)
Operating margin			217.6				179.6				365.3				453.8				427.6
Other operating expenses, net			(129.7	)			(105.2	)			(263.7	)			(142.2	)			(178.5	)
Income (loss) from equity investment			4.4				(0.5	)			2.0				9.3				5.1
Income tax expense			(33.2	)			(26.6	)			(37.3	)			(115.5	)			(91.5	)
Net income from continuing operations			59.1				47.3				66.3				205.4				162.7
Net income from discontinued operations			3.1				2.5				9.5				10.7				16.0
Net income attributable to Devon		$	62.2			$	49.8			$	75.8			$	216.1			$	178.7
Adjusted EBITDA (1)		$	190.7			$	153.0			$	315.7			$	467.4			$	380.6
Throughput (thousands of MMBtu/d):
Bridgeport rich gathering system			860.1				807.3				818.4				811.6				731.1
Bridgeport lean gathering system			269.3				308.0				298.0				296.0				311.3
Acacia transmission system			753.7				730.8				732.7				700.1				698.4
East Johnson County gathering system			242.8				274.4				277.8				258.0				201.3
Barnett assets			2,125.9				2,120.5				2,126.9				2,065.7				1,942.1
Cana gathering system			310.1				238.6				265.7				175.7				96.4
Northridge gathering system			72.3				90.0				85.0				109.5				117.5
Other systems			226.1				253.5				243.0				286.5				314.0
Total			2,734.4				2,702.6				2,720.6				2,637.4				2,470.0
NGL production (MBbls/d):
Bridgeport processing facility			54.6				46.8				49.4				52.8				49.8
Cana processing facility			16.0				9.9				12.1				3.9				0.2
Northridge processing facility			8.7				6.6				6.8				10.5				9.4
Other systems			2.6				2.6				2.7				2.5				2.7
Total			81.9				65.9				71.0				69.7				62.1
Residue natural gas production (thousands of MMBtu/d):
Bridgeport processing facility			637.2				607.9				613.1				599.5				530.4
Cana processing facility			241.1				190.4				209.7				151.5				8.1
Northridge processing facility			55.7				69.2				65.5				85.3				96.2
Other systems			8.1				7.5				7.4				2.6				1.8
Total			942.1				875.0				895.7				838.9				636.5
Realized prices:
NGLs ($/Bbl)		$	29.31			$	40.22			$	35.38			$	49.16			$	38.72
Residue natural gas ($/MMBtu)		$	3.27			$	2.06			$	2.38			$	3.58			$	3.76

 

(1)	Adjusted EBITDA is a non-GAAP financial measure. For additional information, including a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Summary—Non-GAAP Financial Measure.”

 

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Since 2010, operating margin and Adjusted EBITDA have consistently improved as a result of throughput growth and higher NGL production. The largest contributors to rising throughput have been our Cana, Bridgeport rich, East Johnson County and Acacia systems, with daily throughput growth of 222%, 18%, 21% and 8%, respectively, from 2010 to the first six months of 2013. This growth is the result of Devon and other producers developing liquids-rich natural gas production in the Cana-Woodford and Barnett Shales. However, overall growth has been limited by throughput declines for our Predecessor’s other systems, which are the result of natural gas price decreases. As natural gas prices have dropped relative to oil and NGL prices in recent years, many producers, including Devon, have focused on growing their oil and liquids-rich natural gas production rather than dry natural gas. Consequently, Devon Midstream Holdings’ systems serving liquids-rich natural gas regions in the Cana-Woodford and Barnett Shales have higher throughput, while Devon Midstream Holdings’ systems serving dry natural gas regions have experienced throughput declines.

Prices have also impacted operating margin and Adjusted EBITDA. Since 2011, both natural gas and NGL prices have declined significantly, which have negatively impacted operating margin and Adjusted EBITDA.

Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Operating Margin

Operating margin increased $38.0 million, or 21%, from the six months ended June 30, 2012 to the six months ended June 30, 2013, as summarized in the following schedule:

 

		(in millions)
Operating margin, 2012		$	179.6
Change due to volumes			19.6
Change due to pricing			17.5
Change due to operations and maintenance expenses			0.9
Operating margin, 2013		$	217.6

Higher gathering, processing and transportation volumes were responsible for an increase in operating margin of $19.6 million for the six months ended June 30, 2013 compared to the six months ended June 30, 2012. Higher volumes were primarily the result of NGL production increasing nearly 25%, resulting in $17.6 million of higher operating margin. The increase in NGL production was largely driven by higher inlet volumes at the Cana processing facility, improved efficiencies at the Cana and Bridgeport processing facilities and unplanned downtime impacting our Bridgeport processing facility in 2012. The remaining $2.0 million of higher operating margin was largely due to an 8% increase in residue natural gas volumes due to continued development of the liquids-rich areas in the Cana-Woodford and Barnett Shales.

Changes in pricing led to an increase in operating margin of $17.5 million for the six months ended June 30, 2013 compared to the six months ended June 30, 2012. Higher residue natural gas prices contributed an additional $24.4 million to operating margin. Additionally, natural gas pipeline fees increased 15%, which resulted in $21.3 million of additional revenues. These increases were partially offset by lower margins of $28.2 million primarily due to NGL price declines.

Operations and maintenance expenses decreased $0.9 million, or 1%, for the six months ended June 30, 2013 compared to the six months ended June 30, 2012.

 

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Other Operating Expenses, Net

Other operating expenses, net increased $24.5 million, or 23%, from the six months ended June 30, 2012 to the six months ended June 30, 2013, as summarized in the following schedule:

 

		2013				2012				Change
		(in millions)
Depreciation and amortization		$	96.8			$	78.3			$	18.5
General and administrative			22.4				21.6				0.8
Non-income taxes			9.0				8.8				0.2
Other, net			1.5				(3.5	)			5.0
Other operating expenses, net		$	129.7			$	105.2			$	24.5

Depreciation and amortization expense increased $18.5 million, or 24%, from the first six months of 2012 to the first six months of 2013. The increase primarily resulted from higher capitalized costs on the Cana system and, to a lesser extent, the Barnett assets. Devon and other producers have continued to grow natural gas production in the Cana-Woodford and Barnett Shales. As a result, we have increased our throughput capacity by expanding our pipeline and gathering systems and our Cana and Bridgeport processing facilities.

Historical general and administrative expenses consist of costs allocated by Devon for shared services that consist primarily of accounting, treasury, information technology, human resources, legal and facilities management. The costs were allocated based on a proportionate share of Devon’s revenues, employee compensation and gross property, plant and equipment.

General and administrative expense increased $0.8 million, or 4%, from the first six months of 2012 to the first six months of 2013 due to general inflationary increases.

Non-income tax expense consists primarily of ad valorem taxes. Non-income taxes increased $0.2 million, or 2%, from the first six months of 2012 to the first six months of 2013 primarily due to higher ad valorem tax assessments on our Cana assets.

During the first six months of 2013 and 2012, our Predecessor recognized net other expense of $1.5 million and net other income of $3.5 million, respectively. In the second quarter of 2012, our Predecessor received insurance proceeds of $5.6 million related to business interruption that occurred at Gulf Coast Fractionators.

Income Tax Expense

During the first six months of 2013 and 2012, our effective income tax rates were 36% for both periods. These rates differed from the U.S. statutory income tax rate due to the effect of state income taxes.

Discontinued Operations

Our Predecessor is in the process of selling or has sold certain non-core midstream assets that are presented as discontinued operations in our Predecessor’s historical financial statements. Net income from discontinued operations increased $0.6 million from the first six months of 2012 to the first six months of 2013.

 

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

Operating Margin

Operating margin decreased $88.5 million, or 20%, from the year ended December 31, 2011 to the year ended December 31, 2012, as summarized in the following schedule:

 

		(in millions)
Operating margin, 2011		$	453.8
Change due to volumes			20.8
Change due to pricing			(93.8	)
Change due to operations and maintenance expenses			(15.5	)
Operating margin, 2012		$	365.3

Higher gathering, processing and transportation volumes were responsible for an increase in operating margin of $20.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. Residue volumes increased 7%, resulting in a $9.1 million increase to operating margin. The remainder of the operating margin increase resulted from higher natural gas gathered volumes and NGL production, which increased 3% and 2%, respectively. These volume increases primarily resulted from the restart of our Cana processing facility following tornado damage in 2011, higher volumes on our East Johnson County gathering system and continued development of the liquids-rich areas in the Cana-Woodford and Barnett Shales.

Changes in pricing led to a decrease in operating margin of $93.8 million for the year ended December 31, 2012 compared to the year ended December 31, 2011. Lower NGL and residue natural gas prices reduced operating margin by $71.0 million and $42.8 million, respectively. These decreases were partially offset by higher gathering and compression fees which increased $20.0 million, or 9%.

Operations and maintenance expenses increased $15.5 million, or 10%, partially due to higher volumes, including the Cana system expansion. Expenses also increased due to repair and testing activities that were required on our Bridgeport gathering systems in 2012.

Other Operating Expenses, Net

Other operating expenses, net increased $121.5 million, or 85%, from the year ended December 31, 2011 to the year ended December 31, 2012, as summarized in the following schedule:

 

		2012				2011				Change
		(in millions)
Depreciation and amortization		$	159.8			$	144.8			$	15.0
General and administrative			43.6				40.1				3.5
Non-income taxes			13.2				15.3				(2.1	)
Asset impairments			50.1				—				50.1
Other, net			(3.0	)			(58.0	)			55.0
Other operating expenses, net		$	263.7			$	142.2			$	121.5

Depreciation and amortization expense increased $15.0 million, or 10%, from 2011 to 2012. The increase primarily resulted from higher capitalized costs on the Cana system. Devon and other producers have continued to grow natural gas production in the Cana-Woodford Shale. As a result, we have increased our throughput capacity by expanding our pipeline and gathering systems and our Cana processing facility.

Historical general and administrative expenses consist of costs allocated by Devon for shared services that consist primarily of accounting, treasury, information technology, human resources, legal and facilities management. The costs were allocated based on a proportionate share of Devon’s revenues, employee compensation and gross property, plant and equipment.

 

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General and administrative expense increased $3.5 million, or 9%, from 2011 to 2012, primarily due to higher employee compensation and benefits.

Non-income tax expense consists primarily of ad valorem taxes. Non-income taxes decreased $2.1 million, or 14%, from 2011 to 2012 primarily due to lower ad valorem tax assessments on our Barnett assets.

The following schedule summarizes asset impairments recognized in 2012. There were no asset impairments in 2011. Due to declining natural gas production resulting from low natural gas and NGL prices, we determined that the carrying amounts of certain of our Predecessors’ midstream assets, including the Northridge system, were not recoverable from estimated future cash flows. Consequently, the Northridge system and other assets of our Predecessor were written down to their estimated fair values, which were determined using discounted cash flow models.

 

		2012
		(in millions)
Northridge		$	16.3
Other assets not being contributed to Devon Midstream Holdings			33.8
Total asset impairments		$	50.1

During 2012 and 2011, our Predecessor recognized $3.0 million and $58.0 million of net other income, respectively. In 2012, our Predecessor received insurance proceeds of $5.6 million related to business interruption that occurred at Gulf Coast Fractionators. In 2011, our Predecessor received $57.8 million of excess insurance recoveries related to business interruption and equipment damage at the Cana system that resulted from tornadoes.

Income Tax Expense

During 2012 and 2011, our effective income tax rates were 36% for both periods. These rates differed from the U.S. statutory income tax rate due to the effect of state income taxes.

Discontinued Operations

Our Predecessor is in the process of selling or has sold certain non-core assets that are presented as discontinued operations in our Predecessor’s historical financial statements. Net income from discontinued operations decreased $1.2 million from 2011 to 2012. The decrease was due to lower operating earnings subsequent to the divestiture of the West Johnson County processing facility and gathering system in 2012, partially offset by the $8.3 million gain recognized on the divestiture.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Operating Margin

Operating margin increased $26.2 million, or 6%, from the year ended December 31, 2010 to the year ended December 31, 2011, as summarized in the following schedule:

 

		(in millions)
Operating margin, 2010		$	427.6
Change due to volumes			83.4
Change due to pricing			(21.2	)
Change due to operations and maintenance expenses			(36.0	)
Operating margin, 2011		$	453.8

 

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Higher gathering, processing and transportation volumes were responsible for an increase in operating margin of $83.4 million for the year ended December 31, 2011 compared to the year ended December 31, 2010. Residue natural gas volumes increased 32%, resulting in a $40.7 million operating margin increase. Additionally, NGL production and natural gas pipeline throughput increased 12% and 7%, respectively, contributing to the remainder of the increase. The production increase was primarily related to the continued development of the liquids-rich areas in the Cana-Woodford and Barnett Shales, including the Cana processing facility startup in December 2010.

Changes in pricing led to a decrease in operating margin of $21.2 million for the year ended December 31, 2011 compared to the year ended December 31, 2010. Lower residue natural gas prices reduced the operating margin by $39.1 million. A 5% decline in gathering and compression fees decreased the operating margin by $14.1 million. These decreases were partially offset by higher NGL prices, which increased operating margin by $32.0 million.

Operations and maintenance expenses increased $36.0 million, or 30%. The increase was driven by higher volumes and personnel costs associated with the startup of the new Cana processing facility. Expenses also increased $11.0 million due to regulatory testing costs and $8.0 million due to higher maintenance and repair costs.

Other Operating Expenses, Net

Other operating expenses, net decreased $36.3 million, or 20%, from the year ended December 31, 2010 to the year ended December 31, 2011, as summarized in the following schedule:

 

		2011				2010				Change
		(in millions)
Depreciation and amortization		$	144.8			$	124.9			$	19.9
General and administrative			40.1				39.4				0.7
Non-income taxes			15.3				13.8				1.5
Other, net			(58.0	)			0.4				(58.4	)
Other operating expenses, net		$	142.2			$	178.5			$	(36.3	)

Depreciation and amortization expense increased $19.9 million, or 16%, from 2010 to 2011. The increase primarily resulted from higher capitalized costs on the Cana system. Devon and other producers have continued to grow natural gas production in the Cana-Woodford Shale. As a result, we have increased our throughput capacity by expanding our pipeline and gathering systems and our Cana processing facility.

Historical general and administrative expenses consist of costs allocated by Devon for shared services that consist primarily of accounting, treasury, information technology, human resources, legal and facilities management. The costs were allocated based on a proportionate share of Devon’s revenues, employee compensation and gross property, plant and equipment.

General and administrative expense increased $0.7 million, or 2%, due to general inflationary increases.

Non-income tax expense consists primarily of ad valorem taxes. Non-income taxes increased $1.5 million, or 11%, from 2010 to 2011 primarily due to higher ad valorem tax assessments on our Cana assets.

During 2011 and 2010, our Predecessor recognized $58.0 million of net other income and $0.4 million of net other expense, respectively. In 2011, our Predecessor received $57.8 million of excess insurance recoveries related to business interruption and equipment damage at the Cana system that resulted from tornadoes.

Income Tax Expense

During 2011 and 2010, effective income tax rates were 36% for both periods. These rates differed from the U.S. statutory income tax rate due to the effect of state income taxes.

 

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Discontinued Operations

Our Predecessor is in the process of selling or has sold certain non-core assets that are presented as discontinued operations in our Predecessor’s historical financial statements. Net income from discontinued operations decreased $5.3 million from 2010 to 2011. The decrease was primarily due to lower earnings on the Thunder Creek system.

Our Liquidity and Capital Resources

Sources and Uses of Cash

Capital and liquidity has historically been provided by our operating cash flow and we expect this will continue in the future. Additionally, other sources of liquidity will include borrowing capacity under the $             million revolving credit facility we will enter into and proceeds from the issuance of additional limited partner units. We expect the combination of these capital resources will be adequate to meet our short-term working capital requirements, long-term capital expenditures program and expected quarterly cash distributions.

In May 2013, our Predecessor entered into an agreement to sell our controlling interest in our assets and operations located in Montana for approximately $10 million. In August 2013, our Predecessor sold our controlling interest in our assets and operations located in Wyoming for approximately $148 million.

Historically, all cash receipts that pertained to continuing operations were deposited into Devon’s bank accounts, and all cash disbursements were made from these accounts. Accordingly, our Predecessor’s financial statements have reflected no cash balances attributable to continuing operations. Separate cash accounts have been established for two subsidiaries that are included in discontinued operations. Cash transactions handled by Devon were reflected in intercompany advances between Devon and our Predecessor. Following the consummation of this initial public offering, we will maintain our own bank accounts but will continue to utilize Devon’s personnel to manage our cash and investments.

Devon Midstream Holdings’ limited partnership agreement effective as of the closing of this offering provides for the distribution of available cash on a quarterly basis. We expect future cash requirements for Devon Midstream Holdings relating to working capital, maintenance capital expenditures and quarterly cash distributions to its partners, including us, to be funded from cash flows internally generated from its operations. Growth or expansion capital expenditures for Devon Midstream Holdings will be funded by either cash calls to its partners, which consist of us and Devon, or from potential capital market transactions by us or Devon.

The following schedule presents our sources and uses of cash:

 

		Six Months Ended June 30,								Year Ended December 31,
		2013				2012				2012				2011				2010
		(in millions)
Continuing operations:
Operating cash flow		$	164.1			$	127.7			$	254.4			$	401.2			$	391.5
Capital expenditures			(160.6	)			(148.2	)			(351.7	)			(247.6	)			(224.0	)
Contributions from (distributions to) owners			(3.5	)			35.8				115.7				(131.1	)			(171.8	)
Other, net			—				(15.3	)			(18.4	)			(22.5	)			4.3
Net change in cash			—				—				—				—				—
Discontinued operations:
Operating cash flow			3.5				16.2				25.3				33.4				49.1
Divestiture proceeds			0.9				—				87.6				—				1.2
Capital expenditures			(1.2	)			(11.5	)			(13.5	)			(22.5	)			(7.1	)
Contributions from (distributions to) owners			(4.8	)			1.7				(91.9	)			(34.8	)			(32.1	)
Net change in cash			(1.6	)			6.4				7.5				(23.9	)			11.1
Total change in cash		$	(1.6	)		$	6.4			$	7.5			$	(23.9	)		$	11.1

 

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Sources and Uses of Cash—Continuing Operations

Operating cash flow has been a significant source of liquidity. Generally, operating cash flow will increase or decrease due to the same factors that cause increases and decreases in operating margin and Adjusted EBITDA. Consequently, changes in operating cash flow since 2010 are primarily driven by the fluctuations in volume and price described previously in results of operations.

Historically, operating cash flow has been used to fund capital expenditures. Since 2010, our Predecessor completed several capital expansion activities, including the start-up of the processing facility at Cana in 2010 and expansions of the Cana system and Barnett assets in 2013.

Because our continuing operations had no separate cash accounts, the owner contributions and distributions represent the net amount of all transactions that were settled with adjustments to equity.

Other, net uses and sources since 2010 largely pertain to our Predecessor’s equity investment in Gulf Coast Fractionators. During the first six months of 2012 and the years ended December 31, 2012 and 2011, our Predecessor made contributions related to this investment of $13.7 million, $16.8 million and $21.1 million, respectively. During 2010, we received a $3.6 million distribution from this investment in excess of the cumulative income.

Sources and Uses of Cash—Discontinued Operations

Operating cash flow has decreased since 2010 largely due to declining throughput resulting from asset divestitures. In 2012, our Predecessor sold the West Johnson County system for $87.1 million. Our Predecessor also received proceeds in 2013 and 2010 for other minor divestitures. These divestitures also contributed to the general decline in capital expenditures since 2010.

During the first six months of 2013 and the years ended 2011 and 2010, our Predecessor made cash distributions to non-controlling interests of $2.3 million, $5.4 million and $4.7 million, respectively. During the first six months of 2012 and the year ended 2012, our Predecessor received cash contributions from non-controlling interests of $4.8 million and $2.3 million, respectively. The remaining owner contributions and distributions in the table above represent the net amount of all other transactions that were settled with adjustments to equity.

Capital Requirements

The midstream business is capital intensive and can require significant investment to maintain and upgrade existing operations, connect new wells to the system, organically grow into new areas and comply with environmental and safety regulations. Going forward, our capital requirements will consist of the following:

 

•

maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of assets and extend their useful lives or to maintain existing system volumes and related cash flows; and

 

•

expansion capital expenditures, which are made to construct additional assets to increase operations, to expand and upgrade existing systems and facilities or to acquire additional assets which increase operations.

As more completely discussed in “Our Cash Distribution Policy and Restrictions on Distributions—Assumptions and Considerations,” for the twelve months ended ending September 30, 2014, we estimate that Devon Midstream Holdings’ maintenance and expansion capital expenditures will total approximately $132.0 million. Devon Midstream Holdings’ future expansion capital expenditures may vary significantly from period to period based on the investment opportunities available to us. We expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our revolving credit facility or new debt offerings or the issuance of additional partnership units.

 

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Contractual Obligations

A summary of our contractual obligations as of December 31, 2012 is provided in the following table:

 

		Payments Due by Period
		Total				Less Than 1 Year				1-3 Years				3-5 Years				More Than 5 Years
		(in millions)
Lease obligations (1)		$	26.8			$	21.6			$	5.2			$	—			$	—
Rights-of-way (2)			1.1				0.2				0.2				0.2				0.5
Purchase commitments (3)			21.4				21.4				—				—				—
Asset retirement obligations (4)			13.2				0.1				0.1				0.1				12.9
Total		$	62.5			$	43.3			$	5.5			$	0.3			$	13.4

 

(1)	Lease obligations consist of non-cancelable operating leases for equipment and office space used in daily operations.

(2)	Right-of-way payments are estimated to approximate $0.1 million per year for the next ten years. Payments for rights-of-way will be required as long as Devon Midstream Holdings’ systems are in use, which may be more or less than the ten years we have assumed for this disclosure.

(3)	Purchase commitments include commitments to purchase materials in connection with our projects to construct new facilities or expand existing facilities.

(4)	Asset retirement obligations represent the estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2012 balance sheet.

Our Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires us to make estimates, judgments 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 revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Changes in these estimates can have a material effect on the financial statements.

The critical accounting policies used by management in the preparation of our combined financial statements are those that require significant judgments by management with regard to estimates used and are important both to the presentation of our financial condition and results of operations. Our critical accounting policies and significant judgments and estimates related to those policies are described below.

Allocation of Devon Corporate Overhead Costs

Certain of Devon’s centralized overhead and operating costs are incurred for the benefit of its subsidiaries and affiliates, including us. As a result, a portion of such costs are allocated to our operations. The portion of such costs that directly benefits our operations is allocated entirely to us. The remaining portion of costs that benefits us and other Devon affiliates is allocated using a three-factor formula. This formula uses an equal weighting of revenues, employee compensation and gross property, plant and equipment balances to determine amounts to be allocated to us and other Devon affiliates.

These cost allocations are affected by the amount of costs Devon incurs for its centralized overhead and operating activities and the allocation methodologies chosen. Determining the amount of costs Devon incurs for its centralized overhead and operating activities generally does not require significant judgment by management because such costs are readily identifiable. Although there are a number of alternative methodologies for allocating Devon’s centralized overhead and operating costs, management believes the allocation methodologies used are based on assumptions that are reasonable. However, if certain costs were allocated using different methodologies, our distributable cash, profitability and financial condition could change significantly.

 

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Depreciation of Property, Plant and Equipment

Our depreciation calculations include estimates of salvage value and useful lives. As estimates of salvage values decrease, the amount of depreciation recognized in successive periods and over the estimated useful life of PP&E increases. We estimate salvage values to be near zero at the end of the asset’s useful life.

Similar to salvage value estimates, as estimates of useful lives decrease, the amount of depreciation recognized in successive periods increases. However, useful life estimates have no impact on the amount of depreciation recognized over the life of PP&E. For assets subject to the straight-line method of calculating depreciation, we utilize estimated useful lives ranging from three to 25 years. These estimates are based on the historical usage of similar assets.

For assets subject to the units-of-production basis of calculating depreciation, useful lives are estimated based on proved oil, natural gas and NGL reserve estimates from the fields being serviced by those assets. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, natural gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. However, based on historical experience, such differences are not expected to be material.

Impairment of Property, Plant & Equipment

We evaluate PP&E for potential impairment annually and more frequently when events or changes in circumstances indicate that the carrying amount of our PP&E may not be recoverable from estimated future cash flows.

We determine PP&E fair values from estimated discounted future net cash flows. The estimated cash flows can be significantly affected by the inputs used in the calculations, such as future throughput volumes, natural gas and NGL prices, operating costs, useful lives and discount rates. Different assumptions and judgments could be used to determine the cash flow inputs. There are also alternative valuation techniques that could be used to estimate fair value.

There are a number of inter-related inputs that can affect discounted cash flows. Due to the number of inter-related inputs, it is impractical to provide specific quantitative analyses of potential changes in these estimates. However, general analyses can be provided for the most significant inputs which include current and projected throughput and current and projected natural gas and NGL prices. As such inputs decrease, the cash flows will generally change in a like manner and would increase the likelihood of a PP&E impairment charge.

A PP&E impairment would have no direct effect on our operating margin, Adjusted EBITDA or liquidity. However, it would adversely affect our net income.

Goodwill Valuation

We have one reporting unit with goodwill, which requires management to estimate the fair value of the reporting unit and evaluate goodwill for potential impairment. We test goodwill annually in the fourth quarter of each year and more frequently when an event occurs or circumstances change that would more likely than not reduce the fair value of our reporting unit below its carrying amount.

Because quoted market prices are not available for our reporting unit, we estimate its fair value using valuation analyses based on values of comparable companies and comparable transactions. In a comparable companies analysis, we review the public stock market trading multiples for selected publicly-traded midstream companies with comparable financial and operating characteristics. These characteristics are market

 

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capitalization, location of midstream operations and the characterization of such operations that are deemed to be similar to ours. In a comparable transactions analysis, we review certain acquisition multiples for selected recent midstream company or asset package transactions.

The fair value of our reporting unit is then estimated by applying the average multiple determined from the two valuation techniques described above to current year projected Adjusted EBITDA. As these valuation multiples and projected Adjusted EBITDA decrease, the estimated fair value of the reporting unit would decrease. As a result, the likelihood of a goodwill impairment charge would increase.

There are a number of inter-related inputs which can affect the valuation multiples and projected Adjusted EBITDA. Due to the number of inter-related inputs, it is impractical to provide specific quantitative analyses of potential changes in these estimates. However, general analyses can be provided for the most significant inputs which include current and projected throughput and current and projected natural gas and NGL prices. As such inputs decrease, the trading multiples and Adjusted EBITDA will generally change in a like manner and would increase the likelihood of a goodwill impairment charge.

A goodwill impairment would have no direct effect our operating margin, Adjusted EBITDA, distributable cash flow or liquidity. However, it would adversely affect our net income.

Quantitative Disclosures About Market Risk

Because of the contract changes we are making with Devon in conjunction with this offering, we bear almost no commodity price risk with respect to our future contractual arrangements.

 

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INDUSTRY OVERVIEW

General

We provide gathering, processing and transportation services to producers and users of natural gas and crude oil. The market we serve, which begins at the source of production and extends to the point of distribution to the end-user customer, is commonly referred to as the “midstream” market.

Midstream services are a critical part of the natural gas value chain, connecting the exploration and production of natural gas from the wellhead or lease and the delivery of the gas to end-use markets. Natural gas gathering and processing systems create value by collecting raw natural gas from the wellhead and separating dry gas (primarily methane) from NGLs such as ethane, propane, normal butane, isobutane and natural gasoline. A significant portion of natural gas produced at the wellhead contains NGLs. Natural gas produced in association with crude oil typically contains higher concentrations of NGLs than natural gas produced from gas wells. This “rich,” unprocessed, natural gas is generally not acceptable for transportation in the nation’s interstate transmission pipeline system or for commercial use. Processing facilities extract the NGLs, leaving residual dry gas that meets interstate transmission pipeline and commercial quality specifications. Midstream service providers then transport this residual dry gas to end-use markets. Extracted NGLs are sent to fractionators for separation into purity products to become marketable commodities and, on an energy equivalent basis, usually have a greater economic value as feedstock for petrochemicals and petroleum refiners than they would as a component of the natural gas stream.

The following diagram illustrates the groups of assets commonly found along the natural gas and NGL value chains:

 

 

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Refined petroleum products, such as jet fuel, gasoline and distillate fuel oil, are all sources of energy derived from crude oil. According to 2011 data compiled by the EIA, petroleum currently accounts for about 36% of the nation’s total annual energy consumption. The diagram below depicts the segments of the crude oil value chain:

 

Natural Gas Midstream Services

The range of services offered by natural gas midstream service providers are generally divided into the following categories:

Gathering. At the initial stages of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to individual wellheads in the production area. Natural gas gatherers may also install larger diameter pipelines to connection points, referred to as central receipt points, where producers and midstream operators can connect their wells or gathering infrastructure. These systems typically gather raw natural gas to central locations for processing and/or treating. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells and multiple central receipt points. Gathering systems are often designed to be highly flexible and scalable to allow gathering of natural gas at different pressures, to flow natural gas to multiple plants and to quickly connect new customers allowing for additional production without significant incremental capital expenditures. Midstream service providers generally charge a fixed fee to gather raw natural gas.

Compression. Wells produce at progressively lower field pressures as they deplete, and it becomes increasingly difficult to introduce the remaining reserves at these lower pressures against a higher pressure that exists in the connecting gathering system. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to flow into a higher pressure system. Compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure from the compressor to deliver natural gas into a higher pressure pipeline system. If compression is not installed, then the remaining natural gas will not be produced if it cannot overcome the higher gathering system pressure. With compression, however, a well can continue delivering natural gas that otherwise would not be produced. Consequently, gathering systems that operate at lower pressures or that can provide tiered compression service often have a competitive advantage over gathering systems that are limited to high-pressure transmission. Midstream service providers typically provide compression services in exchange for a fixed fee, a percentage of the applicable commodity or a combination of the two.

 

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Treating and Dehydration. Raw natural gas contains various contaminants, such as water vapor, carbon dioxide and hydrogen sulfide, that can render the gas unacceptable for transmission on intrastate and interstate pipelines. In addition, end users will not purchase natural gas with an unacceptable level of these contaminants. To meet downstream pipeline and end-user natural gas quality standards, natural gas is dehydrated to remove water vapor and is chemically treated to separate carbon dioxide and hydrogen sulfide from the gas stream to the extent required. Midstream service providers generally charge a fixed fee, and may also retain a percentage of the natural gas for use as fuel in the treating plant, to treat and dehydrate natural gas.

Processing. After the contaminants are removed, the next step involves the extraction of NGLs from the natural gas stream through a procedure known as processing. Most decontaminated natural gas with a significant NGL content is not suitable for long-haul pipeline transportation or commercial use and must be processed to extract the heavier hydrocarbon components in order to meet pipeline specifications. The separation of heavier hydrocarbons during processing is possible because of the differences in physical properties between the components of the raw gas stream. The three basic types of natural gas processing methods are cryogenic expansion, lean oil absorption and refrigeration, including hydrocarbon dewpoint refrigeration, or HCDP. Cryogenic expansion represents the latest generation of processing, incorporating extremely low temperatures and high pressures to provide the best processing and most economical extraction of NGLs.

Natural gas is processed not only to remove NGLs that would interfere with pipeline transportation or the end use of the residue natural gas, but also to separate from the natural gas those hydrocarbon liquids that could have a higher value as NGLs than as part of the natural gas stream. The principal components of residue natural gas are methane and ethane, but processors typically have the option to either recover ethane from the natural gas stream for processing into NGLs or reject a certain amount of ethane and leave it in the natural gas stream, depending on pipeline specifications and whether the ethane is more valuable as a separate commodity or left in the natural gas stream. The residue natural gas is sold to industrial, commercial and residential customers and electricity generators. The premium or discount in value between natural gas and separated NGLs is known as the “frac spread.” Because certain heavier NGLs often serve as substitutes for products derived from crude oil, these NGL prices tend to correlate with crude oil prices.

