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.

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

LOGO

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 .

LOGO

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


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


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.

iii

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.

SUMMARY

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements, before investing in our common units. The information presented in this prospectus assumes, unless otherwise indicated, (i) an initial public offering price of $ per common unit (the mid-point of the price range set forth on the cover of this prospectus) and (ii) that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” for information about important risks that you should consider before buying our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

Unless the context otherwise requires, references to “we,” “our,” “us” and “the partnership” refer to Devon Midstream Partners, L.P. and its subsidiaries, including Devon Midstream Holdings, L.P. (“Devon Midstream Holdings”), which is the holding company that will own all of our midstream assets. All references to Devon Midstream Holdings, L.P. Predecessor (the “Predecessor”) refer to the predecessor to 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. References to “Devon” refer to Devon Energy Corporation (the ultimate parent of Devon Midstream Partners, L.P.) and its subsidiaries, excluding Devon Midstream Partners, L.P. and its subsidiaries. References to “general partner” refer to DLP GP, L.L.C., our general partner.

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.

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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.

•

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.

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.

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.

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.

•

Long-term natural gas gathering and processing contracts—Devon Midstream Holdings will enter into 10-year natural gas 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.”

•

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.

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 Escalator
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.”

Risk Factors

An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. The following list of risk factors should be read carefully in conjunction with the risks under the caption “Risk Factors” beginning on page 19.

Risks Related to Our Business

•

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.

•

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.

•

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.

Tax Risks to Common Unitholders

•

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.

Formation Transactions and Partnership Structure

We are a Delaware limited partnership recently formed by Devon to own, operate, develop and acquire midstream assets located in North America. At the closing of this offering, the following transactions, which we refer to as the formation transactions, will occur:

•

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 and Devon Midstream Holdings will enter into an omnibus agreement with Devon and certain of its affiliates that will govern our right of first offer to purchase Devon’s retained 80% interest in Devon Midstream Holdings and certain related indemnification matters;

•

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 an aggregate % 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;

•

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.”

Ownership of Devon Midstream Partners, L.P.

The following is a simplified diagram of our ownership structure after giving effect to this offering and the related transactions.

LOGO


Public Common Units			% (1)
Interests of Devon:
Common Units			% (1)
Subordinated Units			%
Incentive Distribution Rights			— (2)
Non-economic General Partner Interest			0.0% (3)

Total			100.0%

(1)	Assumes the underwriters do not exercise their option to purchase additional common units. Any common units not purchased by the underwriters will be issued to Devon for no additional consideration.

(2)

Incentive distribution rights represent a variable interest in distributions and thus are not expressed as a fixed percentage. Please read “How We Make Distributions To Our Partners—Incentive Distribution Rights.” Distributions with respect to the incentive distribution rights will be classified as distributions with respect to equity interests. All of our incentive distribution rights will be issued to Devon.

(3)	Our general partner owns a non-economic general partner interest in us. Please read “How We Make Distributions To Our Partners—General Partner Interest.”

Management of Our Partnership

DLP GP, L.L.C., our general partner, has sole responsibility for conducting our business and for managing our operations and will be controlled by Devon. Neither our general partner, nor any of its affiliates, will receive any compensation in connection with the management of our business, but they will be entitled to reimbursement for all direct and indirect expenses they incur on our behalf. Some of Devon’s executive officers will also serve as executive officers and directors of our general partner. Neither our general partner nor the board of directors of our general partner will be elected by our unitholders. As a result of its ownership of our general partner, Devon will have the right to elect the entire board of directors of our general partner. We will have at least three directors who are independent as defined under the independence standards established by the NYSE. For more information about our current directors and executive officers, please read “Management—Directors and Executive Officers.”

In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, various operating subsidiaries. However, neither we nor our subsidiaries will have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by Devon or others. All of the personnel that will conduct our business immediately following the closing of this offering will be employed or contracted by our general partner and its affiliates, including Devon, but we sometimes refer to these individuals in this prospectus as our employees because they provide services directly to us.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 333 West Sheridan Avenue, Oklahoma City, Oklahoma, and our telephone number is (405) 235-3611. Our website will be located at . We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (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.