Natural gas processing occurs under a contractual arrangement between the producer or owner of the raw natural gas stream and the processor. There are many forms of processing contracts used in the industry, and specific commodity exposure to natural gas or NGL prices is highly dependent on the types of contracts entered into. Processing contracts can vary in length from one month to the “life of the lease.” Four typical processing contract types are described below:

 

•

Fee-Based. In a fee-based arrangement, the processor receives a fee per Mcf of natural gas processed or per gallon of NGLs produced. Under this arrangement, a processor has no direct commodity price exposure.

 

•

Percentage-of-Proceeds. In a percentage-of-proceeds arrangement, the processor receives a negotiated percentage of the natural gas and NGLs that it processes in the form of residue natural gas, NGLs, condensate and sulfur, which the processor can then sell at market prices and retain the proceeds as its compensation. This type of arrangement exposes the processor to commodity price risk, as the revenues from percentage-of-proceeds contracts directly correlate with the market prices of the applicable commodities that the processor receives.

 

•

Percentage-of-Liquids. In a percentage-of-liquids arrangement, the processor receives a negotiated percentage of the NGLs extracted from natural gas that requires processing, which the processor can then sell at market prices and retain the proceeds as its compensation. This contract structure is similar to percentage-of-proceeds arrangements except that the processor receives only a percentage of the NGLs produced. This type of contract may also require a processor to provide the customer with a guaranteed NGL recovery percentage regardless of actual NGL production. Since revenues from percentage-of-liquids contracts directly correlate with the market price of NGLs, this type of arrangement also exposes the processor to commodity price risk.

 

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•

Keep-Whole/Wellhead Purchase. In a keep-whole/wellhead purchase arrangement, the processor gathers or purchases raw natural gas from the customer. The processor extracts and retains the NGLs produced during processing for its own account, which it then sells at market prices. In instances when the processor purchases raw natural gas at the wellhead, the processor may also sell the resulting residue natural gas for its own account at market prices. In those instances when the processor gathers and processes raw natural gas for the customer’s account, the processor generally must return to the customer residue natural gas with an energy content equivalent to the original raw natural gas the processor received, as measured in Btus. This type of arrangement has the highest commodity price exposure for the processor because the costs are dependent on the price of natural gas and the revenues are dependent on the price of NGLs sold, so the processor is exposed both to NGL prices relative to natural gas and to absolute NGL prices. As a result, a processor with these types of contracts benefits when the value of the NGLs is high relative to the cost of the natural gas and is disadvantaged when the cost of the natural gas is high relative to the value of the NGLs.

Fractionation. Fractionation is the separation of the heterogeneous mixture of extracted NGLs, sometimes referred to as “o-grade,” “x-grade,” “y-grade” or “raw make” NGLs, into individual components for end-use sale. Fractionation is accomplished by controlling the temperature of the stream of mixed liquids in order to take advantage of the difference in boiling points of separate products. As the temperature of the stream is increased, the lightest component boils off the top of the distillation tower as a gas, where it then condenses into a purity liquid that is routed to storage. The heavier components in the mixture are routed to the next tower where the process is repeated until all components have been separated. A typical barrel of NGLs consists of ethane, propane, normal butane, isobutane and natural gasoline. Described below are the basic NGL components and their typical uses:

 

•

Ethane. Ethane is used primarily as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products.

 

•

Propane. Propane is used as heating fuel, engine fuel and industrial fuel, for agricultural burning and drying and as petrochemical feedstock for production of ethylene and propylene.

 

•

Normal Butane. Normal butane is principally used for motor gasoline blending and as fuel gas, either alone or in a mixture with propane, and feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber. Normal butane is also used to derive isobutane.

 

•

Isobutane. Isobutane is principally used by refiners to enhance the octane content of motor gasoline and in the production of MTBE, an additive in cleaner-burning motor gasoline.

 

•

Natural Gasoline. Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock.

Midstream service providers generally charge a per-gallon fee for fractionation services and then either return the resulting NGLs to customers or purchase the NGLs for resale.

Transportation and Storage. Once the raw natural gas has been treated or processed or the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. The natural gas industry and the NGL industry have hundreds of thousands of miles of intrastate and interstate transmission pipelines in addition to a network of barges, rails, trucks, terminals and storage to deliver raw NGLs or purity NGL products to market. The bulk of the NGL storage capacity is located near the refining and petrochemical complexes of the Texas and Louisiana Gulf Coasts, with a second major concentration in central Kansas. Each commodity system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily supply-demand shifts. There are two forms of contracts utilized in the transportation and storage of natural gas and NGLs:

 

•

Firm. Firm transportation service requires the reservation of pipeline capacity by a customer between certain receipt and delivery points. Firm customers generally pay a “demand” or “capacity reservation” fee based on the amount of capacity being reserved, regardless of whether the capacity is used, plus a

 

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usage fee based on the actual volumes of natural gas or NGLs transported. Firm storage contracts involve the reservation of a specific amount of storage capacity, including injection and withdrawal rights, and generally include a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee.

 

•

Interruptible. Interruptible service is typically short-term in nature and is generally used by customers that either do not need firm service or have been unable to contract for firm service. These customers pay only for the volume of natural gas or NGLs actually transported or stored. The obligation to provide this service is limited to available capacity not otherwise used by firm customers, and as such, customers receiving services under interruptible contracts are not assured capacity on the pipeline or at the storage facility.

Crude Oil Gathering and Transportation

Pipeline transportation is generally the lowest cost method for shipping crude oil and transports about two-thirds of the petroleum shipped in the United States. Crude oil pipelines transport oil from the wellhead to logistics hubs or refineries. Common carrier pipelines have published tariffs that are regulated by FERC or state authorities. Pipelines may also be proprietary or leased entirely to a single customer. Crude oil gathering assets generally consist of a network of smaller diameter pipelines that are connected directly to the well site or central receipt points delivering into larger diameter trunk lines. Logistic hubs like Cushing, OK provide storage and connections to other pipeline systems and modes of transportation, such as tankers, railroads and trucks. Trucking complements pipeline gathering systems by gathering crude oil from operators at remote wellhead locations not served by pipeline gathering systems. Trucking is generally limited to low volume, short haul movements because trucking costs escalate sharply with distance, making trucking the most expensive mode of crude oil transportation.

Barges and railroads provide additional transportation capabilities for shipping crude oil between gathering storage systems, pipelines, terminals and storage centers and end-users. Barge transportation is typically a cost-efficient mode of transportation that allows for the ability to transport large volumes of crude oil over long distances.

Competition in the crude oil gathering industry is typically regional and based on proximity to crude oil producers, as well as access to attractive delivery points. Overall demand for gathering services in a particular area is generally driven by crude oil producer activity in the area.

U.S. Natural Gas Market Fundamentals

Natural Gas Supply and Demand

As indicated in the chart shown below, U.S. natural gas production and overall U.S. energy demand are expected to grow in the coming decades. Population is a large determinant of energy consumption through its influence on demand for travel, housing, consumer goods and services. According to the U.S. Energy Information Administration, or EIA, energy use is projected to grow by approximately 10% from 2011 to 2040. Energy use per capita is expected to decline by approximately 15% while the total U.S. population is expected to increase by an estimated 29% from 2011 to 2040. Over the course of the next five years, energy use is expected to increase approximately 3%. A discussion of other supply and demand elements follows.

Natural gas is a key component of energy consumption within the United States. According to the EIA, annual consumption of natural gas in the United States increased from approximately 24.3 quadrillion Btu in 2010 to approximately 24.8 quadrillion Btu in 2011. According to the EIA, natural gas consumption represented approximately 20% of total energy consumption in 2011, and the EIA projects that this percentage will increase to approximately 27% by 2040. The charts shown below illustrate energy consumption by fuel source in 2011 and expected energy consumption by fuel source in 2040.

 

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The EIA expects that the growth of natural gas consumption relative to other fuel sources will be primarily driven by the use of natural gas for electricity generation. According to the EIA, demand for natural gas in the electric power sector is projected to increase from approximately 7.6 Tcf in 2011 to approximately 9.5 Tcf in 2040, with a portion of the growth attributable to the retirement of 49 gigawatts of coal-fired capacity by 2022. The EIA also projects that natural gas consumption in the industrial sector will be higher due to the rejuvenation of the industrial sector as it benefits from increasing shale gas production that is accompanied by slow price growth, particularly from 2011 through 2019, when the price of natural gas is expected to remain below 2010 levels. However, the EIA expects growth in natural gas consumption for power generation and in the industrial sector is to be partially offset by decreased usage in the residential sector related primarily to decreased demand for natural gas powered home heating.

U.S. Primary Energy Consumption by Fuel, 1980—2040

 

Source: EIA, Annual Energy Outlook 2013 (January 2013).

In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of natural gas must continue to be developed to support consumption rates. Over the past several years, there has been a fundamental shift in U.S. natural gas production towards unconventional resources, defined by the EIA as natural gas produced from shale formations and coal beds. The emergence of unconventional natural gas plays and advancements in technology have been crucial factors that have allowed producers to efficiently extract significant volumes of natural gas from these plays. According to the EIA, the dual application of horizontal drilling and hydraulic fracturing has been the primary driver of increases in shale gas production. As indicated by the diagram below, the development of these unconventional sources has offset declines in other, more traditional U.S. natural gas supply sources, which has helped meet growing consumption and lowered the need for imported natural gas. In fact, the EIA predicts that the U.S. will become a net exporter of natural gas starting in 2020. The recent developments in the LNG sector have bolstered the prospects for the export potential of domestic natural gas. Since 2011, the Department of Energy has granted several companies building LNG export facilities in the U.S. licenses for the export of LNG to Free Trade Agreement, or FTA, countries and in certain cases non-FTA countries. Several projects are currently underway with off-take commitments from international companies seeking to secure the supply of natural gas.

As indicated by EIA forecasts shown in the diagram below, as the depletion of conventional onshore and offshore resources continues, natural gas from unconventional resource plays is forecasted to fill the disparity and continue to gain market share from higher-cost sources of natural gas. In fact, the EIA estimates that natural gas production from the major shale formations will provide the majority of the growth in domestically-produced

 

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natural gas supply in coming years, increasing to approximately 50% in 2040 as compared with 34% in 2011. According to the EIA, shale gas will be the largest contributor to natural gas production growth, while production from tight sands, coalbed methane deposits and offshore waters is expected to remain stable.

U.S. Dry Natural Gas Production by Source, 1990 —2040

 

Source: EIA, Annual Energy Outlook 2013 (January 2013).

Recently, the price of natural gas has rebounded from historically low levels, with prompt month NYMEX natural gas futures prices reaching $3.57 per MMBtu as of June 30, 2013, compared to a spot price low of $1.82 per MMBtu in April 2012 and a high of $13.31 per MMBtu in July 2008. Additionally, the current range of forward month NYMEX natural gas futures through December 2017 is $3.56 and $4.88 per MMBtu. This compares to an average of $3.28 per MMBtu in 2012. The recent recovery in prices is the result of a moderation in natural gas drilling and increased demand, as well as an extended winter that has resulted in less natural gas in storage than the five-year average.

NGL Supply and Demand

A majority of the U.S. NGL supply comes from natural gas processing facilities. The majority of natural gas processing facilities in the U.S. are located along the U.S. Gulf Coast and in the Mid-Continent, Marcellus and Rockies regions. Smaller gas processing regions are located in Michigan and Illinois, as well as Southern California. In Canada, the majority of the processing capacity is located in Alberta, with a smaller amount in British Columbia.

NGL products from refineries are by-products of refinery processes. As a result, they have generally already been separated into individual components and do not require further fractionation. NGL products from refineries are principally propane, with lesser amounts of butane, refinery naphthas (products similar to natural gasoline) and ethane. Due to refinery maintenance schedules and seasonal demand considerations, refinery production of propane and butane varies on a seasonal basis. NGLs are also imported into certain regions of the United States from Canada and other parts of the world. NGLs (primarily propane) are also exported from certain regions of the United States.

 

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NGL supplies from natural gas processing facilities are increasing rapidly due to the increased drilling activity in unconventional resource plays, where producers are targeting liquids-rich areas to capitalize on forecasted high relative NGL product prices. The EIA projects NGL supply volumes will continue to grow over 40% in the next decade from 2.2 MMBbls/d in 2011 to 3.1 MMBbls/d by 2020. A significant amount of this volume is expected to come from recently discovered unconventional resource plays, which do not typically have the NGL infrastructure to process the liquids-rich natural gas or transport, fractionate, and store the NGL products. As a result of these dynamics, substantial incremental infrastructure is likely to be developed throughout the NGL value chain over the next several years, and traditional regional basis relationships could change significantly. A portion of the increased supply of NGLs will likely be absorbed by the domestic petrochemical sector as feedstocks. In addition, growing production of Canadian heavy crude oil is likely to create demand for additional diluents, primarily natural gasoline and butane.

The remaining product not absorbed domestically will likely drive continued growth in the NGL export market. Due to rapid increases in NGL production, the prices of NGLs (particularly ethane and propane) have experienced downward pressure. The expectation of additional NGL supply is one of the key drivers for new NGL consumption and infrastructure development such as chemical plants, propane dehydrogenation facilities and export markets.

Key Basins in Which We Operate

Fort Worth Basin

The Fort Worth basin is a mature hydrocarbon basin covering more than ten counties in North Texas extending into Southern Oklahoma. Production began with the exploitation of Bend Conglomerate and Strawn Sandstone reservoirs in the early 1900s. Today, the Fort Worth basin is mainly known as the location of the Barnett Shale, which covers approximately 3,400 square miles and was the first resource play to exploit blanket horizontal drilling in an area previously thought to be unproductive.

Barnett Shale. The Barnett Shale is one of the largest and most mature natural gas fields in North America. Located primarily in the Fort Worth basin of North Texas, the “core” region of the Barnett Shale has produced a total of 9.1 Tcf of natural gas since 1981, according to Wood Mackenzie, an energy research and consulting firm. The Barnett Shale underlies the Pennsylvanian Marble Falls formation and overlies the water-bearing Ordovician Ellenberger formation. It was not until the 1980s with new advances in horizontal drilling and well fracturing technology used by Mitchell Energy, a small independent exploration and production company that was acquired by Devon in 2002, that the potential of the Barnett Shale was realized. Significant drilling activity did not begin until the late 1990s due to technological advancements in recovery techniques. Although primarily a natural gas field, the Barnett Shale also includes oil, condensate and NGLs.

The Barnett Shale has been classified into “core” and “non-core” areas of production. To date, production is concentrated in the core area, where the shale is thicker and recovery uncertainty is reduced. According to Wood Mackenzie, operators believe the Barnett Shale provides low risk drilling opportunities due to the maturity of the play. Recent activity has been focused on developing the liquids-rich area of the play, with additional upside potential believed to exist in the southwest portion of the Barnett Shale in higher gas price environments.

Anadarko Basin

The Anadarko basin is a large natural gas-producing basin, spanning from western Oklahoma to the northeast portion of the Texas Panhandle. The basin is approximately 56,000 square miles with about 53,000 producing wells as of December 2012, according to Wood Mackenzie. Although mature and long-lived, the Anadarko Basin has recently been the focus of increased exploration activity. Oil development in the Anadarko basin has been cyclical, with early activity in the late 1990s and early 2000s focusing on oil exploitation and gas production. In addition, the basin benefits from established infrastructure, favorable fiscal terms and a supportive

 

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regulatory environment. Wood Mackenzie reports that, since 2009, operators have been exploring the basin’s rich natural gas fields and older, conventional oil fields with horizontal laterals and enhanced technology, vastly improving recoveries and opening up previously uneconomic plays.

Cana-Woodford Shale. The Cana-Woodford Shale (also referred to as the Anadarko Woodford) is a Late Devonian-aged shale formation found at depths ranging from 8,000 to 16,000 feet. It is a much deeper extension of the Woodford Shale found in the Arkoma Basin and produces liquids-rich natural gas. Canadian County, Oklahoma is the core of the Cana-Woodford play, but since its discovery, operators have extended beyond the play’s main Cana field along a northwest/southeast trend searching for pockets of rich natural gas. Wood Mackenzie reports current production of approximately 190 MBoe per day with about 735 horizontal producing wells in the play.

Arkoma Basin

The Arkoma Basin is home to the Fayetteville Shale, Woodford Shale, and Desmoinesian coalbed methane plays and holds some of the largest natural gas-producing fields in the US. The basin covers approximately 13,000 square miles across Oklahoma and Arkansas and has over 12,000 producing wells across its various plays, according to Wood Mackenzie. The firm reported natural gas production for the Arkoma Basin as approximately 4,000 MMcf/d in 2012 and estimated 2013 production to be approximately 3,900 MMcf/d.

Arkoma-Woodford Shale. The Arkoma-Woodford Shale is an Upper Devonian-aged shale formation found in Hughes, Coal, Pittsburg, and Atoka counties in Oklahoma. Depths range from 6,000 to 12,000 feet, and its thickness varies from 120 to 220 feet. The shale tends to create its own natural fractures, which facilitate gas movement. Initially developed with vertical wells, horizontal drilling is now predominant in the play. According to Wood Mackenzie, gas-in-place for the Arkoma-Woodford Shale is estimated to be 40 to 120 Bcf per square mile.

 

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BUSINESS

Overview

The Partnership

We are a limited partnership recently formed by Devon to own, operate, develop and acquire midstream assets in North America. We gather, process and transport natural gas, primarily for Devon, pursuant to long-term contracts that include fee-based rates, annual rate escalators and primary terms of 10 years. We also fractionate NGLs into component NGL products. Under our gathering and processing agreements, we do not have direct exposure to natural gas and NGL prices because we do not take title to the natural gas that we gather, process and transport or the NGLs that we fractionate. Our midstream assets are integral to the success of Devon’s oil and natural gas exploration and production operations, and Devon intends for us to be the primary growth vehicle for its midstream operations in North America.

Our initial asset is a 20% interest in Devon Midstream Holdings, over which we have operating control and which owns substantially all of Devon’s U.S. midstream assets, consisting of natural gas gathering and transportation systems, natural gas processing facilities and NGL fractionation facilities located in Texas and Oklahoma. Our general partner is responsible for managing our operations. As of the date of this offering, Devon will own an 80% interest in Devon Midstream Holdings. We expect to acquire this 80% interest in Devon Midstream Holdings over time pursuant to our right of first offer.

Devon Midstream Holdings’ primary assets consist of three processing facilities with 1.3 Bcf/d of natural gas processing capacity, approximately 3,660 miles of pipelines with aggregate capacity of 2.9 Bcf/d and fractionation facilities with up to 160 MBbls/d of aggregate NGL fractionation capacity. These assets include the following systems and facilities.

 

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Barnett assets—Devon Midstream Holdings will own the following midstream assets in the Barnett Shale, where Devon is currently the largest natural gas and NGL producer:

 

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Bridgeport processing facility—This natural gas processing facility is one of the largest processing plants in the U.S. with 790 MMcf/d of processing capacity, 63 MBbls/d of NGL production capacity and 15 MBbls/d of NGL fractionation capacity.

 

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Bridgeport rich gathering system—This rich natural gas gathering system consists of approximately 2,420 miles of low- and intermediate-pressure pipeline segments with approximately 145,000 horsepower of compression.

 

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Bridgeport lean gathering system—This lean natural gas gathering system consists of approximately 300 miles of low-, intermediate- and high-pressure pipeline segments with approximately 59,000 horsepower of compression.

 

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Acacia transmission system—This transmission system consists of approximately 120 miles of pipeline, associated storage and approximately 17,000 horsepower of compression and interconnects the tailgate of the Bridgeport processing facility and the Bridgeport lean gathering system to intrastate pipelines as well as two local power plants.

 

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East Johnson County gathering system—This natural gas gathering system consists of approximately 270 miles of low-, intermediate- and high-pressure pipeline segments with approximately 41,000 horsepower of compression.

 

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Cana system—Devon is currently the largest natural gas producer and one of the largest NGL producers in the Cana-Woodford Shale in West Central Oklahoma. This natural gas gathering and processing system consists of a 350 MMcf/d processing facility, 30 MBbls/d of NGL production capacity and approximately 410 miles of associated low-, intermediate- and high-pressure pipeline segments with approximately 92,500 horsepower of compression.

 

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Northridge system—This natural gas gathering and processing system is located in the Arkoma-Woodford Shale in Southeastern Oklahoma and consists of a 200 MMcf/d processing facility, 17 MBbls/d of NGL production capacity and approximately 140 miles of associated low-, intermediate- and high-pressure pipeline segments with approximately 18,000 horsepower of compression.

 

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Gulf Coast Fractionators—Devon Midstream Holdings will own a 38.75% non-operating equity interest in Gulf Coast Fractionators, an NGL fractionator located on the Texas Gulf Coast at the Mont Belvieu hub. This facility has a capacity of approximately 120 MBbls/d to 145 MBbls/d depending on the composition of the inlet NGL stream.

For the six months ended June 30, 2013, approximately 95% of the natural gas gathered and 91% of the natural gas processed by Devon Midstream Holdings was from Devon’s natural gas production. The following table sets forth our pro forma net income and Adjusted EBITDA and Devon Midstream Holdings’ pro forma Adjusted EBITDA for the periods indicated.

 

		Six months ended June 30, 2013				Year ended December 31, 2012
		(in millions)
Pro forma net income		$	21.9			$	46.4
Pro forma Adjusted EBITDA attributable to Devon Midstream Holdings (100%)		$	202.8			$	397.8
Pro forma Adjusted EBITDA attributable to us (20%)		$	40.6			$	79.6

Please read “Summary—Non-GAAP Financial Measure” for our definition of Adjusted EBITDA and our reconciliation thereof to its most directly comparable financial measures calculated and presented in accordance with U.S. GAAP.

About Devon

Devon (NYSE: DVN) is a leading independent energy company engaged primarily in the exploration, development and production of crude oil, natural gas and NGLs. Devon’s operations are concentrated in various onshore areas in the U.S. and Canada. As of September 1, 2013, Devon had a total equity market capitalization of over $23 billion and an investment grade credit rating.

Devon will dedicate approximately 795,000 net acres to Devon Midstream Holdings pursuant to various gathering and processing agreements. Please read “—Our Contractual Relationship with Devon.” Devon had approximately 2.2 BBoe of proved reserves in the U.S. as of December 31, 2012, of which approximately 1.3 BBoe, or 59%, was associated with this dedicated acreage. For the six months ended June 30, 2013, Devon’s average U.S. production was 511 MBoe/d, with approximately 240 MBoe/d, or 46%, associated with this dedicated acreage.

Devon is the largest natural gas producer in the Barnett and Cana-Woodford Shales, the largest NGL producer in the Barnett Shale and one of the largest NGL producers in the Cana-Woodford Shale. In 2012, Devon drilled 322 gross wells in the Barnett Shale with exploration and production capital expenditures of $920 million and drilled 164 gross wells in the Cana-Woodford Shale with exploration and production capital expenditures of approximately $900 million. As of December 31, 2012, Devon held 620,000 net acres in the Barnett Shale, 260,000 net acres in the Cana-Woodford Shale and 60,000 net acres in the Arkoma-Woodford Shale. Devon has drilled over 5,000 gross wells in the Barnett Shale since 2002 and in 2013 expects to drill approximately 150 gross wells with budgeted exploration and production capital expenditures of approximately $500 million. In the Cana-Woodford Shale, Devon has drilled more than 600 gross wells to date and in 2013 expects to drill approximately 150 gross wells with budgeted exploration and production capital expenditures of approximately $550 million. In addition to its current drilling schedule, Devon has identified thousands of additional drilling locations in each of these areas.

 

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Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. We expect to achieve this objective through the following business strategies:

Acquire additional interests in Devon Midstream Holdings. We expect to acquire Devon’s 80% retained interest in Devon Midstream Holdings over time and have a right of first offer with respect to acquiring that interest from Devon. As we continue to acquire interests in Devon Midstream Holdings, we expect to grow our distributable cash flow per unit. We believe that our economic relationship with Devon incentivizes it to offer us its retained interest in Devon Midstream Holdings, although Devon is under no obligation to do so.

Seek accretive acquisitions of other Devon midstream assets. We expect to have the opportunity to acquire other midstream assets that will be retained by Devon following this offering as well as midstream assets Devon develops or acquires in the future. While we believe Devon has a financial incentive to offer us such assets, we do not have the ability to control whether, or the timing and terms under which, such assets may be offered to us.

Grow organically in support of Devon’s upstream portfolio development. As Devon develops the approximately 795,000 net acres dedicated to Devon Midstream Holdings’ systems, we expect our gathering, processing and transportation volumes to grow. For example, Devon expects to drill 150 gross wells in each of the Barnett and Cana-Woodford Shales in 2013, with total capital expenditures of over $1 billion. Substantially all volumes resulting from Devon’s 2013 capital program in these areas are dedicated to Devon Midstream Holdings, and Devon Midstream Holdings will benefit from Devon’s continued development of these areas, through its long-term acreage dedications and fee-based contracts with Devon. We also expect to target economically attractive organic growth and greenfield construction opportunities in areas where Devon has significant undeveloped acreage that is not currently dedicated to any midstream system and that may require additional midstream infrastructure. In addition, Devon is economically incentivized to provide us opportunities to support its exploration and production operations in new geographic areas it develops or acquires from third parties. Devon is under no obligation, however, to develop the acreage dedicated to us or dedicate any additional acreage to us.

Grow through third-party acquisitions and third-party volumes. We intend to pursue accretive acquisitions of assets from third parties that complement or diversify our existing operations. Additionally, our operations are located in attractive North American onshore areas, and we intend to leverage our extensive expertise to attract third-party volumes in these areas.

Maximize value through long-term fixed-fee contracts and minimum volume commitments from Devon. Devon Midstream Holdings will enter into 10-year fixed-fee contracts with annual rate escalators covering all of Devon Midstream Holdings’ gathering and processing facilities. Additionally, in order to minimize volumetric exposure, these contracts will include five-year minimum volume commitments at the Bridgeport processing facility, Bridgeport and East Johnson County gathering systems and Cana and Northridge systems. These minimum volume commitments represent 88% of the total projected volumes for these assets for the twelve months ending September 30, 2014.

 

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Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

Significant relationship with Devon. Our relationship with Devon provides us with access to Devon’s extensive operational and commercial expertise, which we believe will facilitate the execution of our business strategies and allow us to grow the quarterly distributions we pay to our unitholders over time. Devon indirectly owns our general partner, a majority of our limited partner interests and all of our incentive distributions rights, as well as an 80% retained interest in Devon Midstream Holdings. As a result of these ownership interests, we believe Devon is incentivized to promote and support our business plan and to pursue projects that enhance the overall value of our business.

 

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Retained limited partner interest and incentive distribution rights in us, and the right of first offer on interests in Devon Midstream Holdings—Because of its relatively higher participation in any increases to our cash distributions through the incentive distribution rights as well as its     % limited partner interest in us, Devon is positioned to directly benefit from our acquisition, pursuant to our right of first offer, of additional interests in Devon Midstream Holdings, growth of the volumes on Devon Midstream Holdings’ systems from both Devon and third parties and our accretive acquisition of other midstream assets from Devon and third parties.

 

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Long-term natural gas gathering and processing contracts—Devon Midstream Holdings will enter into 10-year gathering and processing agreements with Devon pursuant to which Devon has agreed to provide Devon Midstream Holdings with acreage dedications within the Barnett, Cana-Woodford and Arkoma-Woodford Shales. These agreements also include five-year minimum volume commitments and annual rate escalators. Please read “—Our Contractual Relationship with Devon.”

 

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Substantial portfolio of other retained midstream assets—Devon has significant midstream assets in Canada, including a 50% ownership interest in Access Pipeline that supports current and future production growth at Devon’s Jackfish and Pike heavy oil projects, as well as projects from other large producers in the Canadian oil sands. Access Pipeline is currently undergoing a pipeline loop expansion that will increase its capacity to approximately 700 MBbls/d by the end of 2014. Additionally, Devon will retain a number of other midstream assets in the U.S.

Strategically-located midstream assets. Devon Midstream Holdings will own substantially all of Devon’s U.S. midstream asset portfolio, which is primarily located in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. All of Devon Midstream Holdings’ assets have access to major natural gas and liquids markets through connections to interstate and intrastate pipelines. Furthermore, Devon Midstream Holdings’ areas of operation are proximate to well-developed natural gas and liquids midstream infrastructure and oilfield services providers, which we believe reduces the risk of production delays and facilitates adequate takeaway capacity.

Financial flexibility to pursue growth opportunities. Upon consummation of this offering, we will enter into a $         million revolving credit facility that will be undrawn at the closing of this offering. This facility, combined with our expected ability to access the capital markets, should enable us to fund future accretive acquisitions from Devon and third parties and pursue other growth opportunities.

Experienced management team with a history of safe and reliable operations. Our management team responsible for the day-to-day operations of Devon Midstream Holdings’ assets has an average of 20 years of experience in the oil and natural gas industry and a proven record of enhancing value through the development and operation of midstream assets. We believe this team provides us with a strong foundation for evaluating growth opportunities and maintaining the integrity and efficiency of Devon Midstream Holdings’ assets and operations. Devon Midstream Holdings’ assets maintained operational availability of over 98% for the last three years. We are committed to continuing the safe, reliable and efficient operation of Devon Midstream Holdings’ assets.

 

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Our Contractual Relationship with Devon

Upon the closing of this offering, Devon Midstream Holdings will enter into a 10-year transportation contract with Devon for the Acacia transmission system as well as the following additional fee-based agreements with Devon:

 

Contract		Contract Term (Years)				Minimum Gathering Volume Commitment (MMcf/d)				Minimum Processing Volume Commitment (MMcf/d)				Minimum Volume Commitment Term (Years)				Annual Rate Escalators
Bridgeport gathering and processing contract (1)			10				850				650				5				CPI
East Johnson County gathering contract			10				125				—				5				CPI
Northridge gathering and processing contract			10				40				40				5				CPI
Cana gathering and processing contract			10				330				330				5				CPI

 

(1)	The Bridgeport gathering and processing contract includes volume commitments to the Bridgeport processing facility, as well as the Bridgeport gathering systems.

While our relationship with Devon will provide us with significant benefits, it may also potentially give rise to conflicts. For example, Devon is not restricted from competing with us. In addition, we and our general partner will not have employees but instead will rely on employees of Devon. The executive officers and certain of the directors of our general partner also serve as officers of Devon, and these officers and directors face conflicts of interest, including conflicts regarding the allocation of their time between us and Devon. Please read “Conflicts of Interest and Fiduciary Duties.”

Devon Midstream Holdings’ Assets

Devon Midstream Holdings’ assets include natural gas gathering, processing and transmission systems as well as NGL fractionation facilities. Devon Midstream Holdings gathers natural gas from the wellhead and central receipt points on its systems, delivers it to Devon Midstream Holdings’ facilities for processing and delivers the residue natural gas to intrastate or interstate pipelines, including Devon Midstream Holdings’ Acacia transmission system, for transmission to downstream markets and wholesale customers such as power plants, industrial customers and local distribution companies. Most raw mix NGLs produced from Devon Midstream Holdings’ Bridgeport facility are shipped though interstate pipelines to Gulf Coast Fractionators for fractionation, with minimal volumes sold locally.

Devon Midstream Holdings’ gathering and transmission network consists of approximately 3,660 miles of pipelines that, in aggregate, collects wellhead natural gas from approximately 5,705 receipt points. Devon Midstream Holdings’ gathering systems all include compression, allowing each system to operate at lower pressures and provide sufficient discharge pressure from the compressor to deliver natural gas into higher pressure pipeline systems.

 

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Devon Midstream Holdings’ gathering, processing and transmission assets consist of its Barnett assets and Cana and Northridge systems shown on the following map:

 

The following table provides information relating to the primary gathering systems of Devon Midstream Holdings:

 

Gathering and Transmission Pipelines		Approximate Length (Miles)				Approximate Receipt Points				Compression								Six Months Ended June 30, 2013
										(Units)				(HP)				Estimated Capacity (MMcf/d)				Average Throughput (Thousands of MMBtu/d)				Devon Volume %
Barnett Assets:
Bridgeport rich			2,420				3,800				87				144,959				800				860.1	(1)			92
Bridgeport lean			300				910				23				58,782				350				269.3				98
Acacia			120				5				7				16,622				920				753.7				100
East Johnson County			270				550				18				40,903				260				242.8				93
Cana			410				280				21				92,499				530				310.1				100
Northridge			140				160				7				17,895				75				72.3				100
Total			3,660				5,705				163				371,660				2,935				2,508.3				95	(2)

 

(1)	Natural gas gathered by the Bridgeport rich gathering system contains approximately 1.1 to 1.2 Btu per cubic foot before processing.

(2)	Represents a weighted average of the percent of throughput attributable to Devon.

 

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The following table provides information relating to Devon Midstream Holdings’ processing and fractionation facilities.

 

Processing and Fractionation Facilities		Processing Capacity (MMcf/d)				Estimated NGL Production Capacity (MBbls/d)				Estimated NGL Fractionation Capacity (MBbls/d)				Six Months Ended June 30, 2013
														Average Inlet (MMcf/d)				Devon Volume %
Bridgeport			790				63				15				684				92
Cana			350				30				0				229				100
Northridge			200				17				0				111				55
Gulf Coast Fractionators (1)			N/A				N/A				120 to 145				120	(2)			65
Total			1,340				110				135 to 160				1,024	(3)			91	(4)

 

(1)	Devon Midstream Holdings owns a 38.75% non-operating equity interest in Gulf Coast Fractionators.

(2)	Average inlet for Gulf Coast Fractionators is in MBbls/d.

(3)	Excludes Gulf Coast Fractionators.

(4)	Excludes Gulf Coast Fractionators and represents a weighted average of the percent of volumes attributable to Devon.

Barnett Assets

The Barnett assets consist of a processing facility, a transmission system, one rich gathering system and two lean gathering systems. For the six months ended June 30, 2013, the Barnett assets gathered and transported an average of 2.1 million MMBtu/d and processed natural gas resulting in 0.6 million MMBtu/d of residue natural gas and 55 MBbls/d of raw mix NGLs. The Barnett assets include:

 

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Bridgeport processing facility—This natural gas processing facility is one of the largest processing plants in the U.S. with 790 MMcf/d of processing capacity, 63 MBbls/d of NGL production capacity and 15 MBbls/d of NGL fractionation capacity.

 

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Bridgeport rich gathering system—This rich natural gas gathering system consists of approximately 2,420 miles of low- and intermediate-pressure pipeline segments with approximately 145,000 horsepower of compression. A substantial majority of the natural gas gathered on the system is delivered to the Bridgeport processing facility.

 

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Bridgeport lean gathering system—This lean natural gas gathering system consists of approximately 300 miles of low-, intermediate- and high-pressure pipeline segments with approximately 59,000 horsepower of compression. Natural gas gathered on this system is delivered to the Acacia transmission system and intrastate pipelines without processing.

 

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Acacia transmission system—This transmission system consists of approximately 120 miles of pipeline, associated storage and approximately 17,000 horsepower of compression and interconnects the tailgate of the Bridgeport processing facility and the Bridgeport lean gathering system to intrastate pipelines as well as two local power plants.

 

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East Johnson County gathering system—This natural gas gathering system consists of approximately 270 miles of low-, intermediate- and high-pressure pipeline segments with approximately 41,000 horsepower of compression. Natural gas gathered on this system is delivered to intrastate pipelines without processing.

 

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The following map identifies the locations of the principal assets comprising Devon Midstream Holdings’ Barnett assets:

 

Bridgeport processing facility

The Bridgeport natural gas processing facility, which Devon acquired in 2002, is located in Wise County, Texas, approximately 40 miles northwest of Fort Worth, Texas and has been expanded several times as a result of growth in Barnett Shale natural gas production. In addition to gas processing, the Bridgeport processing facility complex includes units that process and upgrade condensate, fractionate NGLs and serve local and regional NGL markets via truck and rail service. Since 2002, Devon has invested in additional upgrades and expansions at the Bridgeport processing facility that have increased processing capacity by approximately 140 MMcf/d of natural gas and 9 MBbls/d of NGLs.

The Bridgeport processing facility presently consists of seven cryogenic turboexpander plants that have an aggregate throughput design capacity of 790 MMcf/d of natural gas. For the six months ended June 30, 2013, inlet volumes averaged 684 MMcf/d of natural gas resulting in 55 MBbls/d of raw mix NGLs produced, together with 637,200 MMBtu/d of residue natural gas. For the year ended December 31, 2012, inlet volumes averaged 649 MMcf/d of natural gas resulting in 49 MBbls/d of raw mix NGLs produced, together with 613,100 MMBtu/d of residue natural gas.

The Bridgeport processing facility is designed to recover raw mix NGLs including ethane, propane, isobutane, normal butane and natural gasoline from the inlet natural gas stream. The processing facility also has the ability to “reject ethane” by not recovering ethane from the natural gas inlet stream but instead leaving it in the residue natural gas stream. Ethane rejection may occur when the value of ethane is greater as a component of the residue natural gas stream than as a purity liquid product. This ability to either recover or reject ethane allows Devon and other customers to sell ethane in its most valuable state depending on market conditions. A portion of the NGL stream is fractionated through an associated 15 MBbls/d fractionator that extracts NGL purity products

 

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from the raw NGL mix. The processing facility’s fractionation capability allows Devon to maximize the value of its NGL production at Bridgeport by having the ability to sell propane, butanes and natural gasoline to local area markets via truck or rail loading facilities located at the processing facility.

Customers. Devon is the largest customer of the Bridgeport processing facility with approximately 629 MMcf/d and 592 MMcf/d of natural gas processed for the six months ended June 30, 2013 and the year ended December 31, 2012 respectively, which represented approximately 92% and 91% of the total volumes processed at the facility during such periods, respectively.

Contracts. Devon and Devon Midstream Holdings will enter into a 10-year, fixed-fee gathering and processing agreement that will cover gathering services on the Bridgeport rich and Bridgeport lean gathering systems and processing services at the Bridgeport processing facility. This contractual arrangement will include a five-year minimum volume commitment from Devon of 650 MMcf/d of natural gas delivered to the processing facility as well as annual rate escalators.

Delivery Points. The Bridgeport processing facility delivers its residue natural gas to the Acacia transmission system. The majority of raw mix NGLs produced from Bridgeport facility are delivered via Chevron Pipe Line Company’s West Texas LPG pipeline and ONEOK Partners’ Arbuckle NGL pipeline to Gulf Coast Fractionators for fractionation, while some NGLs are fractionated at the plant and sold locally.

Bridgeport rich gathering system

The Bridgeport rich gathering system is comprised of a network of pipelines, compressors and related equipment that collects raw natural gas from producers within a five-county area in the Barnett Shale that includes Jack, Wise, Denton, Parker and Tarrant counties. The Bridgeport rich gathering system presently consists of approximately 2,420 miles of low- and intermediate-pressure pipeline segments with approximately 145,000 horsepower of compression. The rich gathering system isolates liquids-rich natural gas for processing and NGL recovery. As of June 30, 2013, approximately 3,800 natural gas meters were connected to this system. For the six months ended June 30, 2013 and the year ended December 31, 2012, the Bridgeport rich gathering system gathered approximately 860,100 MMBtu/d and 818,400 MMBtu/d of natural gas, respectively.

Customers. Devon is the largest customer on the Bridgeport rich gathering system with approximately 791,000 MMBtu/d and 745,200 MMBtu/d of natural gas gathered for the six months ended June 30, 2013 and the year ended December 31, 2012 respectively, which represented approximately 92% and 91% of the total throughput on the system during such periods, respectively.

Contracts. Devon and Devon Midstream Holdings will enter into a 10-year, fixed-fee gathering and processing agreement that will cover gathering services on the Bridgeport rich and Bridgeport lean gathering systems and processing services at the Bridgeport processing facility. This contractual arrangement will include a five-year minimum volume commitment of a combined 850 MMcf/d of natural gas delivered for gathering into the Bridgeport rich and Bridgeport lean gathering systems as well as annual rate escalators.

Delivery Points. The substantial majority of the natural gas in the system is delivered to the Bridgeport processing facility for processing with limited volumes being delivered to Crosstex, Enbridge Energy Partners and Targa Resources Partners processing facilities. The residue natural gas from the Bridgeport processing facility is connected to the Natural Gas Pipeline of America, the Brazos Electric power plant and the Acacia transmission system. NGL production is delivered to Gulf Coast Fractionators for fractionation through Chevron Pipe Line Company’s West Texas LPG pipeline and ONEOK Partners’ Arbuckle NGL pipeline, both of which are connected to the outlet of the Bridgeport processing facility. NGLs can also be trucked and loaded onto railcars at the Bridgeport processing facility.

 

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Bridgeport lean gathering system

The Bridgeport lean gathering system is comprised of a network of pipelines, compressors and related equipment that collects raw natural gas from producers within a three-county area in the Barnett Shale that includes Wise, Denton and Tarrant counties.

The Bridgeport lean gathering system presently consists of approximately 300 miles of low-, intermediate- and high-pressure pipeline segments with approximately 59,000 horsepower of compression. As of June 30, 2013, there were approximately 910 natural gas meters connected to this system. Gas gathered on this system is not processed. For the six months ended June 30, 2013 and the year ended December 31, 2012, the Bridgeport lean gathering system gathered approximately 269,300 MMBtu/d and 298,000 MMBtu/d of natural gas, respectively.

Customers. Devon is the largest customer on the Bridgeport lean gathering system with approximately 263,900 MMBtu/d and 290,800 MMBtu/d of natural gas gathered for the six months ended June 30, 2013 and the year ended December 31, 2012, respectively, which represented approximately 98% of the total throughput on the system during both periods.

Contracts. Devon and Devon Midstream Holdings will enter into a 10-year, fixed-fee gathering and processing agreement that will cover gathering services on the Bridgeport rich and Bridgeport lean gathering systems and processing services at the Bridgeport processing facility. This contractual arrangement will include a five-year minimum volume commitment of a combined 850 MMcf/d of natural gas delivered for gathering into the Bridgeport rich and Bridgeport lean gathering systems as well as annual rate escalators.

Delivery Points. The Bridgeport lean system delivers natural gas to the Acacia transmission system, Atmos Energy, Crosstex and Enterprise Product Partners.

Acacia transmission system

The Acacia transmission system connects the Bridgeport processing facility tailgate and the Bridgeport lean gathering system to intrastate pipelines in North Texas and two local power plants. The system is comprised of a network of pipelines, associated storage and related equipment that collects natural gas from the Bridgeport processing facility and Bridgeport lean gathering system and consists of approximately 120 miles of pipeline with approximately 17,000 horsepower of compression. For the six months ended June 30, 2013 and the year ended December 31, 2012, the Acacia transmission system gathered approximately 753,700 MMBtu/d and 732,700 MMBtu/d of natural gas, respectively.

Customers. Devon is the only customer on the Acacia transmission system.

Contracts. Devon and Devon Midstream Holdings will enter into a 10-year transportation agreement that will cover transmission services on the Acacia transmission pipeline. This contractual arrangement will include annual rate escalators.

Delivery Points. The Acacia transmission system has the ability to deliver natural gas to Atmos Energy, Brazos Electric, Enbridge Energy Partners, Energy Transfer Partners, Enterprise Product Partners and GDF Suez.

East Johnson County gathering system

The East Johnson County gathering system, which was placed into service by Devon in 2003, is comprised of a network of pipelines and related equipment that collects raw natural gas from producers operating in the Barnett Shale in North Texas. The East Johnson County gathering system presently consists of approximately 270 miles of pipeline segments with approximately 41,000 horsepower of compression. As of June 30, 2013,

 

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there were approximately 550 natural gas meters connected to this system. For the six months ended June 30, 2013 and the year ended December 31, 2012, the East Johnson County gathering system gathered approximately 242,800 MMBtu/d and 277,800 MMBtu/d of natural gas, respectively.

Customers. Devon is the largest customer on the East Johnson County gathering system with approximately 225,500 MMBtu/d and 259,100 MMBtu/d of natural gas gathered for the six months ended June 30, 2013 and the year ended December 31, 2012, which represented approximately 93% of the total throughput on the system during both periods.

Contracts. Devon and Devon Midstream Holdings will enter into a 10-year, fixed-fee gathering agreement that will cover gathering services on the East Johnson County gathering system. This contractual arrangement will include a five-year minimum volume commitment of 125 MMcf/d of natural gas delivered for gathering into the East Johnson County gathering system as well as annual rate escalators.

Delivery Points. The East Johnson County system delivers natural gas to Atmos Energy and Enterprise Product Partners.

Cana System

The Cana system includes an approximately 410-mile gathering system, a multi-train 350 MMcf/d cryogenic processing plant, NGL capacity of 30 MBbls/d and a condensate stabilization facility located in the Cana-Woodford Shale in West Central Oklahoma. For the six months ended June 30, 2013, the Cana system gathered approximately 310,100 MMBtu/d of gas and produced 16 MBbls/d of NGLs.

The following map identifies the locations of the principal assets comprising Devon Midstream Holdings’ Cana system:

 

 

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Cana processing facility

Operations at the Cana natural gas processing facility began in 2010, with 200 MMcf/d of processing capacity and 19 MBbls/d of NGL production capacity. Since 2010, Devon has invested in upgrades and expansions to the Cana processing facility, which have increased processing capacity by approximately 150 MMcf/d of natural gas and NGL production capacity by 11 MBbls/d.

For the six months ended June 30, 2013, inlet volumes averaged 229 MMcf/d of natural gas resulting in 16 MBbls/d of raw mix NGLs being produced, together with 241,100 MMBtu/d of residue natural gas. For the year ended December 31, 2012, inlet volumes at the Cana processing facility averaged 209 MMcf/d of natural gas resulting in 12 MBbls/d of raw mix NGLs being produced, together with 209,700 MMBtu/d of residue natural gas.

The Cana processing facility produces raw mix NGLs that are delivered to Mont Belvieu, Texas for fractionation through ONEOK Partners’ Arbuckle NGL pipeline. Similar to the Bridgeport processing facility, the cryogenic turboexpander plants at this facility have the ability to reject ethane, allowing Devon and other customers to sell ethane in its most valuable state depending on market conditions.

Customers. Devon is the only customer of the Cana processing facility.

Contracts. Devon and Devon Midstream Holdings will enter into a 10-year, fixed-fee gathering and processing agreement that will cover gathering services on the Cana gathering system and processing services at the Cana processing facility. This contractual arrangement will include a five-year minimum volume commitment from Devon of 330 MMcf/d of natural gas delivered to the processing facility as well as annual rate escalators.

Delivery Points. The residue natural gas from the Cana processing facility is delivered to Enogex and ONEOK Partners. The raw mix NGLs produced by the processing facility are delivered through ONEOK Partners’ Arbuckle NGL pipeline to Mont Belvieu, Texas for fractionation.

Cana gathering system

The Cana gathering system, which was placed into service by Devon in 2010, is comprised of a network of pipelines, compressors and related equipment that collects raw natural gas from producers operating in the Cana-Woodford Shale. The Cana gathering system presently consists of approximately 410 miles of pipeline segments with approximately 92,500 horsepower of compression. As of June 30, 2013, there were approximately 280 natural gas meters connected to this system. For the six months ended June 30, 2013 and the year ended December 31, 2012, the Cana gathering system gathered approximately 310,100 MMBtu/d and 265,700 MMBtu/d of natural gas, respectively.

Customers. Devon is the only customer of the Cana gathering system.

Contracts. Devon and Devon Midstream Holdings will enter into a 10-year, fixed-fee gathering and processing agreement that will cover gathering services on the Cana gathering system and processing services at the Cana processing facility. This contractual arrangement will include a five-year minimum volume commitment from Devon of 330 MMcf/d of natural gas delivered to the processing facility as well as annual rate escalators.

Delivery Points. The substantial majority of the natural gas in the Cana system is delivered to the Cana processing facility for processing with limited volumes being delivered to DCP Midstream, Enogex and Mustang Fuel Company processing facilities.

 

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Northridge System

The Northridge system includes an approximate 140-mile gathering system, a 200 MMcf/d cryogenic processing plant and NGL capacity of 17 MBbls/d located in the Arkoma-Woodford Shale in Southeastern Oklahoma. For the six months ended June 30, 2013, the Northridge system gathered 72,300 MMBtu/d of gas and produced 9 MBbls/d of NGLs. Approximately 40% of the gas processed at the Northridge facility is not gathered by Devon Midstream Holdings but is received on an interruptible basis from third parties who deliver the gas directly to the processing facility.

The following map identifies the locations of the principal assets comprising Devon Midstream Holdings’ Northridge system:

 

Northridge processing facility

Operations at the Northridge natural gas processing facility began in 2008, with 200 MMcf/d of processing capacity and 17 MBbls/d of NGL production capacity.

For the six months ended June 30, 2013, inlet volumes averaged approximately 110 MMcf/d of natural gas resulting in approximately 9 MBbls/d of raw mix NGLs being produced, together with 55,700 MMBtu/d of residue natural gas. For the year ended December 31, 2012, inlet volumes at the Northridge processing facility averaged 94 MMcf/d resulting in approximately 7 MBbls/d of raw mix NGLs being produced, together with approximately 65,500 MMBtu/d of residue natural gas.

The Northridge processing facility produces raw mix NGLs that are delivered to Mont Belvieu, Texas for fractionation. Similar to the Bridgeport and Cana processing facilities, the cryogenic turboexpander plant at this facility has the ability to reject ethane, allowing Devon and other customers to sell ethane in its most valuable state depending on market conditions.

 

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Customers. Devon is the largest customer of the Northridge processing facility with approximately 61 MMcf/d and 71 MMcf/d of natural gas processed for the six months ended June 30, 2013 and the year ended December 31, 2012 respectively, which represented approximately 55% and 75% of the total volumes processed at the facility during such periods, respectively.

Contracts. Devon and Devon Midstream Holdings will enter into a 10-year fixed-fee gathering and processing agreement that will cover gathering services for the Northridge gathering system and processing services at the Northridge processing facility. This contractual arrangement will include a five-year minimum volume commitment of 40 MMcf/d of natural gas delivered to the processing facility as well as annual rate escalators.

Delivery Points. The residue natural gas from the Northridge processing facility is delivered to Centerpoint, Enogex and MarkWest. Raw mix NGLs produced by the processing facility are delivered through a ONEOK Partners NGL pipeline to Mont Belvieu, Texas for fractionation.

Northridge gathering system

The Northridge gathering system, which was placed into service by Devon in 2007, is comprised of a network of pipelines and related equipment that collects raw natural gas from producers operating in the Arkoma-Woodford Shale in Southeastern Oklahoma. The Northridge gathering system presently consists of approximately 140 miles of pipeline segments with approximately 18,000 horsepower of compression installed. As of June 30, 2013, there were approximately 160 natural gas meters connected to this system. For the six months ended June 30, 2013 and the year ended December 31, 2012, the Northridge gathering system gathered approximately 72,300 MMBtu/d and 85,000 MMBtu/d of natural gas, respectively.

Customers. Devon is the only customer on the Northridge gathering system.

Contracts. Devon and Devon Midstream Holdings will enter into a 10-year fixed-fee gathering and processing agreement that will cover gathering services for the Northridge gathering system and processing services at the Northridge processing facility. This contractual arrangement will include a five-year minimum volume commitment of 40 MMcf/d of natural gas delivered for gathering into the Northridge gathering system as well as annual rate escalators.

Delivery Points. The substantial majority of the natural gas in the Northridge system is delivered to the Northridge processing facility with limited volumes being delivered to Enogex without processing.

Gulf Coast Fractionators

Devon Midstream Holdings owns a 38.75% non-operating equity interest in Gulf Coast Fractionators, an NGL fractionator located on the Gulf Coast at Mont Belvieu, Texas. Phillips 66 and Targa Resources Partners own 22.50% and 38.75% partnership interests in the fractionator, respectively. Phillips 66 is the operator of the fractionator. Gulf Coast Fractionators receives raw mix NGLs from customers, fractionates the raw mix and redelivers the finished products to the customers for a fee. The facility has a capacity of approximately 120 MBbls/d to 145 MBbls/d depending on the composition of the inlet NGL stream. For the six months ended June 30, 2013 and the year ended December 31, 2012, Gulf Coast Fractionators contributed 7% and 3%, respectively, to our Predecessor’s net income from continuing operations.

Competition

As a result of the relationship between Devon and Devon Midstream Holdings, we do not compete for the portion of Devon’s existing operations for which we currently provide midstream services. For areas where acreage is not dedicated to us, Devon Midstream Holdings will compete with similar enterprises in providing

 

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additional gathering and processing services in its respective areas of operation. Some of these competitors may expand or construct gathering, processing and transportation systems that would create additional competition for the services provided by Devon Midstream Holdings to oil and natural gas producers. In addition, third parties that are significant producers of natural gas in Devon Midstream Holdings’ areas of operation may develop their own gathering, processing and transportation systems in lieu of employing Devon Midstream Holdings’ assets.

Safety and Maintenance Regulation

Devon Midstream Holdings is subject to regulation by the PHMSA under the Accountable Pipeline and Safety Partnership Act of 1996, also known as the APSA, and comparable state statutes, which relate to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Any entity that owns or operates pipeline facilities must comply with such regulations, permit access to and copying of records, and file certain reports and provide information as required by the United States Secretary of Transportation. The PHMSA may assess fines and penalties for violations of these and other requirements imposed by its regulations. We believe that Devon Midstream Holdings is in material compliance with all regulations imposed by the PHMSA pursuant to the APSA.

Devon Midstream Holdings is also subject to the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, and the Pipeline Safety Improvement Act of 2002, or PSIA, as amended by the Pipeline Inspection Protection Enforcement and Safety Act of 2006, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, or the PIPES Act. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the PSIA establishes mandatory inspections for all United States oil and natural gas transportation pipelines, and some gathering lines in high consequence areas. DOT regulations implementing the PSIA require pipeline operators to conduct integrity management programs, which involve frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” or HCAs, such as high population areas, areas that are sources of drinking water, ecological resource areas that are unusually sensitive to environmental damage from a pipeline release, and commercially navigable waterways. The PHMSA has developed regulations that require pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in HCAs. The regulations require operators, including Devon Midstream Holdings, to:

 

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perform ongoing assessments of pipeline integrity;

 

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identify and characterize applicable threats to pipeline segments that could impact a HCA;

 

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improve data collection, integration and analysis;

 

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repair and remediate pipelines as necessary; and

 

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implement preventive and mitigating actions.

Although many of Devon Midstream Holdings’ pipeline facilities fall within a class that is currently not subject to these requirements, it may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with its non-exempt pipelines, particularly its Barnett assets. We currently estimate that Devon Midstream Holdings will incur approximately $2.5 million during 2013 to complete the testing required by existing DOT regulations and their state counterparts. This estimate does not include the costs for any repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down Devon Midstream Holdings’ pipelines during the prudency of such repairs. Additionally, should Devon Midstream Holdings fail to comply with DOT or comparable state regulations, it could be subject to penalties and fines. If future DOT pipeline integrity management regulations were to require that Devon Midstream Holdings expand its integrity managements program to currently unregulated pipelines, including gathering lines, costs associated with compliance may have a material effect on our operations.

 

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Recently enacted pipeline safety legislation, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the 2011 Pipeline Safety Act, reauthorizes funding for federal pipeline safety programs, increases penalties for safety violations, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. The 2011 Pipeline Safety Act, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas. On August 13, 2012, PHMSA issued a proposed rulemaking consistent with the signed act that, once finalized, will increase the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after January 3, 2012 to $200,000 per violation per day, with a maximum of $2,000,000 for a series of violations. The PHMSA recently issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations. The PHMSA has also published advanced notice of proposed rulemakings to solicit comments on the need for changes to its natural gas and liquid pipeline safety regulations, including gathering lines. PHMSA also recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have completed the verification process and, in some cases, performed hydrostatic tests on pipelines to confirm and document the maximum allowable operating pressures. We do not expect that any final rulemaking by PHMSA regarding verification of maximum allowable operating pressure would materially affect our operations or revenues.

The National Transportation Safety Board has recommended that the PHMSA make a number of changes to its rules, including removing an exemption from most safety inspections for natural gas pipelines installed before 1970. While we cannot predict the outcome of legislative or regulatory initiatives, such legislative and regulatory changes could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations (such as integrity management requirements) to pipelines and gathering lines not previously subjected to these requirements. While we expect any legislative or regulatory changes to allow us time to become compliant with new requirements, costs associated with compliance may have a material effect on our operations.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcement of federal intrastate pipeline regulations and inspection of intrastate pipelines. States may adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines; however, states vary considerably in their authority and capacity to address pipeline safety. State standards may include requirements for facility design and management in addition to requirements for pipelines. We do not anticipate any significant problems in complying with state laws and regulations applicable to Devon Midstream Holdings’ operations. Devon Midstream Holdings’ natural gas pipelines have continuous inspection and compliance programs designed to maintain compliance with federal and state pipeline maintenance, safety and pollution control requirements.

Devon Midstream Holdings may be subject to the Chemical Facility Anti-Terrorism Standards Act, or the CFATS, which is administered by the U.S. Department of Homeland Security, or DHS. The CFATS requires that certain facilities register with the DHS to determine if their facilities are exempt from regulation or if they present a high level of security risk. A facility determined to have a high level of security risk will be placed by the DHS into a tier level based on a risk-based tier system. All facilities placed into a tier will be required to provide additional information to help determine final security measures. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. Devon Midstream Holdings has complied with the requirements of CFATS by registering certain of its facilities with the DHS.

While we are not currently subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered by the

 

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U.S. Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security, and we may become subject to such standards in the future. We are currently implementing our own cyber-security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on operations and those of our customers.

In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, referred to as OSHA, and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. The applicable laws and regulations include the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, the EPA Accidental Release Prevention regulations under the Clean Air Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, that this information be provided to employees, state and local government authorities and citizens and that we prepare a risk management plan which is submitted to the EPA. We are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves 10,000 pounds or more of a flammable liquid or gas in one location. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety. However, compliance with these laws and regulations requires facilities to be shut down for internal inspections, which can have a significant impact on processing unit availability.

Regulation of Operations

Regulation of pipeline gathering and transportation services, natural gas sales and transportation of NGLs may affect certain aspects of Devon Midstream Holdings’ business and the market for its products and services.

Gathering Pipeline Regulation. Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from regulation by FERC under the NGA. Although the FERC has not made any formal determinations with respect to any of Devon Midstream Holdings’ facilities, we believe that the natural gas pipelines in its gathering systems meet the traditional tests FERC has used to establish whether a pipeline is a gathering pipeline not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and the FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of some of Devon Midstream Holdings’ natural gas gathering facilities and intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress. If the FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by the FERC under the NGA or the NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of Devon Midstream Holdings’ facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Devon Midstream Holdings’ natural gas gathering operations are subject to ratable take and common purchaser statutes in the states in which we operate. These statutes generally require Devon Midstream Holdings’ gathering pipelines to take natural gas without undue discrimination in favor of one producer over another producer or one source of supply

 

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over another similarly situated source of supply. The regulations under these statutes can have the effect of imposing some restrictions on Devon Midstream Holdings’ ability as an owner of gathering facilities to decide with whom it contracts to gather natural gas. States in which Devon Midstream Holdings operates have adopted a 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 gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to Devon Midstream Holdings’ system due to these regulations.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels. Devon Midstream Holdings’ gathering operations could be adversely affected should they be subject in the future to more stringent application of state or federal regulation of rates and services. Devon Midstream Holdings’ gathering operations also may be or become subject to additional 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 or 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.

Intrastate Natural Gas Pipeline Regulation. Devon Midstream Holdings’ subsidiaries, Southwestern Gas Pipeline, L.L.C. and Acacia Natural Gas, L.L.C., are subject to rate regulation under the Texas Utilities Code, as implemented by the Texas Railroad Commission, or the TRRC, and each have tariffs on file with the TRRC. Generally, the TRRC is vested with the authority to ensure that rates, operations and services of natural gas utilities, including intrastate pipelines and gatherers who have exercised eminent domain authority under the Texas Utilities Code, are just and reasonable, and not discriminatory. The rates Devon Midstream Holdings charges for intrastate services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against Devon Midstream Holdings or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to Devon Midstream Holdings’ system due to this regulation.

The TRRC’s current code of conduct applies the common purchaser act to gathering and transportation activities. The common purchaser statutes generally require pipelines to purchase or take without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on Devon Midstream Holdings’ ability as an owner of pipeline facilities to decide with whom it contracts to purchase natural gas. Texas has adopted a complaint-based regulation of natural gas purchasing, gathering and transportation activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas purchases and gathering and transportation access and rate discrimination.

In Texas, natural gas gathering and transmission pipelines are subject to laws regarding rates, competition and confidentiality (“Competition Statute”) and are subject to complaint procedures for challenging determinations of lost and unaccounted for gas by gas gatherers, processors and transporters (“LUG Statute”). The Competition Statute allows the TRRC the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering and/or transmission in formal rate proceedings. It also gives the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering and transportation, to enforce the requirement that parties participate in an informal complaint process, and to punish purchaser, transporters, and gatherers for taking discriminatory actions against shippers and sellers. The LUG Statute modifies the informal complaint process at the TRRC with procedures unique to lost and unaccounted for gas issues. We cannot predict what effect, if any, these statutes might have on Devon Midstream Holdings’ operations, but they have had no adverse effect since they were enacted in 2007.

 

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The pipeline, which we refer to as the Acacia transmission system, owned by Acacia Natural Gas, L.L.C., Devon Midstream Holdings’ wholly-owned subsidiary, provides interruptible transportation of natural gas in interstate commerce pursuant to Section 311 of the NGPA, and Part 284 of the FERC’s regulations. The NGPA regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of an interstate natural gas pipeline or a local distribution company (“LDC”) served by an interstate natural gas pipeline. Pipelines providing transportation service under Section 311 of the NGPA are required to provide services on an open and nondiscriminatory basis. The rates, terms and conditions of the transportation services provided under Section 311 are subject to FERC regulation. Under Section 311, rates charged for intrastate transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. Rates for service pursuant to Section 311 of the NGPA are generally subject to review and approval by FERC at least once every five years. The terms and conditions of service set forth in the intrastate facility’s statement of operating conditions are also subject to FERC review and approval. In addition, Acacia is required to file periodic reports with FERC. We believe that we are in material compliance with all applicable state and federal laws and regulations governing the Acacia transmission system. Devon Midstream Holdings’ most recent rate filing was accepted by the FERC on November 30, 2012. Should the FERC determine not to authorize rates equal to or greater than Devon Midstream Holdings’ currently approved Section 311 rates, its business may be adversely affected. Failure to observe the service limitations applicable to transportation and storage services under Section 311, failure to comply with the rates approved by the FERC for Section 311 service, and failure to comply with the terms and conditions of service established in the pipeline’s FERC-approved statement of operating conditions could result in alteration of jurisdictional status, or the imposition of administrative, civil and criminal remedies.

Under Oklahoma statutes a gatherer may not refuse to provide “open access” natural gas gathering “including the redelivery of such natural gas to existing redelivery points” for a fee, subject to certain exceptions. Further, a gatherer may not impose unfair, unjust, unreasonable or unduly discriminatory fees and terms of service. The Oklahoma Corporation Commission (“OCC”) has the authority to remedy such fees or terms by ordering an adjustment of the fees and terms offered by the gatherer. If the natural gas is also processed by the gatherer, the OCC may provide a mechanism in the fee that replicates bypassing the shipper’s natural gas. In general, the statutes require that the OCC determine fees and terms of service that would result from “arms-length bargaining in good faith in a competitive market between persons of equal bargaining power.” Oklahoma statutes also provide that the OCC has jurisdiction to adjudicate complaints regarding the purchase and transportation of natural gas. The OCC may order the purchase or transportation of natural gas by the pipeline, subject to certain exceptions.

Natural Gas Storage Regulation. The storage field’s injection and withdrawal wells used in association with the Acacia system, along with water disposal wells located at the Bridgeport processing facility, are under the jurisdiction of the TRRC. Regulatory requirements for these wells involve monthly and annual reporting of the natural gas and water disposal volumes associated with the operation of these wells, respectively. Results of periodic mechanical integrity tests run on these wells must also be reported to the TRRC. We believe that we are in material compliance with all applicable rules and regulations related to these wells.