Conflicts of Interest and Fiduciary Duties

General. Under our partnership agreement, our general partner has a duty to manage us in a manner it believes to be in the best interests of our partnership. However, because our general partner is a wholly-owned subsidiary of Devon, the officers and directors of our general partner also have a duty to manage our general partner in a manner that is in the best interests of Devon. Consequently, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including Devon, on the other hand.

Partnership agreement modifications to fiduciary duties. Delaware law 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, provided that partnership agreements may not eliminate the implied contractual covenant of good faith and fair dealing. This implied covenant is a judicial doctrine utilized by Delaware courts in connection with interpreting ambiguities in partnership agreements and other contracts, and does not form the basis of any separate or independent fiduciary duty in addition to the express contractual duties set forth in our partnership agreement. Under the implied contractual covenant of good faith and fair dealing, a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action.

As permitted by Delaware law, our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of the general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duties. Our partnership agreement also provides that affiliates of our general partner, including Devon, are not restricted from competing with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

The Offering

Common units offered to the public

common units.

common units if the underwriters exercise their option to purchase an additional common units (the “option units”) in full.

Units outstanding after this offering

common units and subordinated units, for a total of limited partner units, regardless of whether or not the underwriters exercise their option to purchase any of the option units. Of this amount, common units will be issued to Devon at the closing of this offering and, assuming the underwriters do not exercise their option to purchase any of the option units, all such option units will be issued to Devon 30 days following this offering, upon the expiration of the underwriters’ option exercise period. However, if the underwriters exercise their option to purchase any portion of the option units, we will (i) issue to the public the number of option units purchased by the underwriters pursuant to such exercise and (ii) issue to Devon, upon the expiration of the option exercise period, all remaining option units. Any such option units issued to Devon will be issued for no additional consideration. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. In addition, our general partner will own a non-economic general partner interest in us.

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.

Cash distributions

Upon completion of this offering, our partnership agreement will provide for a minimum quarterly distribution of $ per common unit and subordinated unit ($ per common unit and subordinated unit on an annualized basis) to the extent we have sufficient cash after establishment of reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.”

For the first quarter that our common units are publicly traded, we will pay a prorated distribution covering the period from the completion of this offering through , 2013, based on the actual length of that period.

Our partnership agreement requires us to distribute all of our available cash each quarter in the following manner:

•

first, to the holders of common units, until each common unit has received the minimum quarterly distribution of $ plus any arrearages from prior quarters;

•

second, to the holders of subordinated units, until each subordinated unit has received the minimum quarterly distribution of $ ; and

•

third, to all unitholders, pro rata, until each unit has received a distribution of $ .

If cash distributions to our unitholders exceed $ per unit in any quarter, the holders of our incentive distribution rights will receive distributions according to the following percentage allocations:


	Marginal Percentage Interest in Distributions
Total Quarterly Distribution Target Amount	Unitholders			Holder of Our Incentive Distribution Rights
$		100.0	%	—
above $ up to $		100.0	%	—
above $ up to $		85.0	%	15.0%
above $ up to $		75.0	%	25.0%
above $		50.0	%	50.0%

We refer to these distributions as “incentive distributions.” Please read “How We Make Distributions to Our Partners.”

If we do not have sufficient available cash at the end of each quarter, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

We believe, based on our financial forecast and related assumptions included in “Our Cash Distribution Policy and Restrictions on Distributions,” that we will have sufficient available cash to pay the minimum quarterly distribution of $ on all of our common units and subordinated units for each quarter in the twelve months ending September 30, 2014. However, we do not have a legal obligation to pay quarterly distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement. There is no guarantee that we will distribute quarterly cash distributions to our unitholders in any quarter. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Subordinated units

Devon will initially indirectly own all of our subordinated units. The principal difference between our common units and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid distributions of available cash of at least (i) $ (the minimum quarterly distribution on an annualized basis) on each outstanding common and subordinated unit for each of three consecutive, non-overlapping four-quarter periods ending on or after , 2016, or (ii) $ (150% of the annualized minimum quarterly distribution) on each outstanding common and subordinated unit and the related distributions on the incentive distribution rights for any four-quarter period ending on or after , 2014, in each case provided there are no arrearages in the payment of the minimum quarterly distributions on our common units at that time.

The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holder(s) of subordinated units or their affiliates are voted in favor of that removal.

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and thereafter common units will no longer be entitled to arrearages. See “How We Make Distributions to Our Partners—Subordination Period.”

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Interests.”