Environmental Matters

General. Devon Midstream Holdings’ natural gas gathering, processing, transportation and fractionation activities are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, Devon Midstream Holdings must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact Devon Midstream Holdings’ business activities in many ways, such as:

 

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requiring the installation of pollution-control equipment, imposing emission or discharge limits or otherwise restricting the way Devon Midstream Holdings operates resulting in additional costs to its operations;

 

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limiting or prohibiting construction activities in areas, such as air quality nonattainment areas, wetlands, coastal regions or areas inhabited by endangered or threatened species;

 

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delaying system modification or upgrades during review of permit applications and revisions;

 

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requiring investigatory and remedial actions to mitigate discharges, releases or pollution conditions associated with our operations or attributable to former operations; and

 

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enjoining the operations of facilities deemed to be in non-compliance with permits issued pursuant to or regulatory requirements imposed by such environmental laws and regulations.

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 and natural resource damages. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or solid wastes have been disposed or otherwise released. Moreover, neighboring landowners and other third parties may file common law claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or solid waste into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and thus, 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. As with the midstream industry in general, complying with current and anticipated environmental laws and regulations can increase our capital costs to construct, maintain and operate equipment and facilities. While these laws and regulations affect our maintenance capital expenditures and net income, we do not believe they will have a material adverse effect on our business, financial position or results of operations or cash flows, nor do we believe that they will affect our competitive position since the operations of our competitors are generally similarly affected. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish Devon Midstream Holdings’ operational ability to gather natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to Devon Midstream Holdings’ business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Waste. Devon Midstream Holdings’ operations generate solid wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws, which impose requirements for the handling, storage, treatment and disposal of hazardous waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes intrinsically associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state solid waste laws and regulations. However, common industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as special or hazardous waste. The transportation of natural gas and NGL in pipelines may also generate some hazardous wastes subject to RCRA or comparable state law requirements.

Site Remediation. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Although petroleum as well as natural gas is excluded from

 

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CERCLA’s definition of “hazardous substance,” in the course of Devon Midstream Holdings’ ordinary operations, Devon Midstream Holdings generates wastes that may be designated as hazardous substances. CERCLA authorizes the U.S. Environmental Protection Agency, or EPA, states, and in some cases, third parties to take actions in response to releases or threatened releases of hazardous substances into the environment and to seek to recover from the classes of responsible persons the costs they incur. Under CERCLA, Devon Midstream Holdings could be subject to strict joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released into the environment and for damages to natural resources.

Devon Midstream Holdings currently owns or leases, and may have in the past owned or leased, properties that for many years have been used for the measurement, gathering, compression, treating and processing of natural gas. Although Devon Midstream Holdings typically used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by it or on or under other locations where such substances have been taken for disposal. Such petroleum hydrocarbons or wastes may have migrated to property adjacent to Devon Midstream Holdings’ owned and leased sites or the disposal sites. In addition, some of the properties may have been operated by third parties or by previous owners whose treatment and disposal or release of petroleum hydrocarbons or wastes was 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, Devon Midstream Holdings could be required to remove previously disposed 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 remedial operations to prevent future contamination. Devon Midstream Holdings is not currently a potentially responsible party in any federal or state Superfund site remediation and there are no current, pending or anticipated Superfund response or remedial activities at or implicating Devon Midstream Holdings facilities or operations.

Air Emissions. The Clean Air Act, and comparable state laws, regulate emissions of air pollutants from various industrial sources, including natural gas processing plants and compressor stations, and also impose various emission limits, operational limits and monitoring, reporting and record keeping requirements on air emission sources. Failure to comply with these requirements could result in monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. Such laws and regulations require pre- construction permits for the construction or modification of certain projects or facilities with the potential to emit air emissions above certain thresholds. These pre-construction permits generally require use of best available control technology (“BACT”) to limit air emissions. Several EPA new source performance standards (“NSPS”) and national emission standards for hazardous air pollutants (“NESHAP”) also apply to Devon Midstream Holdings facilities and operations. These NSPS and NESHAP standards impose emission limits and operational limits as well as detailed testing, recordkeeping and reporting requirements on the “affected facilities” covered by these regulations. Several Devon Midstream Holdings facilities are “major” facilities requiring Title V operating permits which impose semi-annual reporting requirements. Devon Midstream Holdings operates in material compliance with these various air quality regulatory programs. Devon Midstream Holdings may incur capital expenditures in the future for air pollution control equipment in connection with complying with existing and recently proposed rules, or with obtaining or maintaining operating permits and complying with federal, state and local regulations related to air emissions. However, we do not believe that such requirements will have a material adverse effect on Devon Midstream Holdings’ operations.

In addition, the EPA included Wise County in its January 2012 revision to the Dallas-Ft. Worth ozone nonattainment area for the 2008 revised ozone national ambient air quality standard. Devon, Texas industry trade groups and the State of Texas filed petitions for reconsideration with EPA and a petition for review in the U.S. D.C. Circuit Court of Appeals challenging this designation. The appeal remains pending. If EPA’s designation of Wise County ultimately prevails, new major sources, meaning sources that emit greater than 100 tons/year of nitrogen oxides (“NOx”) and volatile organic compounds (“VOCs”), as well as major modifications of existing facilities resulting in net emissions increases of greater than 40 tons/year of NOx or VOCs, would be subject to more stringent new source review (“NSR”) pre-construction permits. NSR pre-

 

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construction permits can take twelve to eighteen months to obtain and require the permit applicant to offset the proposed emission increases with reductions elsewhere at 1.15 to 1 ratio. In addition, if EPA’s nonattainment designation of Wise County prevails, more stringent Texas emission standards would apply to Devon’s existing compressor engines requiring Devon to install additional emission controls. Costs to install these additional controls are estimated at approximately $15 million.

Water Discharges. The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited, except in accordance with the terms of a permit issued by the EPA or a delegated state agency. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. EPA regulations also require facilities that store oil to have spill prevention control and countermeasure (“SPCC”) plans. Devon Midstream Holdings’ facilities are in material compliance with EPA SPCC requirements. Any unpermitted release of petroleum or other pollutants from our operations could result in government penalties and civil liability.

Endangered Species. The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of Devon Midstream Holdings’ processing facilities and pipelines are located in areas that are or may be designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to limits on future development activity in the affected areas. Specifically, the Northridge Gas Plant and Gathering System in southeast Oklahoma are located in American Burying Beetle habitat, a federally-listed endangered species. However, location in this habitat does not affect current plant and gathering system operations and there are no construction projects currently planned for the plant which could trigger ESA requirements.

Climate Change. In December 2009, the EPA determined that emissions of greenhouse gases, or GHGs, present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Based on these findings, EPA has adopted regulations under existing provisions of the federal Clean Air Act, that establish Prevention of Significant Deterioration, (“PSD”) pre-construction permits, and Title V operating permits for GHG emissions from certain large stationary sources. Under these regulations, facilities required to obtain PSD permits must meet “best available control technology” standards for their GHG emissions established by the states or, in some cases, by the EPA on a case-by-case basis. The EPA has also adopted rules requiring the monitoring and reporting of GHG emissions from specified sources in the United States, including, among others, certain onshore oil and natural gas processing and fractionating facilities. We believe we are in substantial compliance with all GHG emissions permitting and reporting requirements applicable to our operations. While Congress has from time to time considered legislation to reduce emissions of GHGs, the prospect for adoption of significant legislation at the federal level to reduce GHG emissions is perceived to be low at this time. Nevertheless, the Obama administration has announced it intends to adopt additional regulations to reduce emissions of GHGs and to encourage greater use of low carbon technologies. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that exploration and production operators produce, some of whom are our customers, which could thereby reduce demand for our midstream services. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, it is uncertain if they would have an adverse effect on our financial condition and operations.

 

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Title to Properties and Rights-of-Way

Devon Midstream Holdings’ real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from easements, rights-of-way, leases, permits or licenses from landowners or governmental authorities permitting the use of such land for its operations. The surface of the land on which Devon Midstream Holdings’ processing facilities and many of its compressors and other facilities are located is owned by Devon Midstream Holdings in fee title, and we believe that Devon Midstream Holdings has satisfactory title to such land. We have no knowledge of any challenge to the underlying title of any material easement, right-of-way, lease, permit or license held by Devon Midstream Holdings or to its title to any material easement, right-of-way, permit or lease, and we believe that Devon Midstream Holdings has satisfactory title to all of its material easements, rights-of-way, permits and licenses.

Some of the easements, rights-of-way, permits and licenses to be transferred to Devon Midstream Holdings may require the consent of the grantor of such rights, which in certain instances is a governmental entity. Our general partner expects to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable Devon Midstream Holdings to operate its business in all material respects as described in this prospectus. With respect to any material consents, permits or authorizations that have not been obtained prior to closing of this offering, the closing of this offering will not occur unless reasonable bases exist that permit our general partner to conclude that such consents, permits or authorizations will be obtained within a reasonable period following the closing, or the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of Devon Midstream Holdings’ business.

Employees

We do not have any employees. The officers of our general partner will manage our operations and activities. As of June 30, 2013, Devon employed approximately 400 people who will provide direct, full-time support to our operations. All of the employees required to conduct and support our operations will be employed by Devon and all of our direct, full-time personnel are subject to the omnibus agreement between our general partner and Devon. None of these employees are covered by collective bargaining agreements, and Devon considers its employee relations to be good.

Legal Proceedings

Devon Midstream Holdings’ operations are subject to a variety of risks and disputes normally incident to its business. As a result, it is and may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. However, assets that will be contributed to Devon Midstream Holdings are not currently subject to any material litigation.

With respect to Devon Midstream Holdings’ properties, Devon maintains insurance policies with insurers in amounts and with coverage and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

 

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MANAGEMENT

Management of Devon Midstream Partners, L.P.

We do not directly employ any of the persons responsible for managing or operating our business. We are managed by our general partner, the executive officers of which are employees of Devon. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Devon indirectly owns all of the membership interests in our general partner. Our general partner has a board of directors, and our unitholders are not entitled to elect the directors or, directly or indirectly, to participate in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Following the closing of this offering, we expect that our general partner will have at least 7 directors. Devon will appoint all members to the board of directors of our general partner. In accordance with the NYSE’s phase-in rules, we will have at least one independent director on the date that our common units are first listed on the NYSE and three independent directors within one year of that date.

Neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner, but we sometimes refer to these individuals in this prospectus as our employees.

Director Independence

Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a publicly-traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.

Committees of the Board of Directors

The board of directors of our general partner will have an audit committee and a conflicts committee, and may have such other committees as the board of directors shall determine from time to time. Each of the standing committees of the board of directors will have the composition and responsibilities described below.

Audit Committee

At least three independent members of the board of directors of our general partner will serve as the initial members of our audit committee. Our general partner initially may rely on the phase-in rules of the SEC and the NYSE with respect to the independence of our audit committee. Those rules permit our general partner to have an audit committee that has one independent member by the date our common units are first listed on the NYSE, a majority of independent members within 90 days thereafter and all independent members within one year thereafter. Our audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee will have the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to our audit committee.

 

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Conflicts Committee

At least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest in accordance with the terms of our partnership agreement. Our conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of our conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee may not own any interest in our general partner or any interest in us or our subsidiaries other than common units or awards under our Equity Plan described below. Any matters approved by our conflicts committee in good faith will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Directors and Executive Officers

The following table shows information regarding the executive officers and directors of our general partner. Directors are elected for one-year terms. The executive officers of our general partner are also executive officers of Devon and are providing their services to our general partner and us pursuant to the services agreement to be entered into among us, Devon and our general partner. The executive officers listed below will divide their working time between the management of Devon, our general partner and us. Our directors hold office until the earlier of their death, resignation, retirement, disqualification or removal by the board of directors. Officers serve at the discretion of the board of directors.

 

Name		Age				Position with DLP GP, L.L.C.
David A. Hager			56			President and Chief Executive Officer/Director
Darryl G. Smette			66			Chief Operating Officer/Director
Jeffrey A. Agosta			46			Executive Vice President and Chief Financial Officer/Director
Lyndon C. Taylor			55			Executive Vice President, General Counsel and Corporate Secretary/Director

David A. Hager will serve as President and Chief Executive Officer and director of our general partner. He serves as Chief Operating Officer of Devon and previously held the position of Executive Vice President Exploration and Production of Devon from March 2009 until June 2013. From 2007 until joining Devon as an executive officer, Mr. Hager served as a member of Devon’s Board of Directors. Mr. Hager started in the oil and gas business as a geophysicist with Mobil Corp., joined Sun Oil in 1981 and remained with the company when it was renamed Oryx Energy. During his tenure at Oryx he managed new ventures and deepwater projects around the world. Oryx merged with Kerr-McGee in 1999, and while at Kerr-McGee, Mr. Hager managed the company’s worldwide deepwater exploration and production operations then took over all of exploration and production in 2003. He later served as Kerr-McGee’s chief operating officer until it was acquired by Anadarko Corp. in 2006. Mr. Hager has a Bachelor’s degree in Geophysics from Purdue University and a Master’s degree in Business Administration from Southern Methodist University.

Darryl G. Smette will serve as Chief Operating Officer and director of our general partner. He has held the position of Executive Vice President Marketing, Midstream and Supply Chain at Devon since 1999 and has been an employee of Devon since 1986. His marketing background includes 15 years with Energy Reserves Group, Inc./BHP Petroleum (Americas), Inc. Mr. Smette serves on the Board of Directors of Panhandle Oil & Gas Inc. Mr. Smette also is an oil and gas industry instructor approved by the University of Texas Department of Continuing Education. He is a member of the Oklahoma Independent Producers Association, Natural Gas Association of Oklahoma and the American Gas Association. Mr. Smette holds an undergraduate degree from Minot State University and a Master’s degree from Wichita State University.

Jeffrey A. Agosta will serve as Executive Vice President and Chief Financial Officer and director of our general partner. He was elected to the position of Executive Vice President and Chief Financial Officer with Devon in March 2010 and has been with Devon since 1997. He held the position of Senior Vice President—Corporate

 

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Finance and Treasurer at Devon from 2003 to 2010. Prior to joining Devon, Mr. Agosta was with the management consulting firm of D. R. Payne and Associates and with KPMG Peat Marwick. He holds a Bachelor’s degree in Accounting from the University of Oklahoma and is a Certified Public Accountant.

Lyndon C. Taylor will serve as Executive Vice President, General Counsel and Corporate Secretary for our general partner. He has held the position of Executive Vice President and General Counsel at Devon since 2007. He served as Deputy General Counsel from the time he joined Devon in 2005 until 2007. Prior to joining Devon, Mr. Taylor was with Skadden, Arps, Slate, Meagher & Flom LLP for 20 years, most recently as managing partner of the energy practice in Houston. He is admitted to practice law in Oklahoma and Texas. Mr. Taylor holds a Bachelor’s degree in Industrial Engineering from Oklahoma State University and a Juris Doctorate degree from the University of Oklahoma.

Reimbursement of Expenses of Our General Partner

Our general partner will not receive any management fee or other compensation for its management of our partnership. Our general partner and its affiliates will, however, be reimbursed for all expenses incurred on our behalf. Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. The partnership agreement provides that our general partner will determine the expenses that are allocable to us. There is no limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. Please read “The Partnership Agreement—Reimbursement of Expenses” and “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Reimbursement of General and Administrative Expenses.”

Compensation of Our Directors

Our general partner did not have any, and paid no compensation to, members of its board of directors in 2012. Following the consummation of this offering, any employees of Devon or its affiliates who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not officers of our general partner or any of their affiliates or employees of Devon or any of its affiliates will receive both cash and equity compensation as “non-employee directors.” Such compensation will consist of an annual retainer of $50,000 for each board member and a fee of $1,500 for each board meeting attended. The independent directors will also receive an annual grant pursuant to the Devon Midstream Partners, L.P. Long Term Incentive Plan (the “Equity Plan”) comprised of the number of units having a grant date value of $75,000, which will generally vest in one year. The Equity Plan is discussed in greater detail below. Further, each director will be indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law and will be reimbursed for all expenses incurred in attending to his or her duties as a director.

Executive Compensation

Compensation Discussion and Analysis

Since our general partner was formed in September 2013, it did not participate in the design or implementation of, nor accrue any obligations with respect to, compensation for the fiscal year ending December 31, 2012. Accordingly, we are not presenting any compensation for historical periods. Compensation paid to the executive officers of Devon that also provide services to us will be reimbursed by us in an amount allocated to us pursuant to Devon’s allocation methodology and subject to the terms of the omnibus agreement that we intend to enter into with Devon prior to the close of this offering, as described below.

 

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We will not directly employ any of the persons responsible for managing our business. All of the initial executive officers that will be responsible for managing our day to day affairs are also current officers of our general partner, Devon or its affiliates, and therefore will have responsibilities for us, our general partner and Devon and its subsidiaries after this offering.

The Devon individuals that we consider to be our “named executive officers” for purposes of this filing are as follows:

 

•

David A. Hager—President and Chief Executive Officer

 

•

Darryl G. Smette—Chief Operating Officer

 

•

Jeffrey A. Agosta—Executive Vice President and Chief Financial Officer

 

•

Lyndon C. Taylor—Executive Vice President, General Counsel and Corporate Secretary

The objectives of Devon’s compensation policies are to attract, motivate and retain qualified management and personnel who are highly talented while ensuring that executive officers and other employees are compensated in a manner that advances both the short- and long-term interests of shareholders. In pursuing these objectives, Devon’s compensation committee believes that compensation should reward executive officers and other employees for both their personal performance and the performance of Devon and its subsidiaries. For a detailed discussion of the compensation and benefits that Devon provided to the officers noted above during the previous fiscal year, please see the “Named Executive Officer Compensation” section of Devon’s most recent proxy statement, filed with the SEC on April 24, 2013.

Prior to the completion of this offering, we and our general partner will enter into an omnibus agreement with Devon pursuant to which, among other matters:

 

•

Devon will make available to our general partner the services of the Devon employees who serve as the executive officers of our general partner; and

 

•

our general partner will be obligated to reimburse Devon for any allocated portion of the costs that Devon incurs in providing compensation and benefits to such Devon employees.

Under the applicable provisions of our partnership agreement, we are required to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. These expenses include compensation expenses for individuals who perform services for us or on our behalf and expenses allocated to us by Devon or its affiliates. We intend to enter into an omnibus agreement with Devon in connection with this offering, which will govern the manner in which expenses will be allocated to us. Consistent with our Predecessor, we expect expenses will be allocated to us based on our proportionate share of Devon’s revenues, employee compensation and gross property, plant and equipment. For more information on the partnership agreement and the omnibus agreement, please read “The Partnership Agreement—Reimbursement of Expenses” and “Certain Relationships and Related Party Transactions—Reimbursement of General and Administrative Expenses.”

The executive officers of our general partner currently receive all of their compensation and benefits for employment related to our business from Devon. Although we bear an allocated portion of Devon’s costs of providing compensation and benefits to the Devon employees who serve as the executive officers of our general partner, we will have no control over such costs and do not establish or direct the compensation policies or practices of Devon. We are required to pay all compensation amounts allocated to us by Devon although we may object to amounts that we deem unreasonable. The executive officers of our general partner, as well as the employees of Devon who may provide services to us, may participate in employee benefit plans and arrangements sponsored by Devon, including plans that may be established in the future. Except with respect to the long-term incentive plan described below, neither we nor our general partner have entered into any additional employment or benefit-related agreements with any of the individuals who provide executive officer services to us, and we do not anticipate entering into any such agreements in the near future.

 

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In the future, the executive officers and directors of our general partner may receive equity-based compensation in connection with the long-term incentive plan that we intend to adopt (described below), and we will be responsible for all costs associated with the grant of awards under such long-term incentive plan. All determinations with respect to awards to be made under our long-term incentive plan to executive officers and other employees of our general partner and of Devon will be made by the board of directors of our general partner, although our general partner’s board of directors may consult with Devon when making such decisions. Responsibility and authority for compensation-related decisions for executive officers and other personnel employed directly by our general partner, if any, will reside with our general partner.

To the extent awards are made under our long-term incentive plan to the executive officers of our general partner, such awards will be approved by the board of directors of our general partner. All other compensation decisions regarding our named executive officers will be made by the board of directors of Devon and the compensation committee of the board of directors of Devon and will not be subject to approvals by the board of directors of our general partner or the audit committee or conflicts committee of the board of directors of our general partner.

Equity Plan

Prior to the completion of this offering, our general partner will adopt the Equity Plan on our behalf, which is described below. This summary, however, does not purport to be a complete description of all of the provisions of the Equity Plan. The summary is qualified in its entirety by reference to the Equity Plan, a copy of which has been filed as Exhibit 10.5 to this Registration Statement. The Equity Plan is designed to provide to employees, officers and directors of our general partner and its affiliates incentive compensation awards based on common units. The Equity Plan is also designed to supplement the compensation that these individuals may receive from the general partner and its affiliates and to provide them incentives to promote our interests and the interests of our affiliates.

General. Our Equity Plan will allow (as determined by the board of directors of our general partner or a committee appointed by the board of our general partner (as described below)) for the provision of grants of (i) unit options, (ii) restricted units, (iii) unit appreciation rights, (iv) phantom units, and (v) distribution equivalent rights (collectively referred to as “awards”).

Eligibility. Awards may be made under the Equity Plan to directors of our general partner, employees and officers of our general partner or any affiliate of our general partner who performs services for us or our affiliates or our general partner or its affiliates.

Administration. The provisions of the Equity Plan will be administered by the board of directors of our general partner or a committee as may be appointed by the Board to administer the Equity Plan, and the board of directors of our general partner or such committee appointed by the board of directors of our general partner has the full authority to select participants to receive awards, determine the types of awards and terms and conditions of awards, and interpret provisions of the Equity Plan.

Common Units Available for Issuance. Subject to certain adjustments that may be required from time to time to prevent dilution or enlargement of the rights of participants in the Equity Plan, a maximum of          common units will be available for grants of all awards under the Equity Plan. Units subject to awards that expire, are cancelled or are terminated without the delivery of units will again be available for issuance under the Equity Plan.

Source of Common Units; Cost. The common units to be issued under the Equity Plan will consist, in whole or in part, of common units acquired in the open market or from any affiliate of ours or any other person, newly issued common units or any combination of the foregoing, as determined by the board of directors of the general partners in its discretion. There will not be any limit on the number of awards that may be granted and paid in cash.

 

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Types of Awards

Options. The board of directors of the general partner is authorized to grant options to participants. The exercise price of any option must be equal to or greater than the fair market value of a common unit on the date the option is granted. The term of an option cannot exceed eight years. Subject to the terms of the Equity Plan, the option’s terms and conditions, which include but are not limited to, exercise price, vesting, treatment of the award upon termination of employment, and expiration of the option, would be determined by the board of directors of the general partner and set forth in an award agreement. Payment for common units purchased upon exercise of an option must be made in full at the time of purchase. The exercise price may be paid (i) in cash or its equivalent (e.g., check), (ii) in common units already owned by the participant, on terms determined by the committee, (iii) in the form of other property as determined by the board or committee, (iv) through participation in a “cashless exercise” procedure involving a broker or (v) by a combination of the foregoing.

Unit Appreciation Rights (“UARs”). The board of directors of the general partner is authorized, either alone or in connection with the grant of an option, to grant UARs to participants. The terms and conditions of a UAR award would be determined by the board of directors of the general partner and set forth in an award agreement. UARs may be exercised at such times and be subject to such other terms, conditions, and provisions as the committee may impose. The committee may establish a maximum amount per common unit that would be payable upon exercise of a UAR. A UAR would entitle the participant to receive on exercise of the UAR an amount equal to the product of (i) the excess of the fair market value of a unit on the date preceding the date of surrender over the fair market value of a common unit on the date the UAR was issued, or, if the UAR is related to an option, the per-unit exercise price of the option and (ii) the number of common units subject to the UAR or portion thereof being exercised. Subject to the discretion of the board or committee, payment of a UAR may be made in cash, common units or a combination thereof.

Restricted Units and Phantom Units. The board of directors of the general partner are authorized to grant restricted units, subject to such terms and conditions as determined by the board of directors of the general partner and set forth in an award agreement. Restricted units may not be sold, transferred, pledged, or otherwise transferred until the time, or until the satisfaction of such other terms, conditions, and provisions, as the committee may determine. When the period of restriction on restricted units terminates, unrestricted common units would be delivered. Unless such board determines otherwise at the time of grant, restricted units carry full voting rights and other rights as a unitholder, including rights to receive distributions. At the time an award of restricted units is granted, the board of directors of the general partner may determine that the payment to the participant of distributions would be deferred until the lapsing of the restrictions imposed upon the common units and whether deferred distributions are to be converted into additional common units or held in cash. The deferred distributions would be subject to the same forfeiture restrictions and restrictions on transferability as the restricted units with respect to which they were paid. Each phantom unit would represent the right of the participant to receive a payment upon vesting of the phantom unit or on any later date specified by the board or committee. The payment would equal the fair market value of a common unit as of the date the phantom unit was granted, the vesting date, or such other date as determined by the committee at the time the phantom unit was granted. At the time of grant, the board or committee may provide a limitation on the amount payable in respect of each phantom unit. The board or committee may provide for a payment in respect of phantom units in cash or in common units having a fair market value equal to the payment to which the participant has become entitled.

Distribution Equivalent Rights. The board of directors of the general partner is authorized to grant distribution equivalent rights either in tandem with an award or as a separate award. The terms and conditions applicable to each distribution equivalent right would be determined by such board and set forth in an award agreement. Amounts payable in respect of distribution equivalent rights may be payable currently or, if applicable, deferred until the lapsing of restrictions on the distribution equivalent rights or until the vesting, exercise, payment, settlement or other lapse of restrictions on the award to which the distribution equivalent

 

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rights relate; provided that distribution equivalent rights may not contain payment or other terms that could adversely affect the option or award to which it relates under Section 409A of the Internal Revenue Code or otherwise.

Amendment and Termination of the LTIP. While the board of directors of our general partner may amend the Equity Plan at any time, any amendment generally may not adversely impair the rights of plan participants with respect to outstanding awards. In addition, an amendment will be contingent on approval by holders of our common units if such amendment would result in the Equity Plan no longer satisfying any requirements of the principal securities exchange on which the common units are traded. Unless terminated earlier, the Equity Plan will terminate on the eighth anniversary of the date on which it is approved by the board of directors of our general partner, after which no further awards may be made under the Equity Plan, but the Equity Plan will continue to govern unexpired awards.

Change in Control. The effect, if any, of a change in control on each of the awards granted under the Equity Plan may be set forth in the applicable award agreement.

Adjustments. In the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off, split-up, unit distribution, issuance of warrants, rights or debentures, stock distribution, stock split or reverse stock split, cash distribution, property distribution, combination or exchange of units, repurchase of units, or similar transaction or other change in corporate structure affecting our common units, adjustments and other substitutions will be made to the Equity Plan, including adjustments in the maximum number of common units subject to the Equity Plan and adjustments to outstanding awards granted under the Equity Plan as the committee determines appropriate. In the event of our merger or consolidation, liquidation or dissolution, outstanding options and awards will be treated as provided for in the agreement entered into in connection with the transaction, or, if not so provided in such agreement, holders of options awards will be entitled to receive in respect of each common unit subject to any outstanding options or awards, upon exercise of any option or payment or transfer in respect of any award, the same number and kind of stock, securities, cash, property or other consideration that each holder of a common unit was entitled to receive in the transaction in respect of a common unit; provided, however, that such stock, securities, cash, property, or other consideration shall remain subject to all of the conditions, restrictions and performance criteria which were applicable to the options and awards prior to such transaction.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that will be issued upon the consummation of this offering and the related transactions and held by:

 

•

each person who then will beneficially own 5% or more of the then outstanding units;

 

•

each director and named executive officer of our general partner; and

 

•

all directors and officers of our general partner as a group.

 

Name of Beneficial Owner (1)		Common Units to be Beneficially Owned		Percentage of Common Units to be Beneficially Owned				Subordinated Units to be Beneficially Owned				Percentage of Subordinated Units to be Beneficially Owned				Percentage of Total Common and Subordinated Units to be Beneficially Owned
Devon (2)						%							100	%				%
David A. Hager						%			—				—	%				%
Darryl G. Smette						%			—				—	%				%
Jeffrey A. Agosta						%			—				—	%				%
Lyndon C. Taylor						%			—				—	%				%
All directors and executive officers as a group (     persons)						%			—				—	%			—	%

 

*	Less than 1%.

(1)	Unless otherwise indicated, the address for all beneficial owners in this table is 333 West Sheridan Avenue Oklahoma City, Oklahoma 73102.

(2)	Devon is the ultimate parent company of Devon Gas Corporation, the sole owner of our general partner. Devon Gas Corporation is the owner of              common units and              subordinated units. Devon may, therefore, be deemed to beneficially own the units held by such entities.

The following table sets forth, as of                     , 2013, the number of shares of common stock of Devon owned by each director and named executive officers of our general partner and by all directors and executive officers of our general partners as a group:

 

Name of Beneficial Owner		Shares of Common Stock Owned Directly or Indirectly		Shares Underlying Options Exercisable Within 60 Days (1)		Total Shares of Common Stock Beneficially Owned		Percentage of Total Shares of Common Stock Beneficially Owned (2)
David A. Hager
Darryl G. Smette
Jeffrey A. Agosta
Lyndon C. Taylor
All directors and executive officers as a group (     persons)

 

*	Less than 1%.

(1)	The shares indicated represent stock options granted under Devon’s current or previous stock option plans, which are currently exercisable or which will become exercisable within 60 days of                     , 2013. Shares subject to options cannot be voted.

(2)	Based on              shares of common stock outstanding as of                     , 2013.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After the consummation of this offering, Devon will indirectly own              common units and subordinated units representing an aggregate     % limited partner interest in us as well as an 80% interest in Devon Midstream Holdings and will own and control our general partner. Devon will appoint all of the directors of our general partner, which will maintain a non-economic general partner interest in us, and Devon will be issued the incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Devon Midstream Partners, L.P. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations.

Formation Stage

The consideration received by Devon

and its affiliates for the contribution of

the assets and liabilities to us

•

common units;

 

•

subordinated units;

 

•

a non-economic general partner interest;

 

•

the incentive distribution rights; and

 

•

a cash payment of approximately $         million from the proceeds of this offering.

Operational Stage

 

Distributions of available cash to our general partner and its affiliates

We will generally make cash distributions to our unitholders, including affiliates of our general partner. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, Devon will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target distribution level.

 

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, Devon and its affiliates would receive an annual distribution of approximately $         million on their common and subordinated units.

 

Payments to our general partner and its affiliates

Our general partner and its affiliates will be entitled to reimbursement for all expenses they incur on our behalf, including salaries and employee benefit costs for employees who provide services to us, and all other necessary or appropriate expenses allocable to us or reasonably incurred by our general partner and its affiliates in connection with operating our business. The partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith.

 

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Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its non-economic general partner interest and its affiliates’ incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

 

Liquidation

If we are ever liquidated, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements Governing the Transactions

We and other parties have entered into or will enter into the various documents and agreements that will affect the offering transactions, including our acquisition of interests in Devon Midstream Holdings, the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds of this offering. These agreements will not be the result of arm’s length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from nonaffiliated third-parties. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, will be paid from the proceeds of this offering.

Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with Devon Midstream Holdings, Devon, our general partner and others. The following discussion describes provisions of the omnibus agreement. Any or all of the provisions of the omnibus agreement will be terminable by Devon at its option if our general partner is removed without cause and units held by our general partner and its affiliates are not voted in favor of that removal. The omnibus agreement will also generally terminate in the event of a change of control of us or our general partner.

Reimbursement of General and Administrative Expenses

Under the omnibus agreement, Devon will, or will cause its affiliates to, perform centralized corporate, general and administrative services for us, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. In exchange, we will reimburse Devon and its affiliates for the expenses incurred by them in providing these services. The omnibus agreement will further provide that we will reimburse Devon and its affiliates for our allocable portion of the premiums on any insurance policies covering our assets.

We will also reimburse Devon for any additional state income, margin or similar tax paid by Devon resulting from the inclusion of us (and our subsidiaries) in a combined state income, margin or similar tax report with Devon as required by applicable law. The amount of any such reimbursement will be limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with Devon.

Our Right of First Offer for Devon’s Interest in Devon Midstream Holdings

Under the omnibus agreement, Devon will be required to offer us the right to purchase its 80% limited partner interest in Devon Midstream Holdings before it can sell that interest to anyone else. We refer to our

 

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purchase right as a right of first offer. The consummation and timing of any future purchases by us of any part of Devon’s interest in Devon Midstream Holdings will depend upon, among other things, Devon’s decision to sell its interest in Devon Midstream Holdings, our ability to reach an agreement with Devon regarding the price and other terms of such purchase, compliance with our debt agreements, and our ability to obtain financing on acceptable terms. Although we will have the right of first offer to purchase Devon’s interest in Devon Midstream Holdings, we are not obligated to purchase any additional interest in Devon Midstream Holdings from Devon.

Pursuant to the omnibus agreement, Devon must give us written notice of its intent to sell all or a portion of its 80% interest in Devon Midstream Holdings specifying the fundamental terms of the proposed sale, other than the sale price. Within 45 days of receiving such notification from Devon, the conflicts committee of our general partner must notify Devon in writing whether we wish to make an offer to purchase the interest to be sold, and, if so, provide the price we are willing to pay for the interest. Thereafter, our conflicts committee and Devon will enter into good faith negotiations for a 45-day period to reach an agreement for us to purchase the interest offered for sale. If our conflicts committee and Devon cannot agree on the terms of purchase for the interest offered for sale after negotiating in good faith for the 45-day period, Devon may give us notice that it rejects our offer and will thereafter seek an alternative purchase. In the event Devon is thereafter able to obtain a good faith, binding offer to pay at least 105% of the highest purchase price (on a present value basis) we proposed or as contained in any greater written offer made by us during the 45-day negotiation period, then Devon will be free to sell the interest at such greater price. If an alternative transaction complying with the provisions set out immediately above has not been consummated by Devon within 270 days after the end of our 45-day negotiation period, the right of first offer would be reinstated and would apply to any future sale or future offer by Devon to sell all or a portion of their interest.

Indemnification

Under the omnibus agreement, Devon will indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of Devon Midstream Holdings’ assets and due to occurrences on or before the closing of this offering. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before the closing of this offering and identified prior to the third anniversary of the closing of this offering, and will be subject to an aggregate deductible of $500,000 before we are entitled to indemnification. There is no cap on the amount for which Devon will indemnify us under the omnibus agreement with respect to environmental claims once we meet the deductible, if applicable. Devon will also indemnify us for certain defects in title to the assets contributed to us and failure to obtain certain consents, licenses and permits necessary to conduct our business, including the cost of curing any such condition. Devon will also indemnify us for liabilities relating to:

 

•

the assets contributed to us, other than environmental liabilities, that arise out of the ownership or operation of the assets prior to the closing of this offering and that are asserted prior to the third anniversary of the closing of this offering;

 

•

events and conditions associated with any assets retained by Devon; and

 

•

all tax liabilities attributable to the assets contributed to us arising prior to the closing of this offering or otherwise related to Devon’s contribution of those assets to us in connection with this offering.

License of Name and Trademark

Devon will grant us a non-transferable, nonexclusive, royalty free right and license to use Devon’s trademarks and tradenames owned by Devon, and we will grant Devon a non-transferable, nonexclusive, royalty free right and license to use trademarks and tradenames owned by us. This license will terminate upon the termination of the omnibus agreement.

 

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Competition

Under our partnership agreement, Devon and its affiliates are expressly permitted to compete with us. Devon and any of its affiliates may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to purchase or construct those assets, other than our right of first offer on Devon’s 80% interest in Devon Midstream Holdings.

Contracts with Affiliates

Gas Gathering and Processing Agreements

Devon Midstream Holdings will enter into 10-year gathering and processing agreements with certain subsidiaries of Devon pursuant to which Devon Midstream Holdings will provide gathering, treating, compression, dehydration, stabilization, processing and fractionation services, as applicable, for natural gas delivered by Devon to Devon Midstream Holdings’ gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales. These agreements provide Devon Midstream Holdings with dedication of all of the natural gas owned or controlled by Devon and produced from or attributable to existing and future wells located on certain oil, natural gas and mineral leases covering lands within the acreage dedications, excluding properties previously dedicated to another natural gas gathering system not owned and operated by Devon. We expect that we will generate substantially all of our revenue for the twelve months ending September 30, 2014 pursuant to these natural gas gathering and processing agreements.

Pursuant to our gathering and processing agreements, Devon has committed to deliver specified minimum daily volumes of natural gas to our gathering systems in the Barnett, Cana-Woodford and Arkoma-Woodford Shales through December 31, 2018. These commitments include 850 MMcf/d to the Bridgeport gathering systems, 650 MMcf/d to the Bridgeport processing facility, 125 MMcf/d to the East Johnson County gathering system, 330 MMcf/d to the Cana system and 40 MMcf/d to the Northridge system.

If Devon delivers a volume of natural gas that is less than any of the minimum volume commitments, then Devon will make a deficiency payment according to the payment terms outlined in the agreements. Pursuant to these agreements, when a deficiency occurs in a calendar quarter, Devon has the right to credit any excess gathered or processed volumes from the immediately preceding quarter against the deficiency. If a deficiency payment is made in a calendar quarter, Devon has the right to use any excess gathered or processed volumes from the immediately succeeding quarter to recoup all or a portion of the deficiency payment. Additionally, the agreements provide for the reduction of the minimum volume commitments in certain instances, including the occurrence of force majeure events in excess of ten consecutive days affecting our systems.

For any production month, Devon may elect ethane rejection by providing us with a notice of election. In that event, the percentage of ethane recovered from the committed natural gas shall be based on actual recoveries that occur for such month based upon reasonable efforts to reject ethane in accordance with our operational capabilities.

Pursuant to the gathering and processing agreements, Devon Midstream Holdings will connect Devon wells to Devon Midstream Holdings’ gathering systems at its expense if the well is located within three miles of its gathering system. If Devon’s well is greater than three miles from Devon Midstream Holdings’ gathering system, then Devon Midstream Holdings has the right, but not the obligation, to connect the well at its sole expense. If Devon Midstream Holdings declines to connect the well into its gathering system, Devon shall have the right, but not the obligation, to construct the appropriate facilities from the well to a mutually agreeable point on Devon Midstream Holdings’ gathering system where Devon Midstream Holdings will provide metering facilities at the point of interconnection. If neither Devon Midstream Holdings nor Devon elects to connect any such well to a Devon Midstream Holdings’ gathering system, then Devon Midstream Holdings shall promptly provide Devon with a release from this agreement to the extent it covers such well.

 

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Devon is entitled to firm service. If capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, Devon Midstream Holdings will take delivery of as much Devon natural gas as is permitted in accordance with applicable law. Subject to certain limitations, Devon Midstream Holdings may commingle Devon’s natural gas with the natural gas of third parties.

We recognize that certain quantities of Devon’s natural gas will be used to fuel or power compression equipment and for operational purposes, and that natural gas may be lost, gained, and/or unaccounted for on Devon Midstream Holdings’ gathering systems. Devon will provide Devon Midstream Holdings with its share of such fuel and natural gas lost, gained, and/or unaccounted for in proportion to all sources of natural gas into Devon Midstream Holdings’ gathering systems and Devon shall reimburse Devon Midstream Holdings with its share of power costs in proportion to all sources of power required for its systems.

The gathering and processing agreements are fee-based, and Devon Midstream Holdings is paid a specified fee per MMBtu for natural gas received on Devon Midstream Holdings’ gathering systems and specified fees for natural gas received as well as processed. The particular fees, all of which are subject to an automatic annual inflation escalator at the beginning of each year, differ from one system to another and do not contain a fee redetermination clause.

In the event that Devon sells, transfers or otherwise disposes to a third party properties within the acreage dedications in our Barnett, Cana-Woodford or Arkoma-Woodford Shales, such third party will be subject to the existing gas gathering and processing agreement with Devon.

Devon Midstream Holdings Partnership Agreement and Devon Midstream Holdings GP, LLC Limited Liability Company Agreement

Devon, on behalf of Devon Midstream Holdings GP, LLC as its ultimate parent, has entered into an agreement of limited partnership for Devon Midstream Holdings. This agreement governs the ownership and management of Devon Midstream Holdings, designates our wholly-owned subsidiary, Devon Midstream Holdings GP, LLC as the general partner of Devon Midstream Holdings, and provides for quarterly distributions of available cash to the limited and general partner, as determined by us as the ultimate parent of the general partner of Devon Midstream Holdings.

Devon Midstream Holdings’ partnership agreement provides that the amount of cash reserves for future maintenance capital expenditures, working capital and other matters and the amount of quarterly cash distributions to Devon Midstream Holdings’ partners will be determined by us as the ultimate parent of Devon Midstream Holdings GP, LLC. Effectively, this decision will be made by the board of directors of our general partner. This approval is also required for the following actions relating to Devon Midstream Holdings:

 

•

effecting any merger or consolidation involving Devon Midstream Holdings;

 

•

effecting any sale or exchange of all or substantially all of Devon Midstream Holdings’ assets;

 

•

dissolving or liquidating Devon Midstream Holdings;

 

•

creating or causing to exist any consensual restriction on the ability of Devon Midstream Holdings’ or its subsidiaries to make distributions, pay any indebtedness, make loans or advances or transfer assets to us or our subsidiaries;

 

•

settling or compromising any claim, dispute or litigation directly against, or otherwise relating to indemnification by Devon Midstream Holdings of, any of the directors or officers of Devon Midstream Holdings GP, LLC; or

 

•

issuing additional partnership interests in Devon Midstream Holdings.

 

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Procedures for Review, Approval and Ratification of Transactions with Related Persons

The board of directors of our general partner will adopt a related party transactions policy in connection with the closing of this offering that will provide that the board of directors of our general partner or its authorized committee will review on at least a quarterly basis all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics will provide that our management will make all reasonable efforts to cancel or annul the transaction.

The related party transactions policy will provide that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The related party transactions policy described above will be adopted in connection with the closing of this offering, and as a result the transactions described above were not reviewed under such policy.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Devon, on the one hand, and us and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner that is in the best interests to its owners. At the same time, our general partner has a duty to manage our partnership in a manner it believes is in our best interests. Our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

 

•

approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; or

 

•

approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates.

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. When our partnership agreement requires someone to act in good faith, it requires that person to subjectively believe that he is acting in a manner that is in the best interests of the partnership or meets the standard otherwise specified in our partnership agreement. Please read “Management—Committees of the Board of Directors—Conflicts Committee” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others:

The directors and officers of our general partner have a fiduciary duty to make decisions in the best interests of the owners of our general partner, which may be contrary to our interests.

Because the officers and certain directors of our general partner are also directors or officers of affiliates of our general partner, including our general partner, they have fiduciary duties to our general partner that may cause them to pursue business strategies that disproportionately benefit our general partner or which otherwise are not in our best interests.

 

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Our general partner is allowed to take into account the interests of parties other than us in exercising certain rights under our partnership agreement.

Our partnership agreement contains provisions that permissibly reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation.

Our general partner and its affiliate compete with us, and will have the ability to compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us, and our general partner or its affiliates may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to acquire those assets, other than our right of first offer on Devon’s 80% interest in Devon Midstream Holdings. We share our management team with our general partner, and the shared management team is under no obligation to offer new business opportunities to us before offering them to our general partner, which could have a material adverse impact on our ability to maintain or grow our business.

Under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

Our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement provides that:

 

•

our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

 

•

our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or, in the case of a criminal matter, acted with knowledge that its conduct was unlawful; and

 

•

in resolving conflicts of interest, it will be presumed that in making its decision the general partner, the board of directors of the general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. Please read “—Fiduciary Duties.”

 

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Common unitholders have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, are not and will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s-length negotiations. Our general partner will determine, in good faith, the terms of any of such future transactions.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval, necessary or appropriate to conduct our business including, but not limited to, the following actions:

 

•

expending, lending, or borrowing money, assuming, guaranteeing, or otherwise contracting for, indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our securities, and incurring any other obligations;

 

•

preparing and transmitting tax, regulatory and other filings, periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

 

•

acquiring, disposing, mortgaging, pledging, encumbering, hypothecating, or exchanging our assets or merging or otherwise combining us with or into another person;

 

•

negotiating, executing and performing contracts, conveyance or other instruments;

 

•

distributing cash;

 

•

selecting or dismissing employees and agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

 

•

maintaining insurance for our benefit;

 

•

forming, acquiring an interest in, and contributing property and loaning money to, any further limited partnerships, joint ventures, corporations, limited liability companies or other relationships;

 

•

controlling all matters affecting our rights and obligations, including bringing and defending actions at law or in equity or otherwise litigating, arbitrating or mediating, and incurring legal expense and settling claims and litigation;

 

•

indemnifying any person against liabilities and contingencies to the extent permitted by law;

 

•

purchasing, selling or otherwise acquiring or disposing of our partnership interests, or issuing additional options, rights, warrants, appreciation rights, phantom or tracking interests relating to our partnership interests; and

 

•

entering into agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Please read “The Partnership Agreement” for information regarding the voting rights of unitholders.

 

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Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders or accelerate the right to convert subordinated units.

The amount of cash that is available for distribution to unitholders is affected by decisions of our general partner regarding such matters as:

 

•

amount and timing of asset purchases and sales;

 

•

cash expenditures;

 

•

borrowings;

 

•

entry into and repayment of current and future indebtedness;

 

•

issuance of additional units; and

 

•

the creation, reduction or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

 

•

enabling affiliates of our general partner to receive distributions on any subordinated units held by them or the incentive distribution rights; or

 

•

hastening the expiration of the subordination period.

In addition, our general partner may use an amount, initially equal to $         million, which would not otherwise constitute operating surplus, in order to permit the payment of distributions on subordinated units and the incentive distribution rights. All of these actions may affect the amount of cash or equity distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “How We Make Distributions To Our Partners.”

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make such distribution on all outstanding units. Please read “How We Make Distributions To Our Partners—Operating Surplus and Capital Surplus—Operating Surplus.”

We will reimburse our general partner and its affiliates for expenses.

We will reimburse our general partner and its affiliates, including Devon, for costs incurred in managing and operating us. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us in good faith, and it will charge on a fully allocated cost basis for services provided to us. Our omnibus agreement and services agreement with Devon also address our payment of annual amounts to, and our reimbursement of, our general partner and its affiliates for these costs and services. Please read “Certain Relationships and Related Party Transactions.”

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets and not against our general partner or its assets or any affiliate of our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained terms that are more favorable without the limitation on liability.

Common units are subject to our general partner’s call right.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at the market price calculated in accordance with the terms of our partnership agreement. As a result, you may be required to sell your common

 

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units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

We may not choose to retain separate counsel for ourselves or for the holders of common units.

The attorneys, independent accountants and others who perform services for us have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of the board of directors of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflict committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict, although we may choose not to do so.

The holder or holders of our incentive distribution rights may elect to cause us to issue common units to it in connection with a resetting of incentive distribution levels without the approval of our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

The holder or holders of a majority of our incentive distribution rights (initially Devon) have the right, at any time when there are no subordinated units outstanding and they have received incentive distributions at the highest level to which they are entitled (50.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution levels at the time of the exercise of the reset election. Following a reset election, a baseline distribution amount will be calculated equal to an amount equal to the prior cash distribution per common unit for the fiscal quarter immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

We anticipate that Devon would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per unit without such conversion. However, Devon may transfer the incentive distribution rights at any time. It is possible that Devon or a transferee could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when the holders of the incentive distribution rights expect that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, the holders of the incentive distribution rights may be experiencing, or may expect to experience, declines in the cash distributions it receives related to the incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for them to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to the holders of the incentive distribution rights in connection with resetting the target distribution levels. Please read “How We Make Distributions To Our Partners—Devon’s Right to Reset Incentive Distribution Levels.”

Fiduciary Duties

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

 

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Our partnership agreement contains various provisions that eliminate and replace the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owner. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. Replacing the fiduciary duty standards in this manner benefits our general partner by enabling it to take into consideration all parties involved in the proposed action. Replacing the fiduciary duty standards also strengthens the ability of our general partner to attract and retain experienced and capable directors. Replacing the fiduciary duty standards represents a detriment to our public unitholders because it restricts the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permits our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

 

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

Partnership agreement modified

standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith,” meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other standard under applicable law, other than the implied contractual covenant of good faith and fair dealing. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards replace the obligations to which our general partner would otherwise be held.

 

If our general partner does not obtain approval from the conflicts committee of the board of directors of our general partner or our common unitholders, excluding any such units owned by our general partner or its affiliates, and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, its board, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought

 

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by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards replace the obligations to which our general partner would otherwise be held.

 

Rights and remedies of unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

Partnership agreement modified

standards

The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its good faith reliance on the provisions of our partnership agreement.

By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

 

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units and subordinated units in and to partnership distributions, please read this section and “How We Make Distributions To Our Partners.” For a description of other rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

Computershare Trust Company, N.A. will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following, which must be paid by unitholders:

 

•

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

•

special charges for services requested by a holder of a common unit; and

 

•

other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor is appointed or has not accepted its appointment within 30 days of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common unit shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

 

•

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

•

automatically becomes bound by the terms and conditions of our partnership agreement; and

 

•

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

 

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We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and any transfers are subject to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

 

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

•

with regard to distributions of available cash, please read “How We Make Distributions To Our Partners”;

 

•

with regard to the duties of, and standard of care applicable to, our general partner, please read “Conflicts of Interest and Fiduciary Duties”;

 

•

with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units”; and

 

•

with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Consequences.”

Organization and Duration

Devon Midstream Partners, L.P. was organized in September 2013 and will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of buying, gathering, compressing, treating, processing and selling natural gas and fractionating and selling NGLs, our general partner may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to Devon in respect of its incentive distribution rights. For a description of these cash distribution provisions, please read “How We Make Distributions To Our Partners.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

 

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Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. Matters that require the approval of a “unit majority” require:

 

•

during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and

 

•

after the subordination period, the approval of a majority of the common units, voting as a single class.

In voting their common and subordinated units, affiliates of our general partner will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

The incentive distribution rights may be entitled to vote in certain circumstances.

 

Issuance of additional units

No approval right.

Amendment of the partnership

agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of

all or substantially all of our assets

Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership

Unit majority. Please read “—Dissolution.”

Continuation of our business upon

dissolution

Unit majority. Please read “—Dissolution.”

 

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to September 30, 2023 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

 

Removal of our general partner

Not less than 66 2⁄3% of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of our general partner

interest

No approval right. Please read “—Transfer of General Partner Interest.”

Transfer of incentive distribution

rights

No approval right. Please read “—Transfer of Subordinated Units and Incentive Distribution Rights.”

Transfer of ownership interests in our

general partner

No approval right. Please read “—Transfer of Ownership Interests in the General Partner.”

 

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If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

•

arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

•

brought in a derivative manner on our behalf;

 

•

asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

•

asserting a claim arising pursuant to any provision of the Delaware Act; or

 

•

asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other Delaware courts) in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

 

•

to remove or replace our general partner;

 

•

to approve some amendments to our partnership agreement; or

 

•

to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

 

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Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Following the completion of this offering, we expect that our subsidiaries will conduct business in two states and we may have subsidiaries that conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, we issue partnership interests to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

 

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Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

 

•

enlarge the obligations of any limited partner without his consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

•

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, our general partner and its affiliates will own approximately     % of our outstanding common and subordinated units.

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 

•

a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

•

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

•

a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed);

 

•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

•

an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or the right to acquire partnership interests;

 

•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

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•

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

•

any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

 

•

a change in our fiscal year or taxable year and related changes;

 

•

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

•

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

 

•

do not adversely affect the limited partners, considered as a whole, or any particular class of limited partners, in any material respect;

 

•

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

•

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

•

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that would reduce or increase the voting percentage required to take any action other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced or increased. Any amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased. For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

 

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Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20% of our outstanding partnership interests (other than incentive distribution rights) immediately prior to the transaction. If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

 

•

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

•

there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

•

the entry of a decree of judicial dissolution of our partnership; or

 

•

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

•

the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

•

neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

 

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Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “How We Make Distributions To Our Partners—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to September 30, 2023 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after September 30, 2023, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interest.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 ²⁄₃% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33 ¹⁄₃% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own     % of our outstanding limited partner units, including all of our subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist:

 

•

all subordinated units held by any person who did not, and whose affiliates did not, vote any units in favor of the removal of the general partner, will immediately and automatically convert into common units on a one-for-one basis, provided such person is not an affiliate of the successor general partner; and

 

•

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general

 

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partner and its affiliates for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest and the incentive distribution rights of the departing general partner and its affiliates for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and all its and its affiliates’ incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its non-economic general partner interest to another person without the approval of any other partner. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Transfer of Ownership Interests in the General Partner

At any time, the owners of our general partner may sell or transfer all or part of its non-economic ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Transfer of Subordinated Units and Incentive Distribution Rights

By transfer of subordinated units or incentive distribution rights in accordance with our partnership agreement, each transferee of subordinated units or incentive distribution rights will be admitted as a limited partner with respect to the subordinated units or incentive distribution rights transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

•

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

•

automatically becomes bound by the terms and conditions of our partnership agreement; and

 

•

gives the consents, waivers and approvals contained in our partnership agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

We may, at our discretion, treat the nominee holder of subordinated units or incentive distribution rights as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

 

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Subordinated units and incentive distribution rights are securities and any transfers are subject to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner for the transferred subordinated units or incentive distribution rights.

Until a subordinated unit or incentive distribution right has been transferred on our books, we and the transfer agent may treat the record holder of the unit or right as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove our general partner or from otherwise changing our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read “—Meetings; Voting.”

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or beneficial owners or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:

 

•

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

•

the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date that is three days before the date the notice is mailed.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units.”

Non-Taxpaying Holders; Redemption

To avoid any adverse effect on the maximum applicable rates chargeable to customers by us or any of our future subsidiaries, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by our subsidiaries, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

•

obtain proof of the federal income tax status of our limited partners (and their owners, to the extent relevant); and

 

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•

permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

•

obtain proof of the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant); and

 

•

permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by the general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

 

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Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Voting Rights of Incentive Distribution Rights

If a majority of the incentive distribution rights are held by our general partner and its affiliates, the holders of the incentive distribution rights will have no right to vote in respect of such rights on any matter, unless otherwise required by law, and the holders of the incentive distribution rights shall be deemed to have approved any matter approved by our general partner.

If less than a majority of the incentive distribution rights are held by our general partner and its affiliates, the incentive distribution rights will be entitled to vote on all matters submitted to a vote of unitholders, other than amendments and other matters that our general partner determines do not adversely affect the holders of the incentive distribution rights in any material respect. On any matter in which the holders of incentive distribution rights are entitled to vote, such holders will vote together with the subordinated units, prior to the end of the subordination period, or together with the common units, thereafter, in either case as a single class, and such incentive distribution rights shall be treated in all respects as subordinated units or common units, as applicable, when sending notices of a meeting of our limited partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our partnership agreement. The relative voting power of the holders of the incentive distribution rights and the subordinated units or common units, depending on which class the holders of incentive distribution rights are voting with, will be set in the same proportion as cumulative cash distributions, if any, in respect of the incentive distribution rights for the four consecutive quarters prior to the record date for the vote bears to the cumulative cash distributions in respect of such class of units for such four quarters.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

•

our general partner;

 

•

any departing general partner;

 

•

any person who is or was an affiliate of our general partner or any departing general partner;

 

•

any person who is or was a director, officer, managing member, manager, general partner, fiduciary or trustee of us or our subsidiaries, an affiliate of us or our subsidiaries or any entity set forth in the preceding three bullet points;

 

•

any person who is or was serving as director, officer, managing member, manager, general partner, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries at the request of our general partner or any departing general partner or any of their affiliates, excluding any such person providing, on a fee-for-service basis, trustee, fiduciary of custodial services; and

 

•

any person designated by our general partner because such person’s status, service or relationship expose such person to potential claims or suits relating to our or our subsidiaries’ business and affairs.

 

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Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

 

•

a current list of the name and last known address of each record holder;

 

•

copies of our partnership agreement, our certificate of limited partnership, and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which our partnership agreement, our certificate of limited partnership and all amendments thereto have been executed;

 

•

information regarding the status of our business and financial condition (provided that obligation shall be satisfied to the extent the limited partner is furnished our most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the SEC pursuant to Section 13(a) of the Exchange Act); and

 

•

any other information regarding our affairs that our general partner determines is just and reasonable.

 

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Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in our partnership interests, do not have rights to receive information from us or any of the persons we indemnify as described above under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other limited partner interests proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts.

In addition, in connection with this offering, we expect to enter into a registration rights agreement with our general partner. Pursuant to the registration rights agreement, we will be required to file a registration statement to register the common units and subordinated units issued to our general partner and the common units issuable upon the conversion of the subordinated units upon request of our general partner. In addition, the registration rights agreement gives our general partner piggyback registration rights under certain circumstances. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution and allocation of expenses. These registration rights are transferable to affiliates of our general partner and, in certain circumstances, to third parties. Please read “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, our general partner and its affiliates will hold an aggregate of             common units and             subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. For information regarding the conversion of subordinated units into common units prior to the end of the subordination period, please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.” The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

Our common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

•

1% of the total number of the securities outstanding; or

 

•

the average weekly reported trading volume of our common units for the four weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned our common units for at least six months (provided we are in compliance with the current public information requirement), or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144, subject only to the current public information requirement. After beneficially owning Rule 144 restricted units for at least one year, a person who is not deemed to have been an affiliate of ours at any time during the 90 days preceding a sale would be entitled to freely sell those common units without regard to the public information requirements, volume limitations, manner of sale provisions and notice requirements of Rule 144.

Issuance of Additional Interests

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders at any time. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Interests.”

Registration Rights

Under our partnership agreement and the registration rights agreement that we expect to enter into, our general partner and its affiliates will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any units that they hold. Subject to the terms and conditions of the partnership agreement and the registration rights agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units to require registration of any of these units and to include any of these units in a registration by us of other units, including units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors, and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discount. Except as described below, our general partner and its affiliates may sell their units in private transactions at any time, subject to compliance with applicable laws.

 

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Lock-up Agreement

We, Devon, our general partner and the directors and executive officers of our general partner have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. Please read “Underwriting” for a description of these lock-up provisions.

Prior to the completion of this offering, we expect to adopt a new long-term incentive plan (the “Long-Term Incentive Plan”). If adopted, we intend to file a registration statement on Form S-8 under the Securities Act to register common units issuable under the Long-Term Incentive Plan. This registration statement on Form S-8 is expected to be filed following the effective date of the registration statement of which this prospectus is a part and will be effective upon filing. Accordingly, common units issued under the Long-Term Incentive Plan will be eligible for resale in the public market without restriction after the effective date of the Form S-8 registration statement, subject to applicable vesting requirements, Rule 144 limitations applicable to affiliates and the lock-up restrictions described above.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES

This section summarizes the material federal income tax consequences that may be relevant to prospective unitholders and is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder (the “Treasury Regulations”), and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below, possibly on a retroactive basis. Unless the context otherwise requires, references in this section to “we” or “us” are references to Devon Midstream Partners, L.P. and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this section does not address all federal income tax matters that affect us or our unitholders and does not describe the application of the alternative minimum tax that may be applicable to certain unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), who have the U.S. dollar as their functional currency, who use the calendar year as their taxable year, and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, (including entities treated as partnerships for federal income tax purposes), estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, IRAs, employee benefit plans, real estate investment trusts or mutual funds. Accordingly, we encourage each unitholder to consult the unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences particular to that unitholder resulting from ownership or disposition of units and potential changes in applicable tax laws.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or a court. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for units and the prices at which our units trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution. Furthermore, the tax consequences of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which may be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (i) the treatment of a unitholder whose units are the subject of a securities loan (e.g., a loan to a short seller to cover a short sale of units) (please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Units—Allocations Between Transferors and Transferees”); and (iii) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We expect to be treated as a partnership for U.S. federal income tax purposes and, therefore, generally will not be liable for entity-level federal income taxes. Instead, as described below, each of our unitholders will take into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if we make no cash distributions to the unitholder.

Section 7704 of the Code generally provides that publicly-traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year

 

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it is publicly-traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). Qualifying income includes income and gains derived from the transportation, storage, processing and marketing of certain natural resources, including crude oil, natural gas and products thereof, as well as other types of income such as interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than     % of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership and our partnership and limited liability company subsidiaries will be disregarded as entities separate from us for federal income tax purposes. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied in rendering its opinion include, without limitation:

(a) Neither we nor any of our partnership or limited liability company subsidiaries has elected or will elect to be treated as a corporation for federal income tax purposes;

(b) For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code; and

(c) Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with oil, natural gas, or products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then as distributing that stock to our unitholders in liquidation. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

The present federal income tax treatment of publicly-traded partnerships, including us, or an investment in our common units may be modified by administrative or legislative action or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly-traded partnerships. One such legislative proposal would have eliminated the Qualifying Income Exception upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Our taxation as a corporation would materially reduce the cash available for distribution to unitholders and thus would likely substantially reduce the value of our units. Any distribution made to a unitholder at a time we are treated as a corporation would be (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in its units, and thereafter (iii) taxable capital gain.

 

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The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of securities loans, please read “—Tax Consequences of Unit Ownership—Treatment of Securities Loans.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under their particular circumstances.

Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its federal income tax return each year its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution.

Basis of Units

A unitholder’s tax basis in its units initially will be the amount paid for those units increased by the unitholder’s initial allocable share of our nonrecourse liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by the amount of all distributions to the unitholder, the unitholder’s share of our losses, and any decreases in the unitholder’s share of our nonrecourse liabilities and its share of our expenditures that are neither deductible nor required to be capitalized. The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests.

Ratio of Taxable Income to Distributions

We estimate that a purchaser of units in this offering who owns those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2016, will be allocated, on a cumulative basis, an amount of federal taxable income that will be     % or less of the cash distributed on those units with respect to that period. These estimates are based upon the assumption that earnings from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and which could be changed or with which the IRS could disagree. Accordingly, we cannot assure that these estimates will prove to be correct, and our counsel has not opined on the accuracy of such estimates. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could affect the value of units. For example, the ratio of taxable income to cash distributions to a purchaser of units in this offering would be higher, and perhaps substantially higher, than our estimate with respect to the period described above if:

We distribute less cash than we have assumed in making this projection; or

 

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we make a future offering of units and use the proceeds of the offering in a manner that does not produce additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes during such period or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Treatment of Distributions

Distributions by us to a unitholder generally will not be taxable to the unitholder, unless such distributions exceed the unitholder’s tax basis in its units, in which case the unitholder generally will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units may decrease the unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please read “—Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution as a result of the reallocation of our liabilities described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation and depletion recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for a portion of the non-pro rata distribution. This deemed exchange generally will result in the unitholder’s recognition of ordinary income in an amount equal to the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

A unitholder may not be entitled to deduct the full amount of loss we allocate to it because its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its units, and (ii) in the case of a unitholder that is an individual, estate, trust or certain types of closely-held corporations, the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (x) any portion of that basis attributable to the unitholder’s share of our liabilities, (y) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar arrangement and (z) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment. A unitholder subject to the at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions deemed to result from a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year.

Losses disallowed to a unitholder or recaptured as a result of the basis or at risk limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used, and will not be available to offset a unitholder’s salary or active business income.