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66²⁄₃% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, Devon will indirectly own an aggregate of % of our outstanding voting units (or % of our outstanding voting units, if the underwriters exercise their option to purchase additional common units in full). This will give Devon the ability to prevent the removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner will have the right, but not the obligation, to purchase all of the remaining common units 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. Please read “The Partnership Agreement—Limited Call Right.”

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending , 2013 you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $ per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read “Material U.S. Federal Income Tax Consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read “Material U.S. Federal Income Tax Consequences.”

Exchange listing

We intend to apply to list our common units on the NYSE under the symbol “DVNM.”

Summary 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 summary 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 summary 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.

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 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;

•

we will acquire a non-economic general partner interest and a 20% limited partner interest in Devon Midstream Holdings;

•

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

•

The following table presents the summary historical financial and operating data of Devon Midstream Holdings Predecessor and our summary 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
	(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
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
Adjusted EBITDA attributable to Devon Midstream Partners, L.P. (20%)	$	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
NGL production (MBbls/d)								81.9			65.9			71.0			69.7			62.1
Residue natural gas production (thousands of MMBtu/d)								942.1			875.0			895.7			838.9			636.5

Statement of Income Data
Operating revenues	$	296.5		$	581.7		$	1,162.4		$	958.9		$	2,000.8		$	2,623.4		$	2,016.0
Operating expenses		(190.3	)		(349.9	)		(1,074.5	)		(884.5	)		(1,899.2	)		(2,311.8	)		(1,766.9	)

Operating income		106.2			231.8			87.9			74.4			101.6			311.6			249.1
Income (loss) from equity investment		4.4			2.0			4.4			(0.5	)		2.0			9.3			5.1
Income tax expense		(1.1	)		(1.7	)		(33.2	)		(26.6	)		(37.3	)		(115.5	)		(91.5	)

Net income from continuing operations		109.5			232.1			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		109.5			232.1		$	62.2		$	49.8		$	75.8		$	216.1		$	178.7

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	$			$


	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
	(unaudited)			(unaudited)
	(in millions, except per unit and operating data)
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
Total assets	$	2,223.9		$	2,576.7		$	2,526.0		$	2,535.2		$	2,446.3		$	2,336.0
Total long-term liabilities	$	17.4		$	446.2		$	456.2		$	449.8		$	461.0		$	418.0
Total equity	$	2,140.2		$	2,057.1		$	1,989.2		$	2,002.0		$	1,901.3		$	1,849.0

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 “—Non-GAAP Financial Measure.”

Non-GAAP Financial Measure

We include in this prospectus the non-GAAP financial measure “Adjusted EBITDA.” We provide this measure because 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 provide reconciliations of Adjusted EBITDA to its most directly comparable financial measures as calculated and presented in accordance with GAAP. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Additionally, because this measure may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility as a comparative measure.

Adjusted EBITDA

We use Adjusted EBITDA as a performance and 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. 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, depreciation and amortization expense and asset impairments. We use Adjusted EBITDA 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.

The GAAP measures most directly comparable to Adjusted EBITDA are net cash provided by operating activities and net income from continuing operations. The non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to the GAAP measures of net cash flows provided by operating activities and net income from continuing operations. Adjusted EBITDA is not a presentation made in accordance with GAAP and has important limitations as an analytical tool because it includes some, but not all, items that affect net cash provided by operating activities and income from continuing operations.

The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to its most directly comparable GAAP financial measures.


	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
	(unaudited)						(unaudited)
	(in millions)
Net income from continuing operations	$	109.5		$	232.1		$	59.1		$	47.3		$	66.3		$	205.4		$	162.7
Add:
Depreciation and amortization		90.6			145.4			96.8			78.3			159.8			144.8			124.9
Asset impairments		—			16.4			—			—			50.1			—			—
Income tax expense		1.1			1.7			33.2			26.6			37.3			115.5			91.5
Equity investment depreciation		1.5			2.1			1.5			0.7			2.1			1.5			1.4
Equity investment income tax expense		0.1			0.1			0.1			0.1			0.1			0.2			0.1

Adjusted EBITDA attributable to Devon Midstream Holdings and our Predecessor (100%)		202.8			397.8			190.7			153.0			315.7			467.4			380.6
Less: Adjusted EBITDA attributable to non-controlling interests		(162.2	)		(318.2	)