 

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In addition to the basis and at risk limitations, a passive activity loss limitation generally limits the deductibility of losses incurred by individuals, estates, trusts, some closely-held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any passive losses we generate will be available to offset only passive income generated by us. Passive losses that exceed a unitholder’s share of passive income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive loss rules generally are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” generally is limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

interest on indebtedness allocable to property held for investment;

interest expense allocated against portfolio income; and

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent allocable against portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Net investment income generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly-traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder or our general partner, we are authorized to treat the payment as a distribution of cash to the relevant unitholder or general partner. Where the tax is payable on behalf of all unitholders or we cannot determine the specific unitholder on whose behalf the tax is payable, we are authorized to treat the payment as a distribution to all current unitholders. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Allocation of Income, Gain, Loss and Deduction

Our items of income, gain, loss and deduction generally will be allocated amongst our unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or we make incentive distributions, gross income will be allocated to the recipients to the extent of these distributions.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code (or the principles of Section 704(c) of the Code) to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units (a “Book-Tax Disparity”). As a result, the federal income tax burden associated with any Book-Tax

 

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Disparity immediately prior to an offering generally will be borne by our partners holding interests in us prior to such offering. In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Code to eliminate a Book-Tax Disparity, will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has “substantial economic effect.” In any other case, a partner’s share of an item will be determined on the basis of the partner’s interest in us, which will be determined by taking into account all the facts and circumstances, including (i) the partner’s relative contributions to us, (ii) the interests of all the partners in profits and losses, (iii) the interest of all the partners in cash flow and (iv) the rights of all the partners to distributions of capital upon liquidation. Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations of income, gain, loss or deduction under our partnership agreement will be given effect for federal income tax purposes.

Treatment of Securities Loans

A unitholder whose units are loaned (for example, a loan to “short seller” to cover a short sale of units) may be treated as having disposed of those units. If so, such 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. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the lending unitholder, and (ii) any cash distributions received by the unitholder as to those units may be treated as ordinary taxable income.

Due to a lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder that enters into a securities loan with respect to its units. Unitholders desiring to assure their status as partners and avoid the risk of income recognition from a loan of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please read “—Disposition of Units—Recognition of Gain or Loss.”

Tax Rates

Under current law, the highest marginal federal income tax rates for individuals applicable to ordinary income and long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% net investment income tax (“NIIT”) applies to certain net investment income earned by individuals, estates, and trusts. For these purposes, net investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if married filing separately) or $200,000 (if the unitholder is unmarried or in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We will make the election permitted by Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchasers of our units under Section 743(b) of the Code. That election is irrevocable without

 

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the consent of the IRS. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase, and the adjustment will reflect the purchase price paid. The Section 743(b) adjustment does not apply to a person who purchases units directly from us.

Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with applicable Treasury Regulations. A literal application of Treasury Regulations governing a 743(b) adjustment attributable to properties depreciable under Section 167 of the Code may give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing from other unitholders. If we have any such properties, we intend to adopt methods employed by other publicly-traded partnerships to preserve the uniformity of units, even if inconsistent with existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach. Please read “—Uniformity of Units.”

The IRS may challenge the positions we adopt with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We will use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in its tax return its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of those assets. If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation and depletion deductions previously taken, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

 

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The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discounts and commissions we incur will be treated as syndication expenses. Please read “Disposition of Units—Recognition of Gain or Loss.”

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis in the units sold. A unitholder’s amount realized generally will equal the sum of the cash and the fair market value of other property it receives plus its share of our nonrecourse liabilities with respect to the units sold. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, such as depreciation or depletion recapture and our “inventory items,” regardless of whether such inventory item is substantially appreciated in value. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and capital gain or loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

For purposes of calculating gain or loss on the sale of units, the unitholder’s adjusted tax basis will be adjusted by its allocable share of our income or loss in respect of its units for the year of the sale. Furthermore, as described above, the IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all of those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed in the paragraph above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, it may designate specific units sold for purposes of determining the holding period of the units transferred. A unitholder

 

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electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” financial position, including a partnership interest with respect to which gain would be recognized if it were sold, assigned or terminated at its fair market value, in the event the taxpayer or a related person enters into:

 

•

a short sale;

 

•

an offsetting notional principal contract; or

 

•

a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is authorized to issue Treasury Regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the final Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses could be reallocated among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells or purchases any of its units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction in

 

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the case of a seller). Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have “constructively” terminated as a partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than the calendar year, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 generally would require that we file two tax returns for one fiscal year thereby increasing our administration and tax preparation costs. However, pursuant to an IRS relief procedure the IRS may allow a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. Following a constructive termination, we would be required to make new tax elections, including a new election under Section 754 of the Code, and the termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination may either accelerate the application of, or subject us to, any tax legislation enacted before the termination that would not otherwise have been applied to us as a continuing as opposed to a terminating partnership.

Uniformity of Units

Because we cannot match transferors and transferees of units and other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements. Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

Our partnership agreement permits our general partner to take positions in filing our tax returns that preserve the uniformity of our units. These positions may include reducing the depreciation, amortization or loss deductions to which a unitholder would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. Vinson & Elkins L.L.P. is unable to opine as to the validity of such filing positions.

A unitholder’s basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans and other tax-exempt organizations as well as by non-resident alien individuals, non-U.S. corporations and other non-U.S. persons (collectively, “Non-U.S. Unitholders”) raises

 

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issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders that are tax-exempt entities or non-U.S. unitholders should consult their tax advisors before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-U.S. unitholders are taxed by the United States on income effectively connected with the conduct of a U.S. trade or business (“effectively connected income”) and on certain types of U.S.-source non-effectively connected income (such as dividends), unless exempted or further limited by an income tax treaty will be considered to be engaged in business in the United States because of their ownership of our units. Furthermore, is it probable that they will be deemed to conduct such activities through permanent establishments in the United States within the meaning of applicable tax treaties. Consequently, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax on their share of our net income or gain in a manner similar to a taxable U.S. unitholder. Moreover, under rules applicable to publicly-traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a non-U.S. unitholder classified as a corporation will be treated as engaged in a United States trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain as adjusted for changes in the foreign corporation’s “U.S. net equity” to the extent reflected in the corporation’s effectively connected earnings and profits. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A non-U.S. unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the non-U.S. unitholder. Under a ruling published by the IRS interpreting the scope of “effectively connected income,” gain recognized by a non-U.S. person from the sale of its interest in a partnership that is engaged in a trade or business in the United States will be considered to be effectively connected with a U.S. trade or business. Thus, part or all of a non-U.S. unitholder’s gain from the sale or other disposition of its units may be treated as effectively connected with a unitholder’s indirect U.S. trade or business constituted by its investment in us. Moreover, under the Foreign Investment in Real Property Tax Act, a non-U.S. unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or indirectly constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of our worldwide real property interests and our other assets used or held for use in a trade or business consisted of U.S. real property interests (which include U.S. real estate (including land, improvements, and certain associated personal property) and interests in certain entities holding U.S. real estate) at any time during the shorter of the period during which such unitholder held the units or the 5-year period ending on the date of disposition. More than 50% of our assets may consist of U.S. real property interests. Therefore, non-U.S. unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take

 

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various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to all of the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

The IRS may audit our federal income tax information returns. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully challenge the positions we adopt, and such a challenge could adversely affect the value of the units. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and may result in an audit of the unitholder’s own return. Any audit of a unitholder’s return could result in adjustments unrelated to our returns.

Publicly-traded partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings of the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review may go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

(1) the name, address and taxpayer identification number of the beneficial owner and the nominee;

(2) a statement regarding whether the beneficial owner is:

(a) a non-U.S. person;

(b) a non-U.S. government, an international organization or any wholly-owned agency or instrumentality of either of the foregoing; or

(c) a tax-exempt entity;

(3) the amount and description of units held, acquired or transferred for the beneficial owner; and

(4) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

 

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Accuracy-Related Penalties

Certain penalties may be imposed as a result of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion. We do not anticipate that any accuracy related penalties will be assessed against us.

State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders may be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property now or in the future or in which the unitholder is a resident. We currently conduct business or own property in Texas and Oklahoma. Texas does not impose a personal income tax on individuals, but does impose an income tax on corporations and other entities. Oklahoma imposes a personal income tax on individuals as well as on corporations and other entities. In addition, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. We strongly recommend that each prospective unitholder consult, and depend upon, its own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and non-U.S., as well as U.S. federal tax returns that may be required of it. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, alternative minimum tax or non-U.S. tax consequences of an investment in us.

 

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INVESTMENT BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Internal Revenue Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

 

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

 

•

whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material U.S. Federal Income Tax Consequences—Tax-Exempt Organizations and Other Investors.”

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans from engaging in specified transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

(i) the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

(ii) the entity is an “operating company”—i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

(iii) there is no significant investment by benefit plan investors, which is defined to mean that less than 20% of the value of each class of equity interest is held by the employee benefit plans referred to above.

Plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

 

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UNDERWRITING

Merrill Lynch, Pierce, Fenner & Smith Incorporated and Barclays Capital Inc. are acting as representatives of each of the underwriters named below. Subject to the terms and conditions set forth in an underwriting agreement among us and the underwriters, we have agreed to sell to the underwriters, and each of the underwriters has agreed, severally and not jointly, to purchase from us, the number of common units set forth opposite its name below.

 

Underwriter		Number of Common Units
Merrill Lynch, Pierce, Fenner & Smith                       Incorporated
Barclays Capital Inc.
Total

Subject to the terms and conditions set forth in the underwriting agreement, the underwriters have agreed, severally and not jointly, to purchase all of the common units sold under the underwriting agreement if any of these common units are purchased. If an underwriter defaults, the underwriting agreement provides that the purchase commitments of the nondefaulting underwriters may be increased or the underwriting agreement may be terminated.

We have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make in respect of those liabilities.

The underwriters are offering the common units, subject to prior sale, when, as and if issued to and accepted by them, subject to approval of legal matters by their counsel, including the validity of the common units, and other conditions contained in the underwriting agreement, such as the receipt by the underwriters of officer’s certificates and legal opinions. The underwriters reserve the right to withdraw, cancel or modify offers to the public and to reject orders in whole or in part.

Commissions and Discounts

The representatives have advised us that the underwriters propose initially to offer the common units to the public at the public offering price set forth on the cover page of this prospectus and to dealers at that price less a concession not in excess of $         per common unit. After the initial offering, the public offering price, concession or any other term of the offering may be changed.

The following table shows the public offering price, underwriting discount and proceeds before expenses to us. The information assumes either no exercise or full exercise by the underwriters of their option to purchase additional common units.

 

Per Common Unit

Without Option

With Option

Public offering price

$

$

$

Underwriting discount (1)

$

$

$

Proceeds, before expenses, to Devon Midstream Partners, L.P.

$

$

$

 

 

(1)	Excludes a fixed aggregate structuring fee of approximately $1.2 million payable to Merrill Lynch, Pierce, Fenner & Smith Incorporated and Barclays Capital Inc. for the evaluation, analysis and structuring of our partnership.

 

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The expenses of the offering, not including the underwriting discount, are estimated at $         and are payable by us.

Option to Purchase Additional Common Units

We have granted an option to the underwriters, exercisable for 30 days after the date of this prospectus, to purchase up to              additional common units at the public offering price, less the underwriting discount. If the underwriters exercise this option, each will be obligated, subject to conditions contained in the underwriting agreement, to purchase a number of additional common units proportionate to that underwriter’s initial amount reflected in the above table.

No Sales of Similar Securities

We, our executive officers and directors and our other existing security holders have agreed not to sell or transfer any common units or securities convertible into, exchangeable for, exercisable for, or repayable with common units, for 180 days after the date of this prospectus without first obtaining the written consent of the representatives. Specifically, we and these other persons have agreed, with certain limited exceptions, not to directly or indirectly

 

•

offer, pledge, sell or contract to sell any common units,

 

•

sell any option or contract to purchase any common units,

 

•

purchase any option or contract to sell any common units,

 

•

grant any option, right or warrant for the sale of any common units,

 

•

lend or otherwise dispose of or transfer any common units,

 

•

request or demand that we file a registration statement related to the common units, or

 

•

enter into any swap or other agreement that transfers, in whole or in part, the economic consequence of ownership of any common units whether any such swap or transaction is to be settled by delivery of common units or other securities, in cash or otherwise.

This lock-up provision applies to common units and to securities convertible into or exchangeable or exercisable for or repayable with common units. It also applies to common units owned now or acquired later by the person executing the agreement or for which the person executing the agreement later acquires the power of disposition. In the event that either (x) during the last 17 days of the lock-up period referred to above, we issue an earnings release or material news or a material event relating to us occurs or (y) prior to the expiration of the lock-up period, we announce that we will release earnings results or become aware that material news or a material event will occur during the 16-day period beginning on the last day of the lock-up period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

New York Stock Exchange Listing

We expect the common units to be approved for listing on the New York Stock Exchange under the symbol “DVNM.” In order to meet the requirements for listing on that exchange, the underwriters have undertaken to sell a minimum number of common units to a minimum number of beneficial owners as required by that exchange.

Before this offering, there has been no public market for our common units. The initial public offering price will be determined through negotiations among us and the representatives. In addition to prevailing market conditions, the factors to be considered in determining the initial public offering price are:

 

•

the valuation multiples of publicly-traded companies that the representatives believe to be comparable to us,

 

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•

our financial information,

 

•

the history of, and the prospects for, our company and the industry in which we compete,

 

•

an assessment of our management, its past and present operations, and the prospects for, and timing of, our future revenues,

 

•

the present state of our development, and

 

•

the above factors in relation to market values and various valuation measures of other companies engaged in activities similar to ours.

An active trading market for the common units may not develop. It is also possible that after the offering the common units will not trade in the public market at or above the initial public offering price.

The underwriters do not expect to sell more than 5% of the common units in the aggregate to accounts over which they exercise discretionary authority.

Price Stabilization, Short Positions and Penalty Bids

Until the distribution of the common units is completed, SEC rules may limit underwriters and selling group members from bidding for and purchasing our common units. However, the representatives may engage in transactions that stabilize the price of the common units, such as bids or purchases to peg, fix or maintain that price.

In connection with the offering, the underwriters may purchase and sell our common units in the open market. These transactions may include short sales, purchases on the open market to cover positions created by short sales and stabilizing transactions. Short sales involve the sale by the underwriters of a greater number of common units than they are required to purchase in the offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ option to purchase additional common units described above. The underwriters may close out any covered short position by either exercising their option to purchase additional common units or purchasing common units in the open market. In determining the source of common units to close out the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the option granted to them. “Naked” short sales are sales in excess of such option. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of our common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common units made by the underwriters in the open market prior to the completion of the offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common units sold by or for the account of such underwriter in stabilizing or short covering transactions.

Similar to other purchase transactions, the underwriters’ purchases to cover the syndicate short sales may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of our common units. As a result, the price of our common units may be higher than the price that might otherwise exist in the open market. The underwriters may conduct these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of our common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these transactions or that these transactions, once commenced, will not be discontinued without notice.

 

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Electronic Distribution

In connection with the offering, certain of the underwriters or securities dealers may distribute prospectuses by electronic means, such as e-mail.

Other Relationships

Some of the underwriters and their affiliates have engaged in, and may in the future engage in, investment banking and other commercial dealings in the ordinary course of business with us or our affiliates. They have received, or may in the future receive, customary fees and commissions for these transactions.

In addition, in the ordinary course of their business activities, the underwriters and their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers. Such investments and securities activities may involve securities and/or instruments of ours or our affiliates. The underwriters and their affiliates may also make investment recommendations and/or publish or express independent research views in respect of such securities or financial instruments and may hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Notice to Prospective Investors in Australia

No placement document, prospectus, product disclosure statement or other disclosure document has been lodged with the Australian Securities and Investments Commission (“ASIC”), in relation to the offering. This registration statement does not constitute a prospectus, product disclosure statement or other disclosure document under the Corporations Act 2001 (the “Corporations Act”), and does not purport to include the information required for a prospectus, product disclosure statement or other disclosure document under the Corporations Act.

Any offer in Australia of the common units may only be made to persons (the “Exempt Investors”), who are:

 

(a)

“sophisticated investors” (within the meaning of section 708(8) of the Corporations Act), “professional investors” (within the meaning of section 708(11) of the Corporations Act) or otherwise pursuant to one or more exemptions contained in section 708 of the Corporations Act; and

 

(b)

“wholesale clients” (within the meaning of section 761G of the Corporations Act),

so that it is lawful to offer the common units without disclosure to investors under Chapters 6D and 7 of the Corporations Act.

The common units applied for by Exempt Investors in Australia must not be offered for sale in Australia in the period of 12 months after the date of allotment under the offering, except in circumstances where disclosure to investors under Chapters 6D and 7 of the Corporations Act would not be required pursuant to an exemption under both section 708 and Subdivision B of Division 2 of Part 7.9 of the Corporations Act or otherwise or where the offer is pursuant to a disclosure document which complies with Chapters 6D and 7 of the Corporations Act. Any person acquiring common units must observe such Australian on-sale restrictions.

This registration statement contains general information only and does not take account of the investment objectives, financial situation or particular needs of any particular person. It does not contain any securities recommendations or financial product advice. Before making an investment decision, investors need to consider whether the information in this registration statement is appropriate to their needs, objectives and circumstances, and, if necessary, seek expert advice on those matters.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area (each, a relevant member state), other than Germany, an offer of securities described in this registration statement may not be made to the public in that relevant member state other than:

 

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

 

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•

to fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

 

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive; provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in the Relevant Member State, and includes any relevant implementing measure in each relevant member state. The expression 2010 PD Amending Directive means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

Notice to Prospective Investors in Germany

This registration statement has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Sales Prospectus Act (Verkaufsprospektgesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute the common units in Germany. Consequently, the common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to this offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of the common units to the public in Germany or any other means of public marketing. The common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 8f paragraph 2 no. 4 of the German Sales Prospectus Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

This offering of our common units does not constitute an offer to buy or the solicitation or an offer to sell the common units in any circumstances in which such offer or solicitation is unlawful.

Notice to Prospective Investors in Hong Kong

No advertisement, invitation or document relating to the common units has been or may be issued or has been or may be in the possession of any person for the purposes of issue, whether in Hong Kong or elsewhere, which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to common units which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” as defined in the Securities and Futures Ordinance and any rules made under that Ordinance.

 

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Notice to Prospective Investors in the Netherlands

The common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

Notice to Prospective Investors in Switzerland

This registration statement is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. The common units are not being offered to the public in Switzerland, and neither this registration statement, nor any other offering materials relating to the common units may be distributed in connection with any such public offering.

We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (“CISA”). Accordingly, the common units may not be offered to the public in or from Switzerland, and neither this registration statement, nor any other offering materials relating to the common units may be made available through a public offering in or from Switzerland. The common units may only be offered and this registration statement may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Notice to Prospective Investors in the United Kingdom

Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (“FSMA”) that is not a “recognised collective investment scheme” for the purposes of FSMA (“CIS”) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This registration statements to is only being distributed in the United Kingdom to, and is only directed at:

 

(i)

if we are a CIS and are marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the “CIS Promotion Order”) or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

 

(ii)

otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Financial Promotion Order”) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

 

(iii)

in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”). The common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to us.

 

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VALIDITY OF OUR COMMON UNITS

The validity of our common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with our common units offered hereby will be passed upon for the underwriters by Latham & Watkins, LLP, Houston, Texas.

EXPERTS

The combined financial statements of Devon Midstream Holdings, L.P. Predecessor as of December 31, 2012 and December 31, 2011 and for each of the three years in the period ended December 31, 2012 included in this prospectus have been so included in reliance on the report of KPMG LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The balance sheet of Devon Midstream Partners, L.P. at September 19, 2013 included in this prospectus has been so included in reliance on the report of KPMG LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 regarding our common units. This prospectus, which constitutes part of the registration statement, does not contain all of the information set forth in the registration statement. For further information regarding us and our common units offered in this prospectus, we refer you to the registration statement and the exhibits and schedule filed as part of the registration statement. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549, at prescribed rates or from the SEC’s web site on the Internet at http://www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on public reference rooms.

As a result of the offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website will be located at                      and we intend to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.

We intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

 

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FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. Forward-looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. No assurance can be given as to our value, the price at which our securities will trade after this offering or whether a liquid market for those securities will develop or be maintained. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

 

•

changes in general economic conditions;

 

•

competitive conditions in our industry;

 

•

actions taken by third-party operators, processors and transporters;

 

•

changes in the availability and cost of capital;

 

•

operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

 

•

the effects of existing and future laws and governmental regulations;

 

•

the effects of future litigation; and

 

•

certain factors discussed elsewhere in this prospectus.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

 

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INDEX TO FINANCIAL STATEMENTS

 

DEVON MIDSTREAM PARTNERS, L.P.
Unaudited Pro Forma Consolidated Financial Statements
Introduction			F-2
Pro Forma Consolidated Statement of Operations for the Six Months Ended June 30, 2013			F-4
Pro Forma Consolidated Statement of Operations for the Year Ended December 31, 2012			F-5
Pro Forma Consolidated Balance Sheet at June 30, 2013			F-6
Notes to Pro Forma Consolidated Financial Statements			F-7
Audited Balance Sheet
Report of Independent Registered Public Accounting Firm			F-11
Balance Sheet at September 19, 2013			F-12
Notes to Balance Sheet			F-13
DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR
Audited Combined Financial Statements
Report of Independent Registered Public Accounting Firm			F-14
Combined Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010			F-15
Combined Balance Sheets at December 31, 2012 and 2011			F-16
Combined Statements of Equity for the Years Ended December 31, 2012, 2011 and 2010			F-17
Combined Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010			F-18
Notes to Combined Financial Statements			F-19
Unaudited Combined Interim Financial Statements
Combined Statements of Operations for the Six Months Ended June 30, 2013 and 2012 (unaudited)			F-30
Combined Balance Sheets at June 30, 2013 (unaudited) and December 31, 2012			F-31
Combined Statements of Equity for the Six Months Ended June 30, 2013 and 2012 (unaudited)			F-32
Combined Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012 (unaudited)			F-33
Notes to Combined Financial Statements			F-34

 

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DEVON MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

FOR THE YEAR ENDED DECEMBER 31, 2012 AND THE SIX MONTHS ENDED JUNE 30, 2013

Introduction

Devon Midstream Partners, L.P. (the “Partnership”) is a Delaware limited partnership that was formed in September 2013 by Devon Energy Corporation (“Devon”) in connection with Devon’s plans to offer common units representing limited partner interests in the Partnership to the public (the “Offering”).

At the completion of the Offering, Devon will indirectly own a non-economic general partner interest in the Partnership through DLP GP, L.L.C. (“DLP”), a wholly-owned subsidiary of Devon and the general partner of the Partnership, and a limited partner interest in the Partnership. DLP will be the Partnership’s general partner. The Partnership, through a wholly-owned subsidiary, will own a 20% interest in Devon Midstream Holdings, L.P. (“Devon Midstream Holdings”), which is a Delaware limited partnership to be formed. Devon will retain the remaining 80% limited partner interest in Devon Midstream Holdings. The Partnership’s wholly-owned subsidiary Devon Midstream Holdings GP, L.L.C. will be Devon Midstream Holdings’ general partner and will control its assets and operations. As part of the Offering, Devon will contribute to Devon Midstream Holdings its natural gas gathering, processing and transportation systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales located in Texas and Oklahoma and its 38.75% interest in Gulf Coast Fractionators.

Unless the context requires otherwise, for purposes of this pro forma presentation, all references to “we”, “our”, “us” and the “Partnership” refer to Devon Midstream Partners, L.P. and its subsidiaries, including Devon Midstream Holdings. Devon Midstream Holdings’ financial information is consolidated with the Partnership because the Partnership, through ownership of Devon Midstream Holdings’ general partner, will control Devon Midstream Holdings upon completion of the Offering.

The unaudited pro forma financial statements of the Partnership are based on the historical financial statements of Devon Midstream Holdings, L.P. Predecessor (the “Predecessor”), which comprises all of Devon’s U.S. midstream assets and operations. The unaudited pro forma consolidated statements of operations for the year ended December 31, 2012 and for the six months ended June 30, 2013 assume the Offering and related transactions occurred on January 1, 2012. The unaudited pro forma consolidated balance sheet as of June 30, 2013 assumes the Offering and related transactions occurred on June 30, 2013. The unaudited pro forma consolidated financial statements do not present the Partnership’s actual results of operations had the Offering and related transactions been completed at the dates indicated. In addition, they do not project the Partnership’s results of operations for any future period. The unaudited pro forma consolidated financial statements reflect the following significant assumptions and transactions:

 

•

Devon will contribute midstream assets in the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as a 38.75% non-operating equity interest in Gulf Coast Fractionators to Devon Midstream Holdings;

 

•

Devon Midstream Holdings will become a party to 10-year, fixed-fee gathering, processing and transportation agreements with Devon pursuant to which Devon will dedicate to Devon Midstream Holdings specified natural gas production in the Barnett, Cana-Woodford and Arkoma-Woodford Shales;

 

•

we will acquire a non-economic general partner interest and a 20% limited partner interest in Devon Midstream Holdings;

 

•

we will issue              common units and              subordinated units to Devon, representing a limited partner interest in us, and all of our incentive distribution rights, which will entitle Devon to increasing percentages of the cash that we distribute in excess of $         per unit per quarter;

 

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•

we will issue to our general partner a non-economic general partner interest in us;

 

•

we will issue              common units to the public, representing a limited partner interest in us;

 

•

we will enter into a $         million new revolving credit facility that will be undrawn at closing; and

 

•

we will use the net proceeds from this Offering (including any net proceeds from the exercise of the underwriters’ option to purchase additional common units from us) as described in “Use of Proceeds.”

The unaudited pro forma consolidated financial statements and accompanying notes have been prepared in conformity with accounting principles generally accepted in the United States of America. These accounting principles are consistent with those used in, and should be read together with, the Predecessor’s historical combined financial statements and related notes, which are included elsewhere in this prospectus.

The adjustments reflected in the unaudited pro forma consolidated financial statements are based on currently available information and certain estimates and assumptions. Therefore, actual results may differ from the pro forma adjustments. However, management believes that the estimates and assumptions used provide a reasonable basis for presenting the significant effects of the Offering and the related transactions. Management also believes the pro forma adjustments give appropriate effect to the estimates and assumptions and are applied in conformity with accounting principles generally accepted in the United States of America.

 

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DEVON MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

 

		Six Months Ended June 30, 2013
		Predecessor Historical				Adjustments for Non- Contributed Assets (a)				Predecessor Historical, As Adjusted				Offering Related Adjustments						Pro Forma, As Adjusted
		(in millions, except per unit data)
Operating revenues:
Operating revenues – affiliates		$	1,059.3			$	(33.7	)		$	1,025.6			$	(749.8	)		(b)		$	275.8
Operating revenues			103.1				(13.8	)			89.3				(68.6	)		(b)			20.7
Total operating revenues			1,162.4				(47.5	)			1,114.9				(818.4	)		(b)			296.5
Operating expenses:
Product purchases – affiliates			780.7				(8.1	)			772.6				(772.6	)		(b)			—
Product purchases			81.4				(9.9	)			71.5				(71.5	)		(b)			—
Operations and maintenance			60.1				(9.2	)			50.9				—						50.9
Operations and maintenance – affiliates			22.6				(4.6	)			18.0				—						18.0
Depreciation and amortization			96.8				(6.2	)			90.6				—						90.6
General and administrative – affiliates			22.4				(0.9	)			21.5				(2.0	)		(c)			19.5
Non-income taxes			9.0				(0.9	)			8.1				—						8.1
Other, net			1.5				1.7				3.2				—						3.2
Total operating expenses			1,074.5				(38.1	)			1,036.4				(846.1	)					190.3
Operating income			87.9				(9.4	)			78.5				27.7						106.2
Income from equity investment			4.4				—				4.4				—						4.4
Income before income taxes			92.3				(9.4	)			82.9				27.7						110.6
Income tax expense			33.2				(3.3	)			29.9				(28.8	)		(d)			1.1
Net income from continuing operations			59.1				(6.1	)			53.0				56.5						109.5
Non-controlling interests			—				—				—				(87.6	)		(e)			(87.6	)
Net income attributable to Devon Midstream Partners, L.P.		$	59.1			$	(6.1	)		$	53.0			$	(31.1	)				$	21.9
Net income attributable to Devon Midstream Partners, L.P.:
General partner interest																				$
Limited partner interests:
Common units																				$
Subordinated units																				$
Net income per limited partner unit (basic and diluted):
Common units																				$
Subordinated units																				$
Weighted average number of limited partner units outstanding (basic and diluted):
Common units
Subordinated units

See accompanying notes to the pro forma consolidated financial statements.

 

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DEVON MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

 

		Year Ended December 31, 2012
		Predecessor Historical				Adjustments for Non- Contributed Assets (a)				Predecessor Historical, As Adjusted				Offering Related Adjustments						Pro Forma, As Adjusted
		(in millions, except per unit data)
Operating revenues:
Operating revenues – affiliates		$	1,816.5			$	(62.6	)		$	1,753.9			$	(1,210.0	)		(b)		$	543.9
Operating revenues			184.3				(30.4	)			153.9				(116.1	)		(b)			37.8
Total operating revenues			2,000.8				(93.0	)			1,907.8				(1,326.1	)		(b)			581.7
Operating expenses:
Product purchases – affiliates			1,324.2				(13.9	)			1,310.3				(1,310.3	)		(b)			—
Product purchases			140.3				(22.5	)			117.8				(117.8	)		(b)			—
Operations and maintenance			127.2				(19.5	)			107.7				—						107.7
Operations and maintenance – affiliates			43.8				(10.0	)			33.8				—						33.8
Depreciation and amortization			159.8				(14.4	)			145.4				—						145.4
General and administrative – affiliates			43.6				(1.9	)			41.7				(3.5	)		(c)			38.2
Non-income taxes			13.2				(1.3	)			11.9				—						11.9
Asset impairments			50.1				(33.7	)			16.4				—						16.4
Other, net			(3.0	)			(0.5	)			(3.5	)			—						(3.5	)
Total operating expenses			1,899.2				(117.7	)			1,781.5				(1,431.6	)					349.9
Operating income			101.6				24.7				126.3				105.5						231.8
Income from equity investment			2.0				—				2.0				—						2.0
Income before income taxes			103.6				24.7				128.3				105.5						233.8
Income tax expense			37.3				8.9				46.2				(44.5	)		(d)			1.7
Net income from continuing operations			66.3				15.8				82.1				150.0						232.1
Non-controlling interests			—				—				—				(185.7	)		(e)			(185.7	)
Net income attributable to Devon Midstream Partners, L.P.		$	66.3			$	15.8			$	82.1			$	(35.7	)				$	46.4
Net income attributable to Devon Midstream Partners, L.P.:
Limited partner interests:
Common units																				$
Subordinated units																				$
Net income per limited partner unit (basic and diluted):
Common units																				$
Subordinated units																				$
Weighted average number of limited partner units outstanding (basic and diluted):
Common units
Subordinated units

See accompanying notes to the pro forma consolidated financial statements.