Adjusted EBITDA attributable to Devon Midstream Partners, L.P. (20%)	$	40.6		$	79.6

Add (deduct):
Current income tax expense								(38.4	)		(32.3	)		(47.0	)		(73.5	)		(0.4	)
Changes in assets and liabilities								17.8			5.0			(10.6	)		8.0			2.1
Other								(6.0	)		2.0			(3.7	)		(0.7	)		9.2

Net cash provided by operating activities							$	164.1		$	127.7		$	254.4		$	401.2		$	391.5

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

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;

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our debt service requirements and other liabilities;

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

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fluctuations in our working capital needs;

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restrictions on distributions contained in any of our debt agreements;

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the cost of acquisitions, if any;

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

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

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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

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 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.

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:

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

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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;

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

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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:

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the level of capital expenditures it makes;

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its debt service requirements and other liabilities;

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restrictions contained in its debt agreements;

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its ability to borrow funds;

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fluctuations in its working capital needs;

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the cost of acquisitions, if any; and

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the amount of cash reserves established by it.

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:

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environmental or other governmental regulations;

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weather conditions;

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increases in storage levels of natural gas and NGLs;

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increased use of alternative energy sources;

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decreased demand for natural gas and NGLs;

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

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economic conditions;

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supply disruptions;

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

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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

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:

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

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

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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;

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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;

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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.

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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;

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geologic considerations;

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

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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.

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

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

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;

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

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improve data collection, integration and analysis;

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repair and remediate the pipeline as necessary; and

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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.

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:

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

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

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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;

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fires, ruptures and explosions; and

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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.

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.

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.

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:

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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;

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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;

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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;

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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;

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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;

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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;

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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;

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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;

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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;

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

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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.

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:

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

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whether to exercise its call right;

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

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whether to exercise its registration rights;

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whether to elect to reset target distribution levels; and

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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.”

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 66²⁄₃% 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:

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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;

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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;

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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

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

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:

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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

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.

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.

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

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.

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.”

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

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.

USE OF PROCEEDS

•

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.

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 $ .

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		$

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.

•

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.

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

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

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.

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

(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

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.

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	$

(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.

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

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

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

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:

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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;

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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

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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.

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:

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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.

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

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:

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provide for the proper conduct of our business;

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

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

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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.

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:

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$ million (as described below); plus

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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

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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

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

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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

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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

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:

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

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

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expansion capital expenditures;

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

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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;

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

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

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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:

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borrowings other than working capital borrowings;

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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.

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:

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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

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

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:

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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:

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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;

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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.

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:

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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

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:

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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
	Total Quarterly Distribution per Unit Target Amount		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	%

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:

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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;

•

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

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
	Quarterly Distribution per Unit Prior to 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 $

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

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.

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.

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.

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.

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


	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.”

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

•

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:

•

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

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.

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.

•

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.

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.

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.”

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.

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.

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.

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

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.

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.

Discontinued Operations

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

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.

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.

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

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.

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:

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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.

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:

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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.

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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.

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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:

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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.

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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.

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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.

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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.

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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:

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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.

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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

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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

LOGO

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

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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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	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

About Devon

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Business Strategies

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.

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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:

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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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Our Contractual Relationship 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.

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:

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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
Gathering and Transmission Pipelines	Approximate Length (Miles)		Approximate Receipt Points		(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
Processing and Fractionation Facilities	Processing Capacity (MMcf/d)		Estimated NGL Production Capacity (MBbls/d)				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 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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The following map identifies the locations of the principal assets comprising Devon Midstream Holdings’ Barnett assets:

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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.

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.

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:

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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.

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:

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David A. Hager—President and Chief Executive Officer

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Darryl G. Smette—Chief Operating Officer

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Jeffrey A. Agosta—Executive Vice President and Chief Financial Officer

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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:

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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:

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each person who then will beneficially own 5% or more of the then outstanding units;

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each director and named executive officer of our general partner; and

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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 no

Position with DLP GP, L.L.C.

David A. Hager

President and Chief Executive Officer/Director

Darryl G. Smette

Chief Operating Officer/Director

Jeffrey A. Agosta

Executive Vice President and Chief Financial Officer/Director

Lyndon C. Taylor

Executive Vice President, General Counsel and Corporate Secretary/Director

Devon Midstream Partners, L.P. S-1