 

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DEVON MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

 

		June 30, 2013
		Predecessor Historical				Adjustments for Non- Contributed Assets (a)				Predecessor Historical, As Adjusted				Offering Related Adjustments						Pro Forma, As Adjusted
		(in millions)
Assets
Current assets:
Cash		$	—			$	—			$	—			$				(f)		$	—
																		(g)
Inventories			4.4				(1.3	)			3.1				—						3.1
Assets held for sale			20.6				(20.6	)			—				—						—
Other			0.3				—				0.3				—						0.3
Total current assets			25.3				(21.9	)			3.4				—						3.4
Property, plant and equipment, at cost			3,126.9				(264.1	)			2,862.8				—						2,862.8
Less accumulated depreciation and amortization			(1,241.7	)			165.1				(1,076.6	)			—						(1,076.6	)
Net property, plant and equipment			1,885.2				(99.0	)			1,786.2				—						1,786.2
Equity investment			62.3				—				62.3				—						62.3
Goodwill			401.7				(29.7	)			372.0				—						372.0
Assets held for sale			202.2				(202.2	)			—				—						—
Total assets		$	2,576.7			$	(352.8	)		$	2,223.9			$	—					$	2,223.9
Liabilities and Partners’ Equity
Current liabilities:
Distribution payable		$	—			$	—			$	—			$				(g)		$	—
																		(g)
Accrued expenses and other			69.7				(3.4	)			66.3				—						66.3
Current liabilities associated with assets held for sale			3.7				(3.7	)			—				—						—
Total current liabilities			73.4				(7.1	)			66.3				—						66.3
Asset retirement obligations			14.8				(5.1	)			9.7				—						9.7
Deferred income taxes			426.3				(84.6	)			341.7				(334.0	)		(d)			7.7
Other			5.1				(5.1	)			—				—						—
Total liabilities			519.6				(101.9	)			417.7				(334.0	)					83.7
Partners’ equity:
Devon Midstream Holdings, L.P. Predecessor equity			2,009.5				(203.3	)			1,806.2				(1,806.2	)		(i)			—
General partner, common and subordinated units			—				—				—				428.0			(d), (f), (g), (i), (j), (k)			428.0
Total partners’ equity attributable to Devon Midstream Partners, L.P.			2,009.5				(203.3	)			1,806.2				(1,378.2	)					428.0
Non-controlling interests			47.6				(47.6	)			—				1,712.2			(k)			1,712.2
Total partners’ equity			2,057.1				(250.9	)			1,806.2				334.0						2,140.2
Total liabilities and partners’ equity		$	2,576.7			$	(352.8	)		$	2,223.9			$	—					$	2,223.9

See accompanying notes to the pro forma consolidated financial statements.

 

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DEVON MIDSTREAM PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

 

1.	Basis of Presentation

The historical financial information for the year ended December 31, 2012 is derived from and should be read in conjunction with the audited historical combined financial statements of the Predecessor. The historical financial information for the six months ended June 30, 2013 and balance sheet information at June 30, 2013 is derived from and should be read in conjunction with the unaudited historical financial statements of the Predecessor. In each case, the historical financial information reflects 100% of the Predecessor’s operations. However, in conjunction with the Offering, only the Predecessor’s natural gas gathering and processing systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma and its 38.75% interest in Gulf Coast Fractionators will be contributed to Devon Midstream Holdings and included in the Partnership. Also, the Partnership will only own a 20% interest in Devon Midstream Holdings.

The pro forma adjustments have been prepared as if certain transactions to be completed in conjunction with the Offering had taken place on January 1, 2012 in the case of the pro forma statements of operations for the year ended December 31, 2012 and the six months ended June 30, 2013, or on June 30, 2013 in the case of the pro forma balance sheet. These transactions and adjustments are described in Note 3 to these unaudited pro forma consolidated financial statements.

Also, upon completion of this offering, we anticipate incurring incremental general and administrative expense of approximately $3.5 million per year as a result of being a publicly-traded partnership, including expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses, Sarbanes-Oxley compliance expenses, expenses associated with listing on the New York Stock Exchange, independent auditor fees, legal fees, investor relations expenses, and registrar and transfer agent fees. The unaudited pro forma combined financial statements do not reflect these additional public company costs.

 

2.	Summary of Significant Accounting Policies

The accounting policies used in preparing the unaudited pro forma consolidated financial statements are those used by the Predecessor as set forth in its audited historical combined financial statements contained elsewhere in this prospectus beginning on page F-15.

 

3.	Pro Forma Adjustments and Assumptions

The accompanying unaudited pro forma financial statements give pro forma effect to the following:

 

(a)

The creation of Devon Midstream Holdings and removal of all amounts related to Devon’s midstream assets not being contributed to us. In conjunction with the Offering, only the Predecessor’s natural gas gathering and processing systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales in Texas and Oklahoma and its 38.75% interest in Gulf Coast Fractionators will be contributed to Devon Midstream Holdings and included in the Partnership.

 

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(b)

Two contract changes that take effect upon completion of the Offering. The first contract change converts our natural gas processing percent-of-proceeds contracts to fixed-fee contracts. This contract change increases operating revenues as presented in the table below. The second contract change results in our ceasing to take title to the natural gas we gather and process or the NGLs we fractionate. This contract change decreases both operating revenues and product purchases as presented in the following table.

 

		Six Months Ended June 30, 2013				Year Ended December 31, 2012
		(in millions)
Operating revenues – affiliates:
Conversion to fixed-fee contracts		$	22.8			$	100.3
Cease taking title to products			(772.6	)			(1,310.3	)
Operating revenues – affiliates			(749.8	)			(1,210.0	)
Operating revenues:
Conversion to fixed-fee contracts			2.9				1.7
Cease taking title to products			(71.5	)			(117.8	)
Operating revenues			(68.6	)			(116.1	)
Total operating revenues		$	(818.4	)		$	(1,326.1	)
Cease taking title to products:
Product purchases – affiliates		$	(772.6	)		$	(1,310.3	)
Product purchases		$	(71.5	)		$	(117.8	)

 

(c)

The reduction of general and administrative expenses allocated from Devon of $2.0 million for the six months ended June 30, 2013 and $3.5 million for the year ended December 31, 2012. The lower allocation results from the decreases in operating revenues, which are a component of the allocations, reflected in adjustment (b).

 

(d)

The elimination of corporate federal total income tax expense of $28.8 million for the six months ended June 30, 2013 and $44.5 million for the year ended December 31, 2012. Also, reflects the elimination of corporate federal deferred income tax liabilities of $334.0 million as of June 30, 2013. In conjunction with the Offering, Devon Midstream Holdings will be created as a partnership, and its operating subsidiaries will be nontaxable entities, except for certain state taxes. Accordingly, Devon Midstream Holdings, including its subsidiaries, will not be subject to corporate federal income taxes.

 

(e)

Income attributable to non-controlling interests of $87.6 million for the six months ended June 30, 2013 and $185.7 million for year ended December 31, 2012, which represents Devon’s 80% interest in Devon Midstream Holdings’ net income.

 

		Six Months Ended June 30, 2013				Year Ended December 31, 2012
		($ in millions)
Pro forma predecessor net income		$	109.5			$	232.1
Non-controlling interest %			80	%			80	%
Pro forma non-controlling interest in net income		$	87.6			$	185.7

 

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(f)

The sale of              common units, representing a     % limited partner interest in us, at an assumed price of $         per unit and resulting in gross proceeds of $         million and underwriting discounts and other costs totaling $         million. If the underwriters were to exercise in full their option to purchase an additional              common units, gross proceeds would equal $         million.

 

		(in millions)
Gross proceeds from initial public offering		$
Underwriting discount
Expenses and costs of initial public offering
Structuring fee			(1.2	)
Net proceeds		$

 

(g)

The recognition and repayment of a $         million liability, representing the distribution of the offering proceeds to Devon as reimbursement of certain capital expenditures incurred with respect to the assets contributed to us, as well as partial consideration for the 20% limited partner interest in Devon Midstream Holdings.

 

		As of June 30, 2013
Net proceeds from initial public offering		$
Payment for debt issuance costs
Distribution to Devon from the offering		$

 

(h)

Estimated debt issuance costs of $         million associated with the new $         million revolving credit facility, which will initially have no borrowings.

 

(i)

The elimination of the Predecessor’s capital accounts of $1,806.2 million following Devon’s contribution to us of a 20% interest in Devon Midstream Holdings and a 100% interest in Devon Midstream Holdings’ general partner in exchange for          subordinated units, all our incentive distribution rights and a non-economic general partner interest in us.

 

(j)

The issuance to Devon of          subordinated units, representing a     % limited partner interest in us, for $         million and the issuance of all our incentive distribution rights. Additionally, the issuance to our general partner of a non-economic general partner interest in us.

 

(k)

Devon’s 80% limited partner interest in Devon Midstream Holdings’ of $1,712.2 million.

Included below is a reconciliation between the Predecessor’s historical equity and the pro forma partners’ equity:

 

						Partners’ Equity
		Predecessor				Devon Midstream Partners, L.P.				Non-controlling interest
Predecessor equity		$	1,806.2			$	—			$	—
Adjustment (d)			—				334.0				—
Adjustment (f)			—								—
Adjustment (g)			—								—
Adjustment (i)			(1,806.2	)			1,806.2				—
Adjustment (j)			—
Adjustment (k)			—				(1,712.2	)			1,712.2
Pro forma partners’ equity		$	—			$	428.0			$	1,712.2

 

4.	Commitments and Contingencies

Commitments and contingencies of the Predecessor are described in the unaudited combined interim financial statements for the six months ended June 30, 2013 contained elsewhere in this prospectus.

 

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5.	Income Per Unit

Pro forma net income per unit is determined by dividing the pro forma net income that would have been allocated, in accordance with the net income allocation provisions of the limited partnership agreement, to the holders of common and subordinated units under the two-class method by the number of common and subordinated units expected to be outstanding at the closing of the Offering. For purposes of this calculation, we assumed that (i) the Minimum Quarterly Distribution was made to all unitholders for each quarter during the periods presented, (ii) the number of units outstanding was              common units and              subordinated units and (iii) no incentive distributions were made to Devon. The common and subordinated unitholders each represent 50% limited partner interests. All units were assumed to have been outstanding since January 1, 2012.

Pro forma basic and diluted net income per unit are equivalent since it is expected there will be no dilutive units outstanding at the date of closing of the Offering.

Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, Devon is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Devon Energy Corporation:

We have audited the accompanying balance sheet of Devon Midstream Partners, L.P. (the “Partnership”) as of September 19, 2013. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit 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 balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statement referred to above presents fairly, in all material respects, the financial position of the Partnership as of September 19, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Oklahoma City, Oklahoma

September 27, 2013

 

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DEVON MIDSTREAM PARTNERS, L.P.

BALANCE SHEET

September 19, 2013

 

Assets
Cash		$	—
Total assets		$	—
Partners’ Equity
Limited partner equity		$	1,000
General partner equity			—
Receivable from Devon			(1,000	)
Total partners’ equity		$	—

 

See accompanying note to the balance sheet

 

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DEVON MIDSTREAM PARTNERS, L.P.

NOTE TO BALANCE SHEET

 

1.	Organization and Nature of Business

Devon Midstream Partners, L.P. (the “Partnership”) is a Delaware limited partnership that was formed in September 2013 by Devon Energy Corporation (“Devon”) in connection with Devon’s plans to offer common units representing limited partner interests in the Partnership to the public (the “Offering”).

At the completion of the Offering, Devon will indirectly own a non-economic general partner interest in the Partnership through DLP GP, L.L.C. (“DLP”), a wholly-owned subsidiary of Devon and the general partner of the Partnership, and limited partner interest in the Partnership. DLP will be the Partnership’s general partner. The Partnership, through a wholly-owned subsidiary, will own a 20% interest in Devon Midstream Holdings, L.P. (“Devon Midstream Holdings”), which is a Delaware limited partnership to be formed. Devon will retain the remaining 80% limited partner interest in Devon Midstream Holdings. The Partnership’s wholly-owned subsidiary Devon Midstream Holdings GP, L.L.C. will be Devon Midstream Holdings’ general partner and will control its assets and operations.

As part of the Offering, Devon will contribute to Devon Midstream Holdings its natural gas gathering, processing and transportation systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales located in Texas and Oklahoma and its 38.75% interest in Gulf Coast Fractionators. The most significant system is the Barnett system, which serves the Barnett Shale in North Texas. This system includes integrated gathering pipelines, one gas processing plant and an NGL fractionator. The Cana system serves the Cana-Woodford Shale in West Central Oklahoma. This system consists of integrated gathering pipelines and a gas processing plant. The Northridge system serves the Arkoma-Woodford Shale in Southeastern Oklahoma. This system consists of integrated gathering pipelines and a gas processing plant. Gulf Coast Fractionators is an NGL fractionator located on the Gulf Coast at the Mont Belvieu hub. The Predecessor’s other assets include systems that serve the Powder River Basin in Wyoming and other areas where Devon operates.

Devon will provide services to the Partnership pursuant to an omnibus agreement. Consistent with Devon, the Partnership has adopted a December 31 fiscal year end.

On September 19, 2013, Devon Gas Corporation, a wholly-owned subsidiary of Devon, contributed $1,000 to the Partnership in the form of a receivable in exchange for a non-economic general partner interest and 100% limited partner interest in the Partnership. There have been no other transactions involving the Partnership as of September 27, 2013.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors

Devon Energy Corporation:

We have audited the accompanying combined balance sheets of Devon Midstream Holdings, L.P. Predecessor (Predecessor) as of December 31, 2012 and 2011, and the related combined statements of operations, equity, and cash flows for each of the years in the three-year period ended December 31, 2012. These combined financial statements are the responsibility of the Predecessor’s management. Our responsibility is to express an opinion on these combined 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 combined financial statements referred to above present fairly, in all material respects, the financial position of the Predecessor as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Oklahoma City, Oklahoma

September 27, 2013

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

COMBINED STATEMENTS OF OPERATIONS

 

		Year Ended December 31,
		2012				2011				2010
		(in millions)
Operating revenues:
Operating revenues – affiliates		$	1,816.5			$	2,325.0			$	1,778.1
Operating revenues			184.3				298.4				237.9
Total operating revenues			2,000.8				2,623.4				2,016.0
Operating expenses:
Product purchases – affiliates			1,324.2				1,774.2				1,288.4
Product purchases			140.3				239.9				180.5
Operations and maintenance			127.2				109.6				81.4
Operations and maintenance – affiliates			43.8				45.9				38.1
Depreciation and amortization			159.8				144.8				124.9
General and administrative – affiliates			43.6				40.1				39.4
Non-income taxes			13.2				15.3				13.8
Asset impairments			50.1				—				—
Other, net			(3.0	)			(58.0	)			0.4
Total operating expenses			1,899.2				2,311.8				1,766.9
Operating income			101.6				311.6				249.1
Income from equity investment			2.0				9.3				5.1
Income from continuing operations before income taxes			103.6				320.9				254.2
Income tax expense			37.3				115.5				91.5
Net income from continuing operations			66.3				205.4				162.7
Discontinued operations:
Net income from discontinued operations			10.6				12.8				20.5
Net income from discontinued operations attributable to non-controlling interests			(1.1	)			(2.1	)			(4.5	)
Net income from discontinued operations attributable to Devon			9.5				10.7				16.0
Net income attributable to Devon		$	75.8			$	216.1			$	178.7

See accompanying notes to the combined financial statements.

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

COMBINED BALANCE SHEETS

 

		December 31,
		2012				2011
		(in millions)
Assets
Current assets:
Inventories		$	5.5			$	6.0
Prepaid expenses			4.2				4.3
Assets held for sale			21.4				16.7
Other			0.3				0.3
Total current assets			31.4				27.3
Property, plant and equipment, at cost			2,985.8				2,619.3
Less accumulated depreciation and amortization			(1,142.6	)			(932.3	)
Net property, plant and equipment			1,843.2				1,687.0
Equity investment			57.7				41.8
Goodwill			401.7				401.7
Assets held for sale			201.2				288.5
Total assets		$	2,535.2			$	2,446.3
Liabilities and Equity
Current liabilities:
Accrued expenses and other		$	80.1			$	80.0
Current liabilities associated with assets held for sale			3.3				4.0
Total current liabilities			83.4				84.0
Asset retirement obligations			13.2				11.8
Deferred income taxes			431.8				443.8
Other			4.8				5.4
Total liabilities			533.2				545.0
Equity:
Devon equity			1,953.3				1,856.0
Non-controlling interests			48.7				45.3
Total equity			2,002.0				1,901.3
Commitments and contingencies (Note 9)
Total liabilities and equity		$	2,535.2			$	2,446.3

See accompanying notes to the combined financial statements.

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

COMBINED STATEMENTS OF EQUITY

 

		Year Ended December 31,
		2012				2011				2010
		(in millions)
Devon equity
Balance as of beginning of year		$	1,856.0			$	1,800.4			$	1,820.9
Net income			75.8				216.1				178.7
Net distributions from (to) Devon – continuing operations			115.7				(131.1	)			(171.8	)
Net distributions to Devon – discontinued operations			(94.2	)			(29.4	)			(27.4	)
Balance as of end of year		$	1,953.3			$	1,856.0			$	1,800.4
Non-controlling interests
Balance as of beginning of year		$	45.3			$	48.6			$	48.8
Net income			1.1				2.1				4.5
Net distributions from (to) non-controlling interests – discontinued operations			2.3				(5.4	)			(4.7	)
Balance as of end of year		$	48.7			$	45.3			$	48.6
Total equity
Balance as of beginning of year		$	1,901.3			$	1,849.0			$	1,869.7
Net income			76.9				218.2				183.2
Net distributions from (to) Devon – continuing operations			115.7				(131.1	)			(171.8	)
Net distributions to Devon and non-controlling interests – discontinued operations			(91.9	)			(34.8	)			(32.1	)
Balance as of end of year		$	2,002.0			$	1,901.3			$	1,849.0

See accompanying notes to the combined financial statements.

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS

 

		Year Ended December 31,
		2012				2011				2010
		(in millions)
Cash flows from operating activities:
Net income from continuing operations		$	66.3			$	205.4			$	162.7
Adjustments to reconcile net income from continuing operations to net cash provided by operating activities:
Depreciation and amortization			159.8				144.8				124.9
Asset impairments			50.1				—				—
Deferred income tax (benefit) expense			(10.5	)			42.0				91.1
(Income) loss from equity investment, net of distributions			0.3				(0.9	)			—
Other noncash items, net			(1.0	)			1.9				10.7
Changes in assets and liabilities:
Inventories			0.5				3.7				1.7
Prepaid expenses			0.1				(1.0	)			(1.0	)
Other assets			0.5				0.7				(1.1	)
Accrued expenses and other liabilities			(11.7	)			4.6				2.5
Net cash provided by operating activities			254.4				401.2				391.5
Cash used in investing activities:
Capital expenditures			(351.7	)			(247.6	)			(224.0	)
Contribution to equity investment			(16.8	)			(21.1	)			—
Distribution from equity investment in excess of cumulative income			—				—				3.6
Other			—				0.1				—
Net cash used in investing activities			(368.5	)			(268.6	)			(220.4	)
Cash flows from financing activities:
Net distributions from (to) Devon			115.7				(131.1	)			(171.8	)
Other			(1.6	)			(1.5	)			0.7
Net cash provided by (used in) financing activities			114.1				(132.6	)			(171.1	)
Cash flows from discontinued operations:
Net cash provided by operating activities			25.3				33.4				49.1
Net cash provided by (used in) investing activities			74.1				(22.5	)			(5.9	)
Net cash used in financing activities – net distributions to Devon and non-controlling interests			(91.9	)			(34.8	)			(32.1	)
Net cash provided by (used in) discontinued operations			7.5				(23.9	)			11.1
Net change in cash and cash equivalents			7.5				(23.9	)			11.1
Beginning cash and cash equivalents – related to assets held for sale			8.1				32.0				20.9
Ending cash and cash equivalents – related to assets held for sale		$	15.6			$	8.1			$	32.0

See accompanying notes to the combined financial statements.

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

NOTES TO COMBINED FINANCIAL STATEMENTS

 

1.	Organization and Nature of Business

The accompanying financial statements of Devon Midstream Holdings, L.P. Predecessor (the “Predecessor”) have been prepared in connection with the proposed initial public offering of limited partner units in Devon Midstream Partners, L.P. (the “Partnership”). Formed in Delaware in September 2013, the Partnership is a subsidiary of Devon Energy Corporation (“Devon”). The Predecessor is comprised of Devon’s U.S. midstream assets and operations, including its 38.75% interest in Gulf Coast Fractionators.

As part of the initial public offering of limited partner units in the Partnership (the “Offering”), Devon will contribute certain of the Predecessor’s assets and operations to Devon Midstream Holdings, L.P. (“Devon Midstream Holdings”), which is a Delaware limited partnership to be formed. Devon will then contribute a 20% interest in Devon Midstream Holdings to the Partnership and will retain the remaining 80% interest. DLP GP, L.L.C. (“DLP”), a wholly-owned subsidiary of Devon, will serve as the general partner for the Partnership. The Partnership’s wholly-owned subsidiary Devon Midstream Holdings GP, L.L.C. will serve as the general partner for Devon Midstream Holdings. Devon will provide services to the Partnership pursuant to an omnibus agreement. DLP, the Partnership and Devon Midstream Holdings have all adopted December 31 fiscal year ends.

The Predecessor is engaged in the business of purchasing natural gas from Devon and third parties at or near the wellhead and then gathering, compressing, treating and processing the purchased natural gas and fractionating the natural gas liquids, or NGLs, that result from the natural gas processing. After performing these activities, the Predecessor sells its natural gas and NGLs to Devon. The Predecessor primarily performs these activities to support Devon’s operations. However, to the extent system capacity is available, the Predecessor also provides these services for other companies engaged in the production, distribution and marketing of natural gas and NGLs.

The Predecessor’s assets consist of Devon’s U.S. natural gas gathering and processing systems, as well as a 38.75% interest in Gulf Coast Fractionators. These systems are located primarily in Texas and Oklahoma. The most significant system is the Bridgeport system, which serves the Barnett Shale in North Texas. This system includes integrated gathering pipelines, one gas processing plant and an NGL fractionator. The Cana system serves the Cana-Woodford Shale in West Central Oklahoma. This system consists of integrated gathering pipelines and a gas processing plant. The Northridge system serves the Arkoma-Woodford Shale in Southeastern Oklahoma. This system consists of integrated gathering pipelines and a gas processing plant. Gulf Coast Fractionators is a full-service NGL fractionator located on the Gulf Coast at the Mont Belvieu hub. The Predecessor’s other assets include systems that serve the Powder River Basin in Wyoming and other areas where Devon operates.

In connection with the initial public offering of limited partner units in the Partnership, Devon will contribute to Devon Midstream Holdings the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as the 38.75% interest in Gulf Coast Fractionators.

 

2.	Summary of Significant Accounting Policies

Basis of Presentation

The Predecessor’s accompanying combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America on the basis of Devon’s historical ownership of the Predecessor’s assets and its operations. These financial statements include the Predecessor’s accounts and those of its majority-owned subsidiaries. All significant intercompany transactions and balances have been eliminated.

 

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The accompanying financial statements have been prepared from records maintained by Devon and may not be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported. Because a direct ownership relationship did not exist among the businesses comprising the Predecessor, the net investment in the Predecessor is shown as equity, in lieu of owner’s equity, in the combined financial statements.

During the reporting periods for the accompanying financial statements, Devon provided cash management services to the Predecessor through a centralized treasury system. As a result, all revenues covered by the centralized treasury system were deemed to have been received in cash by the Predecessor from Devon during the period in which the revenue was recorded in the financial statements. All charges and cost allocations covered by the centralized treasury system were deemed to have been paid in cash to Devon during the period in which the cost was recorded in the financial statements. The net effects of these amounts are reflected as net distributions to or contributions from Devon and non-controlling interests in the accompanying statements of equity. As a result of this accounting treatment, the Predecessor’s working capital does not reflect any affiliate accounts receivables or payables, except for amounts that pertain to planned cash transfers between the Predecessor and Devon affiliates.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make 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 revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known. Significant items subject to such estimates and assumptions include the following:

 

•

reporting unit fair value and the related assessment of goodwill for impairment,

 

•

fair value of property, plant and equipment and the related impairment assessment,

 

•

depreciation of property, plant and equipment,

 

•

allocations of Devon’s corporate overhead costs,

 

•

legal and environmental risks and exposures,

 

•

asset retirement obligations, and

 

•

income taxes.

Reportable Segments

The Predecessor’s operations are managed through distinct operating segments, which are defined primarily as each natural gas gathering and processing system serving separate geographic regions. For financial reporting purposes, the operating segments are aggregated into one reporting segment due to the similar nature of the businesses.

Revenue Recognition and Gas Balancing

The Predecessor’s operating revenues consist of revenues from gathering, compressing, treating and processing natural gas and from fractionating NGLs. Generally, the Predecessor receives fees for the services it provides. For natural gas processing services, the Predecessor receives a percent-of-proceeds fee based on the sales value of extracted NGLs and residue natural gas. For gathering, compression and treating services, the Predecessor receives a fixed fee based on the volume and thermal content of the associated natural gas.

Operating revenues are recorded at the time products are sold or services are provided to Devon or other customers at a fixed or determinable price, delivery or performance has occurred, title has transferred and collectability of the revenue is probable.

 

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Operating revenues and expenses attributable to the Predecessor’s natural gas and NGL purchase and processing contracts are reported on a gross basis when the Predecessor takes title to the products and has risks and rewards of ownership. The natural gas purchased under these contracts is processed in the Predecessor’s processing facilities.

Allocation of Costs

Certain of Devon’s centralized overhead and operating costs represent shared services that benefit its subsidiaries and affiliates, including the Predecessor. The shared services consist primarily of accounting, treasury, information technology, human resources, legal and facilities management. The accompanying financial statements include costs allocated by Devon for these shared services in the form of a management services fee. The costs are allocated to the Predecessor based on its proportionate share of Devon’s revenues, employee compensation and gross property, plant and equipment. Management believes these allocation methodologies are reasonable. All allocated costs are included in general and administrative expenses in the accompanying statements of operations.

Devon grants certain share-based awards to members of its Board of Directors and selected employees. The Predecessor does not grant share-based awards but does participate in Devon’s share-based award plans. The awards granted under Devon’s plans are measured at fair value on the date of grant and are recognized as expense over the applicable requisite service periods.

The Predecessor does not sponsor any pension, postretirement or employee savings plans. However, the Predecessor participates in certain plans sponsored by Devon. The Predecessor participates in Devon’s non-contributory defined benefit pension plans, including both qualified and nonqualified plans. Devon also has defined benefit postretirement plans that provide medical and, in some cases, life insurance benefits, in which the Predecessor participates. Devon also sponsors, and the Predecessor participates in, 401(k) and enhanced contribution plans to which Devon makes contributions to participant accounts.

Income Taxes

Certain of the Predecessor’s operations are subject to income taxes assessed by the federal and various state jurisdictions in the U.S. Additionally, certain of the Predecessor’s operations are subject to tax assessed by the State of Texas that is computed based on modified gross margin as defined by the State of Texas. The Texas margin tax is presented as income tax expense in the accompanying statements of operations.

In addition, the Predecessor accounts for deferred income taxes related to the federal and state jurisdictions using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some portion of carryforwards is determined to be unlikely, a valuation allowance is provided to reduce the recorded tax benefits from such assets. 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 and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

The Predecessor recognizes the financial statement effects of tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits are presented as other current or long-term liabilities in the accompanying balance sheet based on timing of the expected settlement. Interest and penalties related to unrecognized tax benefits are included in current income tax expense.

 

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In connection with the Offering, the Predecessor’s operations will be structured so that none of its operations will be subject to income tax, except for the operations subject to the Texas gross margin tax. Accordingly, Devon Midstream Holdings, including its subsidiaries, will no longer be subject to corporate federal income taxes.

Discontinued Operations

The Predecessor classifies as discontinued operations its assets or asset groups that have clearly distinguishable cash flows and are in the process of being sold or have been sold.

Cash and Cash Equivalents

The Predecessor considers all highly liquid investments with original contractual maturities of three months or less to be cash equivalents. Under the Predecessor’s cash management arrangement with Devon, the Predecessor remits all excess cash to Devon who then funds the Predecessor’s controlled disbursement accounts as amounts are presented for payment. There were no outstanding checks in excess of cash balances as of December 31, 2012.

Inventories

Inventories consist of materials and supplies used in the Predecessor’s operations. All inventories are recorded at the lower of the weighted average cost or market value.

Property, Plant and Equipment

Costs directly and indirectly related to the acquisition or construction of the Predecessor’s processing facilities, pipelines and equipment are capitalized and recorded as property, plant and equipment. Direct costs include labor and material costs. Indirect costs include taxes, fees, the cost of funds used during construction and other various costs. Improvement costs which extend the useful lives or increase the capacity of these assets are also capitalized. Repair and maintenance costs which do not increase the useful lives or capacity of these assets are recognized as operations and maintenance expense in the accompanying statements of operations.

Costs for property, plant and equipment that are in use are depreciated over the assets’ estimated useful lives, using either the unit-of-production or straight-line method.

Upon the disposition or retirement of property, plant and equipment related to continuing operations, any gain or loss is recognized as other income or expense in the statement of operations. When a disposition or retirement occurs which qualifies as discontinued operations, any gain or loss is recognized as income or loss from discontinued operations in the statement of operations.

The Predecessor evaluates its property, plant and equipment for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. The carrying amount of a long-lived asset is not recoverable when it exceeds the undiscounted sum of the cash flows expected to result from the use and eventual disposition of the asset. Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions. When the carrying amount of a long-lived asset is not recoverable, an impairment loss is recognized equal to the excess of the asset’s carrying value over its fair value. The fair values of long-lived assets are generally determined from estimated discounted future net cash flows. The fair value of the predecessor’s long-lived assets is considered a level 3 fair value measurement. Estimated future net cash flows are highly dependent on the duration of expected cash flows and estimated future natural gas and NGL pricing, operating costs, capital expenditures and throughput volumes.

 

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Equity Method of Accounting

The Predecessor accounts for investments it does not control but has the ability to exercise significant influence using the equity method of accounting. Under this method, equity investments are carried originally at the acquisition cost, increased by the Predecessor’s proportionate share of the investee’s net income and by contributions made, and decreased by the Predecessor’s proportionate share of the investee’s net losses and by distributions received.

The Predecessor evaluates its equity investments for potential impairment whenever events or changes in circumstances indicate that the carrying amount of the investments may not be recoverable.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net assets acquired. Goodwill is tested at least annually for impairment. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense. Because quoted market prices are not available for Predecessor’s reporting unit, the fair value of the reporting unit is estimated using valuation analyses based on values of comparable companies and comparable transactions. The Predecessor performed annual impairment tests of goodwill as of the fourth quarters of 2012, 2011 and 2010. Based on these assessments, no impairment of goodwill was required.

Asset Retirement Obligations

The Predecessor recognizes liabilities for retirement obligations associated with its pipelines and processing and fractionation facilities. Such liabilities are recognized when there is a legal obligation associated with the retirement of the assets and the amount can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its fair value, with an offsetting asset retirement cost recorded as an increase to the associated property, plant and equipment. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost. The Predecessor’s asset retirement obligations include estimated environmental remediation costs which arise from normal operations and are associated with the retirement of the long-lived assets. The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property, plant and equipment.

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for environmental remediation or restoration claims resulting from improper operation of assets are recorded when it is probable that an obligation has been incurred and the amount can be reasonably estimated. Expenditures related to such environmental matters are expensed or capitalized in accordance with the Predecessor’s accounting policy for property, plant and equipment.

 

3.	Affiliate Transactions

The Predecessor engages in various transactions with Devon and other affiliated entities. These transactions relate to sales to and from affiliates, services provided by affiliates, cost allocations from affiliates and centralized cash management activities performed by affiliates. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with nonaffiliated third parties. The amounts related to affiliate transactions are specified in the accompanying financial statements.

 

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The following schedule presents the affiliate transactions and other transactions made to or received from Devon, all of which are settled through an adjustment to equity:

 

		Year Ended December 31,
		2012				2011				2010
		(in millions)
Continuing operations:
Operating revenues – affiliates		$	(1,816.5	)		$	(2,325.0	)		$	(1,778.1	)
Operating expenses – affiliates			1,411.6				1,860.2				1,365.9
Net affiliate transactions			(404.9	)			(464.8	)			(412.2	)
Capital expenditures			351.7				247.6				224.0
Other third-party transactions, net			168.9				86.1				16.4
Total third-party transactions			520.6				333.7				240.4
Net distributions from (to) Devon – continuing operations		$	115.7			$	(131.1	)		$	(171.8	)
Discontinued operations:
Operating revenues – affiliates		$	(89.5	)		$	(152.3	)		$	(173.2	)
Operating expenses – affiliates			60.3				107.6				111.8
Cash used in financing activities – affiliates			(1.1	)			(24.7	)			(22.3	)
Net affiliate transactions			(30.3	)			(69.4	)			(83.7	)
Capital expenditures			13.5				22.5				7.0
Other third-party transactions, net			(75.1	)			12.1				44.6
Net third-party transactions			(61.6	)			34.6				51.6
Net distributions to Devon and non-controlling interests – discontinued operations		$	(91.9	)		$	(34.8	)		$	(32.1	)

During 2012, 2011 and 2010, Devon was the Predecessor’s only significant customer. Devon accounted for 91%, 89% and 88% of the Predecessor’s operating revenues during 2012, 2011 and 2010, respectively.

Share-based compensation costs included in the management services fee charged to the Predecessor by Devon were approximately $12.8 million, $12.6 million, and $12.7 million for 2012, 2011 and 2010, respectively. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Predecessor by Devon were approximately $9.1 million, $8.3 million, and $6.9 million for 2012, 2011 and 2010, respectively. These amounts are included in general and administrative expenses in the accompanying statements of operations.

 

4.	Other, net

During 2012 and 2011, we recognized $3.0 million and $58.0 million of net other income, respectively. In 2012, we received insurance proceeds of $5.6 million related to business interruption that occurred at Gulf Coast Fractionators. In 2011, we received $57.8 million of excess insurance recoveries related to business interruption and equipment damage at our Cana system that resulted from tornadoes.

 

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5.	Income Taxes

Income Tax Expense

The Predecessor is a member of an affiliated group that files consolidated income tax returns. Income taxes are calculated based on each entity’s separate taxable income or loss. The components of income tax expense related to the Predecessor’s income from continuing operations are as follows:

 

		Year Ended December 31,
		2012				2011				2010
		(in millions)
Current income tax expense:
U.S. federal		$	45.4			$	71.4			$	0.4
Various states			1.6				2.1				—
Total current tax expense			47.0				73.5				0.4
Deferred income tax expense (benefit):
U.S. federal			(9.4	)			40.8				88.3
Various states			(0.3	)			1.2				2.8
Total deferred tax expense (benefit)			(9.7	)			42.0				91.1
Total income tax expense		$	37.3			$	115.5			$	91.5

The following schedule reconciles the Predecessor’s total income tax expense and the amount computed by applying the statutory U.S. federal tax rate to income from continuing operations before income taxes:

 

		Year Ended December 31,
		2012				2011				2010
		(in millions)
Expected income tax expense based on federal statutory rate of 35%		$	36.0			$	112.2			$	88.7
State income taxes, net of federal benefit and other			1.3				3.3				2.8
Total income tax expense		$	37.3			$	115.5			$	91.5

Deferred Tax Assets and Liabilities

The tax effects of temporary differences that gave rise to significant portions of the Predecessor’s deferred tax assets and liabilities are presented below:

 

		December 31,
		2012				2011
		(in millions)
Deferred tax assets:
Asset retirement obligations		$	4.2			$	3.9
Other			0.1				1.8
Total deferred tax assets			4.3				5.7
Deferred tax liabilities:
Property, plant and equipment			(435.4	)			(449.5	)
Other			(0.7	)			—
Total deferred tax liabilities			(436.1	)			(449.5	)
Deferred tax liability, net		$	(431.8	)		($	443.8	)

 

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Unrecognized Tax Benefits

For the years ended December 31, 2012, 2011 and 2010, the Predecessor had not recorded any amounts related to unrecognized tax benefits. Included below is a summary of the tax years that remain subject to examination by taxing authorities:

 

Jurisdiction		Tax Years Open
U.S. federal			2008-2012
Various U.S. states			2008-2012

 

6.	Discontinued Operations

The Predecessor is in the process of selling or has sold certain non-core assets that are presented as discontinued operations in the accompanying financial statements. The following schedule summarizes net income for the Predecessor’s discontinued operations:

 

		Year Ended December 31,
		2012				2011				2010
		(in millions)
Operating revenues:
Operating revenues		$	22.6			$	20.4			$	25.5
Operating revenues – affiliates			89.5				152.3				173.2
Total operating revenues			112.1				172.7				198.7
Operating expenses:
Operating expenses			40.9				38.3				51.9
Operating expenses – affiliates			60.3				107.6				111.8
Asset impairments			3.0				6.8				1.2
(Gain) loss on sale of assets, net			(8.7	)			—				1.7
Total operating expenses			95.5				152.7				166.6
Income before income taxes			16.6				20.0				32.1
Income tax expense			6.0				7.2				11.6
Net income			10.6				12.8				20.5
Net income attributable to non-controlling interests			(1.1	)			(2.1	)			(4.5	)
Net income attributable to Devon		$	9.5			$	10.7			$	16.0

 

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The following schedule presents the main classes of assets and liabilities associated with the Predecessor’s discontinued operations:

 

		December 31,
		2012				2011
		(in millions)
Cash and cash equivalents		$	15.6			$	8.1
Accounts receivable			3.7				4.3
Inventories			2.0				2.2
Other current assets			0.1				2.1
Total current assets			21.4				16.7
Property, plant and equipment			184.7				262.5
Goodwill			16.5				26.0
Total assets		$	222.6			$	305.2
Accounts payable		$	2.8			$	3.6
Other current liabilities			0.5				0.4
Total current liabilities			3.3				4.0
Asset retirement obligations			4.2				4.8
Other long-term liabilities			0.3				0.2
Total liabilities		$	7.8			$	9.0
Non-controlling interests in equity		$	48.7			$	45.3

Subsequent Events

In May 2013, the Predecessor entered into an agreement to sell its controlling interest in its assets and operations located in Montana for approximately $10 million. This sales price is subject to customary adjustments for financial activity between the effective and closing date of the transaction.

In August 2013, the Predecessor sold its controlling interest in its assets and operations located in Wyoming for approximately $148 million.

 

7.	Property, Plant and Equipment

The components of property, plant and equipment are as follows:

 

		December 31,
		2012				2011
		(in millions)
Pipelines		$	1,817.2			$	1,634.0
Processing facilities			1,160.0				977.1
Other			8.6				8.2
Property, plant and equipment			2,985.8				2,619.3
Accumulated depreciation and amortization			(1,142.6	)			(932.3	)
Property, plant and equipment, net		$	1,843.2			$	1,687.0

During 2012, the Predecessor recognized $50.1 million of asset impairments related to its continuing operations. The impairments resulted from the impact of lower natural gas and NGL prices on the Predecessor’s Northridge system and other less significant systems.

 

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8.	Asset Retirement Obligations

The schedule below summarizes the changes in the Predecessor’s asset retirement obligations:

 

		Year Ended December 31,
		2012				2011
		(in millions)
Beginning asset retirement obligations		$	11.8			$	10.0
Revisions to existing liabilities			0.2				1.0
Liabilities incurred			0.5				0.4
Liabilities settled			—				(0.1	)
Liabilities assumed by others			—				(0.2	)
Accretion			0.7				0.7
Ending asset retirement obligations		$	13.2			$	11.8

 

9.	Commitments and Contingencies

Commitments

The Predecessor leases certain equipment and office space under operating lease arrangements. Total rental expense recognized under these operating leases was $27.8 million, $25.9 million and $27.8 million in 2012, 2011 and 2010, respectively.

In addition to its operating leases, the Predecessor has rights-of-way commitments that have remaining non-cancelable terms in excess of one year. The following schedule includes these long-term commitments and short-term commitments to purchase materials in connection with the Predecessor’s growth projects as of December 31, 2012:

 

Year Ending December 31,		Operating Leases				Rights-of- Way				Purchase Commitments
		(in millions)
2013		$	21.6			$	0.2			$	21.4
2014			5.2				0.1				—
2015			—				0.1				—
2016			—				0.1				—
2017			—				0.1				—
Thereafter			—				0.5				—
Total		$	26.8			$	1.1			$	21.4

Litigation Contingencies

The Predecessor is involved in various routine legal actions and proceedings arising in the normal course of its business. However, to the Predecessor’s knowledge, there were no material pending legal proceedings to which the Predecessor is a party or to which any of its property is subject.

Environmental Contingencies

The operation of pipelines, plants and other facilities for gathering, processing or transmitting 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, the Predecessor must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing

 

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and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Predecessor’s results of operations, financial condition or cash flows. At December 31, 2012, Predecessor had $0.4 million of liabilities recorded for environmental matters which are included in other long-term liabilities in the accompanying combined balance sheet.

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

COMBINED STATEMENTS OF OPERATIONS

 

		Six Months Ended June 30,
		2013				2012
		(unaudited)
		(in millions)
Operating revenues:
Operating revenues – affiliates		$	1,059.3			$	865.2
Operating revenues			103.1				93.7
Total operating revenues			1,162.4				958.9
Operating expenses:
Product purchases – affiliates			780.7				624.4
Product purchases			81.4				71.3
Operations and maintenance			60.1				61.1
Operations and maintenance – affiliates			22.6				22.5
Depreciation and amortization			96.8				78.3
General and administrative – affiliates			22.4				21.6
Non-income taxes			9.0				8.8
Other, net			1.5				(3.5	)
Total operating expenses			1,074.5				884.5
Operating income			87.9				74.4
Income (loss) from equity investment			4.4				(0.5	)
Income from continuing operations before income taxes			92.3				73.9
Income tax expense			33.2				26.6
Net income from continuing operations			59.1				47.3
Discontinued operations:
Net income from discontinued operations			4.3				3.1
Net income from discontinued operations attributable to non-controlling interests			(1.2	)			(0.6	)
Net income from discontinued operations attributable to Devon			3.1				2.5
Net income attributable to Devon		$	62.2			$	49.8

See accompanying notes to the unaudited combined financial statements.

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

COMBINED BALANCE SHEETS

 

		Pro Forma June 30, 2013				June 30, 2013				December 31, 2012
		(unaudited)				(unaudited)
		(in millions)
Assets
Current assets:
Inventories		$	4.4			$	4.4			$	5.5
Prepaid expenses			—				—				4.2
Assets held for sale			20.6				20.6				21.4
Other			0.3				0.3				0.3
Total current assets			25.3				25.3				31.4
Property, plant and equipment, at cost			3,126.9				3,126.9				2,985.8
Less accumulated depreciation and amortization			(1,241.7	)			(1,241.7	)			(1,142.6	)
Net property, plant and equipment			1,885.2				1,885.2				1,843.2
Equity investment			62.3				62.3				57.7
Goodwill			401.7				401.7				401.7
Assets held for sale			202.2				202.2				201.2
Total assets		$	2,576.7			$	2,576.7			$	2,535.2
Liabilities and Equity
Current liabilities:
Distribution payable		$				$	—			$	—
Accrued expenses and other			69.7				69.7				80.1
Current liabilities associated with assets held for sale			3.7				3.7				3.3
Total current liabilities							73.4				83.4
Asset retirement obligations			14.8				14.8				13.2
Deferred income taxes			426.3				426.3				431.8
Other			5.1				5.1				4.8
Total liabilities							519.6				533.2
Equity:
Devon equity							2,009.5				1,953.3
Non-controlling interests							47.6				48.7
Total equity							2,057.1				2,002.0
Commitments and contingencies (Note 6)
Total liabilities and equity		$	2,576.7			$	2,576.7			$	2,535.2

See accompanying notes to the unaudited combined financial statements.

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

COMBINED STATEMENTS OF EQUITY

 

		Six Months Ended June 30,
		2013				2012
		(unaudited)
		(in millions)
Devon equity
Balance as of beginning of year		$	1,953.3			$	1,856.0
Net income			62.2				49.8
Net distributions from (to) Devon – continuing operations			(3.5	)			35.8
Net distributions to Devon – discontinued operations			(2.5	)			(3.1	)
Balance as of end of year		$	2,009.5			$	1,938.5
Non-controlling interests
Balance as of beginning of year		$	48.7			$	45.3
Net income			1.2				0.6
Net distributions from (to) non-controlling interests – discontinued operations			(2.3	)			4.8
Balance as of end of year		$	47.6			$	50.7
Total equity
Balance as of beginning of year		$	2,002.0			$	1,901.3
Net income			63.4				50.4
Net distributions from (to) Devon – continuing operations			(3.5	)			35.8
Net distributions from (to) Devon and non-controlling interests – discontinued operations			(4.8	)			1.7
Balance as of end of year		$	2,057.1			$	1,989.2

See accompanying notes to the unaudited combined financial statements.

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

COMBINED STATEMENTS OF CASH FLOWS

 

		Six Months Ended June 30,
		2013				2012
		(unaudited)
		(in millions)
Cash flows from operating activities:
Net income from continuing operations		$	59.1			$	47.3
Adjustments to reconcile net income from continuing operations to net cash provided by operating activities:
Depreciation and amortization			96.8				78.3
Deferred income tax benefit			(5.2	)			(5.7	)
(Income) loss from equity investment, net of distributions			(4.4	)			2.8
Changes in assets and liabilities:
Inventories			1.1				(1.4	)
Prepaid expenses			4.2				4.3
Other assets			(0.2	)			0.5
Accrued expenses and other liabilities			12.7				1.6
Net cash provided by operating activities			164.1				127.7
Cash flows from investing activities:
Capital expenditures			(160.6	)			(148.2	)
Contribution to equity investment			—				(13.7	)
Net cash used in investing activities			(160.6	)			(161.9	)
Cash flows from financing activities:
Net distributions from (to) Devon			(3.5	)			35.8
Other			—				(1.6	)
Net cash provided by (used in) financing activities			(3.5	)			34.2
Cash flows from discontinued operations:
Net cash provided by operating activities.			3.5				16.2
Net cash used in investing activities			(0.3	)			(11.5	)
Net cash provided by (used in) financing activities – net distributions from (to) Devon and non-controlling interests			(4.8	)			1.7
Net cash provided by (used in) discontinued operations			(1.6	)			6.4
Net change in cash and cash equivalents			(1.6	)			6.4
Beginning cash and cash equivalents – related to assets held for sale			15.6				8.1
Ending cash and cash equivalents – related to assets held for sale		$	14.0			$	14.5

See accompanying notes to the unaudited combined financial statements.

 

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DEVON MIDSTREAM HOLDINGS, L.P. PREDECESSOR

NOTES TO UNAUDITED CONDENSED COMBINED FINANCIAL STATEMENTS

 

1.	Organization and Nature of Business

The accompanying financial statements of Devon Midstream Holdings, L.P. Predecessor (the “Predecessor”) have been prepared in connection with the proposed initial public offering of limited partner units in Devon Midstream Partners, L.P. (the “Partnership”). Formed in Delaware in September 2013, the Partnership is a subsidiary of Devon Energy Corporation (“Devon”). The Predecessor is comprised of Devon’s U.S. midstream assets and operations, including its 38.75% interest in Gulf Coast Fractionators.

As part of the initial public offering of limited partner units in the Partnership (the “Offering”), Devon will contribute certain of the Predecessor’s assets and operations to Devon Midstream Holdings, L.P. (“Devon Midstream Holdings”), which is a Delaware limited partnership to be formed. Devon will then contribute a 20% interest in Devon Midstream Holdings to the Partnership and will retain the remaining 80% interest. DLP GP, L.L.C. (“DLP”), a wholly-owned subsidiary of Devon, will serve as the general partner for the Partnership. Devon Midstream Holdings GP, L.L.C. will serve as the general partner for Devon Midstream Holdings. Devon will provide services to the Partnership pursuant to an omnibus agreement. DLP, the Partnership and Devon Midstream Holdings have all adopted December 31 fiscal year ends.

The Predecessor is engaged in the business of purchasing natural gas from Devon and third parties at or near the wellhead and then gathering, compressing, treating and processing the purchased natural gas and fractionating the natural gas liquids, or NGLs, that result from the natural gas processing. After performing these activities, the Predecessor sells its natural gas and NGLs to Devon. The Predecessor primarily performs these activities to support Devon’s operations. However, to the extent system capacity is available, the Predecessor also provides these services for other companies engaged in the production, distribution and marketing of natural gas and NGLs.

The Predecessor’s assets consist of Devon’s U.S. natural gas gathering and processing systems, as well as a 38.75% interest in Gulf Coast Fractionators. These systems and assets are located primarily in Texas and Oklahoma. The Barnett assets serve the Barnett Shale in North Texas. These assets include integrated gathering pipelines, one gas processing plant and an NGL fractionator. The Cana system serves the Cana-Woodford Shale in West Central Oklahoma. This system consists of integrated gathering pipelines and a natural gas processing plant. The Northridge system serves the Arkoma-Woodford Shale in Southeastern Oklahoma. This system consists of integrated gathering pipelines and a gas processing plant. Gulf Coast Fractionators is an NGL fractionator located on the Gulf Coast at the Mont Belvieu hub. The Predecessor’s other assets include systems that serve the Powder River Basin in Wyoming and other areas where Devon operates.

In connection with the initial public offering of limited partner units in the Partnership, Devon will contribute to Devon Midstream Holdings the Predecessor’s systems serving the Barnett, Cana-Woodford and Arkoma-Woodford Shales, as well as the 38.75% interest in Gulf Coast Fractionators.

 

2.	Basis of Presentation

These financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission. Pursuant to such rules and regulations, certain disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted. The accompanying combined financial statements and notes should be read in conjunction with the Predecessor’s audited combined financial statements and notes for the three-year period ended December 31, 2012.

The accompanying unaudited interim combined financial statements reflect all adjustments that are, in the opinion of management, necessary to a fair statement of the Predecessor’s financial position as of June 30, 2013

 

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and its results of operations and cash flows for the six-month periods ended June 30, 2013 and 2012. Due to seasonal fluctuations and other factors, the operating results for the six months ended June 30, 2013, are not necessarily indicative of the results that may be expected for the year ending December 31, 2013 or for any future period.

Pro Forma Information

The June 30, 2013 pro forma balance sheet reflects a pro forma distribution payable of $         million. This amount represents an estimate of the cash distribution expected to be made to Devon upon the closing of the Offering. This planned distribution represents reimbursement for capital expenditures paid by Devon on behalf of the Predecessor. The estimated cash distribution will be funded with the net proceeds received from the Offering. The actual distribution, if any, is dependent on the amount of net proceeds received from the Offering, including the price and number of units sold. Accordingly, the pro forma adjustment is an estimate that may differ materially from the actual distribution, if any.

 

3.	Affiliate Transactions

The Predecessor engages in various transactions with Devon and other affiliated entities. These transactions relate to sales to and from affiliates, services provided by affiliates, cost allocations from affiliates, centralized cash management performed by affiliates and financing with affiliates. Management believes these transactions are executed on terms that are fair and reasonable and are consistent with terms for transactions with nonaffiliated third parties. The amounts related to affiliate transactions are specified in the accompanying financial statements.

The following schedule presents the affiliate transactions and other transactions made to or received from Devon, all of which are settled through an adjustment to equity:

 

		Six Months Ended June 30,
		2013				2012
		(in millions)
Continuing operations:
Operating revenues – affiliates		$	(1,059.3	)		$	(865.2	)
Operating expenses – affiliates			825.7				668.5
Net affiliate transactions			(233.6	)			(196.7	)
Capital expenditures			160.6				148.2
Other third-party transactions, net			69.5				84.3
Total third-party transactions			230.1				232.5
Net distributions from (to) Devon – continuing operations		$	(3.5	)		$	35.8
Discontinued operations:
Operating revenues – affiliates		$	(13.6	)		$	(73.5	)
Operating expenses – affiliates			4.0				54.9
Cash used in financing activities – affiliates			(5.2	)			4.5
Net affiliate transactions			(14.8	)			(14.1	)
Capital expenditures			1.2				11.5
Other third-party transactions, net			8.8				4.3
Net third-party transactions			10.0				15.8
Net distributions from (to) Devon and non-controlling interests – discontinued operations		$	(4.8	)		$	1.7

 

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During the six-month periods ended June 30, 2013 and 2012, Devon was the Predecessor’s only significant customer. Devon accounted for 91% and 90% of the Predecessor’s operating revenues during the six-month periods in 2013 and 2012, respectively.

Share-based compensation costs included in the management services fee charged to the Predecessor by Devon were approximately $6.7 million and $6.0 million for the six months ended June 30, 2013 and 2012, respectively. Pension, postretirement and employee savings plan costs included in the management services fee charged to the Predecessor by Devon were approximately $3.9 million and $4.0 million for the six months ended June 30, 2013 and 2012, respectively. These amounts are included in general and administrative expenses in the accompanying statements of operations.

 

4.	Income Taxes

The Predecessor is a member of an affiliated group that files consolidated income tax returns. Income taxes are calculated based on each entity’s separate taxable income or loss. The components of income tax expense related to the Predecessor’s income from continuing operations are as follows:

 

		Six Months Ended June 30,
		2013				2012
		(in millions)
Current income tax expense:
U.S. federal		$	37.3			$	31.3
Various states			1.1				1.0
Total current tax expense			38.4				32.3
Deferred income tax benefit:
U.S. federal			(5.1	)			(5.5	)
Various states			(0.1	)			(0.2	)
Total deferred tax benefit			(5.2	)			(5.7	)
Total income tax expense		$	33.2			$	26.6

The following schedule reconciles the Predecessor’s total income tax expense and the amount computed by applying the statutory U.S. federal tax rate to income from continuing operations before income taxes:

 

		Six Months Ended June 30,
		2013				2012
		(in millions)
Expected income tax expense based on federal statutory rate of 35%		$	32.2			$	25.8
State income taxes, net of federal benefit			1.0				0.8
Total income tax expense		$	33.2			$	26.6

 

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5.	Discontinued Operations

The Predecessor is in the process of selling or has sold certain non-core assets that are presented as discontinued operations in the accompanying financial statements. The following schedule summarizes net income for the Predecessor’s discontinued operations:

 

		Six Months Ended June 30,
		2013				2012
		(in millions)
Operating revenues:
Operating revenues		$	8.8			$	10.5
Operating revenues – affiliates			13.6				73.5
Total operating revenues			22.4				84.0
Operating expenses:
Operating expenses			11.5				24.5
Operating expenses – affiliates			4.0				54.9
(Gain) loss on sale of assets, net			0.2				(0.3	)
Total operating expenses			15.7				79.1
Income before income taxes			6.7				4.9
Income tax expense			2.4				1.8
Net income			4.3				3.1
Net income attributable to non-controlling interests			(1.2	)			(0.6	)
Net income attributable to Devon		$	3.1			$	2.5

The following schedule presents the main classes of assets and liabilities associated with the Predecessor’s discontinued operations:

 

		June 30, 2013				December 31, 2012
		(in millions)
Cash and cash equivalents		$	14.0			$	15.6
Accounts receivable			4.3				3.7
Inventories			2.0				2.0
Other current assets			0.3				0.1
Total current assets			20.6				21.4
Property, plant and equipment			185.7				184.7
Goodwill			16.5				16.5
Total assets		$	222.8			$	222.6
Accounts payable		$	3.3			$	2.8
Other current liabilities			0.4				0.5
Total current liabilities			3.7				3.3
Asset retirement obligations			4.7				4.2
Other long-term liabilities			—				0.3
Total liabilities		$	8.4			$	7.8
Non-controlling interests in equity		$	47.6			$	48.7

 

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Divestiture Agreements

In May 2013, the Predecessor entered into an agreement to sell its controlling interest in its assets and operations located in Montana for approximately $10 million. This sales price is subject to customary adjustments for financial activity between the effective and closing date of the transaction.

In August 2013, the Predecessor sold its controlling interest in its assets and operations located in Wyoming for approximately $148 million.

 

6.	Commitments and Contingencies

Litigation Contingencies

The Predecessor is involved in various routine legal actions and proceedings arising in the normal course of its business. However, to the Predecessor’s knowledge, there were no material pending legal proceedings to which the Predecessor is a party or to which any of its property is subject.

Environmental Contingencies

The operation of pipelines, plants and other facilities for gathering, processing or transmitting 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, the Predecessor must comply with United States laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating pipelines, plants, and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures, including citizen suits, which can include the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of injunctions or restrictions on operation. Management believes that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on the Predecessor’s results of operations, financial condition or cash flows. At June 30, 2013, Predecessor had $0.4 million of liabilities recorded for environmental matters which are included in other long-term liabilities in the accompanying combined balance sheet.

 

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APPENDIX A

AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

DEVON MIDSTREAM PARTNERS, L.P.

To be filed by amendment.

 

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APPENDIX B

GLOSSARY OF TERMS

Bbls or barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil, as NGLs or other liquid hydrocarbons.

Bcf: One billion cubic feet of natural gas.

Bcf/d: One billion cubic feet per day.

Bcfe: One Bcf equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Btu: British thermal units.

condensate: Similar to crude oil and produced in association with natural gas gathering and processing.

dehydration: The process of removing liquids and moisture content from gas or other matter.

DOT: Department of Transportation.

EIA: Energy Information Administration.

EPA: Environmental Protection Agency.

FERC: Federal Energy Regulatory Commission.

field: The general area encompassed by one or more oil or gas reservoirs or pools that are located on a single geologic feature, that are otherwise closely related to the same geologic feature (either structural or stratigraphic).

fractionation: The process by which a mixed stream of natural gas liquids is separated into its constituent products.

Henry Hub: A pipeline interchange near Erath, Louisiana, where a number of interstate and intrastate natural gas pipelines interconnect through a header system operated by Sabine Pipe Line. It is the standard delivery point for the NYMEX natural gas futures contract in the U.S.

hydrocarbon: An organic compound containing only carbon and hydrogen.

Mcf: One thousand cubic feet of natural gas.

MMBtu: One million British thermal units.

MMBtu/d: One million British thermal units per day

MMcf: One million cubic feet of natural gas.

MMcfe: One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbls of crude oil, condensate or natural gas liquids.

MMcfe/d: One million cubic feet equivalent per day.

MMcf/d: One million cubic feet per day.

 

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natural gas: Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.

NGLs: Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane and natural gasoline.

NYMEX: New York Mercantile Exchange.

oil: Crude oil and condensate.

residue natural gas: The pipeline quality natural gas remaining after natural gas is processed.

SEC: United States Securities and Exchange Commission.

TBtu/d: One trillion British thermal units per day.

Tcf: One trillion cubic feet of natural gas.

Tcfe: One Tcf equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

throughput: The volume of product transported or passing through a pipeline, plant, terminal or other facility.

wellhead: The equipment at the surface of a well used to control the pressure; the point at which the hydrocarbons and water exit the ground.

workover: Operations on a completed production well to clean, repair and maintain the well for the purposes of increasing or restoring production.

 

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Through and including                     , 2013 (25 days after the date of this prospectus), all dealers that buy, sell or trade our common units, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 

Common Units

Representing Limited Partner Interests

Devon Midstream Partners, L.P.

 

 

PROSPECTUS

 

 

BofA Merrill Lynch

Barclays

                    , 2013

 

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Part II

Information not required in prospectus

 

ITEM 13.

OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than underwriting discounts) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the FINRA filing fee and the exchange listing fee the amounts set forth below are estimates.

 

SEC registration fee		$	54,560
FINRA filing fee		$	60,500
Printing and engraving expenses			*
Fees and expenses of legal counsel			*
Accounting fees and expenses			*
Transfer agent and registrar fees			*
Exchange listing fee			*
Miscellaneous			*
Total		$	*

 

*	To be filed by amendment.

 

ITEM 14.

INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other persons from and against all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of the general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference.

Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of the general partner or any of its direct or indirect subsidiaries.

Our general partner will enter into indemnification agreements (each, an “Indemnification Agreement”) with each of its officers and directors (each, an “Indemnitee”). Each Indemnification Agreement provides that our general partner will indemnify and hold harmless each Indemnitee against all expense, liability and loss (including attorney’s fees, judgments, fines or penalties and amounts to be paid in settlement) actually and reasonably incurred or suffered by the Indemnitee in connection with serving in their capacity as officers and directors of our general partner (or of any subsidiary of our general partner) or in any capacity at the request of our general partner or its board of directors to the fullest extent permitted by applicable law, including Section 18-108 of the Delaware Limited Liability Company Act in effect on the date of the agreement or as such laws may be amended to provide more advantageous rights to the Indemnitee. The Indemnification Agreement also provides that the general partner must advance payment of certain expenses to the Indemnitee, including fees of counsel, in advance of final disposition of any proceeding subject to receipt of an undertaking from the Indemnitee to return such advance if it is ultimately determined that the Indemnitee is not entitled to indemnification.

Any underwriting agreement entered into in connection with the sale of the securities offered pursuant to this registration statement will provide for indemnification of Devon Midstream Holdings and our general partner, their officers and directors, and any person who controls Devon Midstream Holdings and our general partner, including indemnification for liabilities under the Securities Act.

 

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ITEM 15.

RECENT SALES OF UNREGISTERED SECURITIES.

On September 19, 2013, in connection with the formation of Devon Midstream Partners, L.P., we issued (i) a non-economic general partner interest in us to DLP GP, L.L.C. and (ii) a 100% limited partner interest in us to Devon Gas Corporation for $1,000. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

 

ITEM 16.

EXHIBITS.

 

Exhibit Number				Description
1.1		*—		Form of Underwriting Agreement (including form of Lock-up Agreement)
3.1		—		Certificate of Limited Partnership of Devon Midstream Partners, L.P.
3.2		*—		Form of Amended and Restated Limited Partnership Agreement of Devon Midstream Partners, L.P. (included as Appendix A to the Prospectus)
5.1		*—		Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered.
8.1		*—		Opinion of Vinson & Elkins L.L.P. relating to tax matters.
10.1		*—		Form of Credit Agreement
10.2		*—		Form of Contribution, Conveyance and Assumption Agreement
10.3		*—		Form of Omnibus Agreement
10.4		*—		Form of Indemnification Agreement
10.5		*—		Form of Long Term Incentive Plan
21.1		*—		List of Subsidiaries of Devon Midstream Partners, L.P.
23.1		—		Consent of KPMG LLP
23.2		*—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.3		*—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
24.1		—		Powers of Attorney (contained on the signature pages to this Registration Statement)

The following documents are filed as exhibits to this registration statement:

 

*	To be filed by amendment.

 

ITEM 17.

UNDERTAKINGS.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being

 

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registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(1) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(2) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(3) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(4) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

The undersigned registrant hereby undertakes that:

(1) If the registrant is relying on Rule 430B:

(A) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(B) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(2) If the registrant is subject to Rule 430C, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with DLP GP, L.L.C. or its subsidiaries, and of fees, commissions, compensation and other benefits paid, or accrued to DLP GP, L.L.C. or its subsidiaries for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

 

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement (No. 333-             ) to be signed on its behalf by the undersigned, thereunto duly authorized, in Oklahoma City, Oklahoma, on September 27, 2013.

 

Each person whose signature appears below appoints Jeffrey A. Agosta and Lyndon C. Taylor, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or would do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them of their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Signature		Title		Date
/s/ David A. Hager David A. Hager		President and Chief Executive Officer, Director (Principal Executive Officer)		September 27, 2013
/s/ Jeffrey A. Agosta Jeffrey A. Agosta		Executive Vice President and Chief Financial Officer, Director (Principal Financial Officer and Principal Accounting Officer)		September 27, 2013
/s/ Darryl G. Smette Darryl G. Smette		Chief Operating Officer, Director		September 27, 2013
/s/ Lyndon C. Taylor Lyndon C. Taylor		Executive Vice President, General Counsel and Corporate Secretary, Director		September 27, 2013

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EXHIBIT INDEX

 

Exhibit Number				Description
1.1		*—		Form of Underwriting Agreement (including form of Lock-up Agreement)
3.1		—		Certificate of Limited Partnership of Devon Midstream Partners, L.P.
3.2		*—		Form of Amended and Restated Limited Partnership Agreement of Devon Midstream Partners, L.P. (included as Appendix A to the Prospectus)
5.1		*—		Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered.
8.1		*—		Opinion of Vinson & Elkins L.L.P. relating to tax matters.
10.1		*—		Form of Credit Agreement
10.2		*—		Form of Contribution, Conveyance and Assumption Agreement
10.3		*—		Form of Omnibus Agreement
10.4		*—		Form of Indemnification Agreement
10.5		*—		Form of Long Term Incentive Plan
21.1		*—		List of Subsidiaries of Devon Midstream Partners, L.P.
23.1		—		Consent of KPMG LLP
23.2		*—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.3		*—		Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
24.1		—		Powers of Attorney (contained on the signature pages to this Registration Statement)

 

*	To be filed by amendment.