Ocean Rig Partners DRS/A Draft registration statement (amended)

Submitted on a confidential basis on July 24, 2014

CONFIDENTIAL TREATMENT REQUESTED

This draft registration statement has not been filed publicly with the Securities and Exchange Commission

and all information contained herein remains confidential.

Registration No. 333-          

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM F-1

REGISTRATION STATEMENT

Under

THE SECURITIES ACT OF 1933

Ocean Rig Partners LP

(Exact name of Registrant as specified in its charter)

Republic of the Marshall Islands	1381	N/A
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

c/o Ocean Rig Management Inc. 109 Kifisias Ave. and Sina Str. GR-15124, Amaroussion Athens, Greece 011 30 210 81 28 600	Seward & Kissel LLP Attention: Gary J. Wolfe, Esq. One Battery Park Plaza New York, New York 10004 (212) 574-1200
(Address and telephone number of Registrant’s principal executive offices)	(Name, address and telephone number of agent for service)

Copies to:

Gary J. Wolfe, Esq. Robert E. Lustrin, Esq. Seward & Kissel LLP One Battery Park Plaza New York, New York 10004 (212) 574-1200 (telephone number) (212) 480-8421 (facsimile number) Sean T. Wheeler Latham and Watkins LLP 811 Main Street, Suite 3700 Houston, Texas 77002 (713) 546-5400 (telephone number) (713) 546-5401 (facsimile number)

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 being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act, 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, please 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.  ¨

CALCULATION OF REGISTRATION FEE

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

(1) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) under the Securities Act of 1933.

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 Commission, acting pursuant to said Section 8(a), may determine.

The information in this Prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This Prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject To Completion, dated             , 2014

PROSPECTUS

[LOGO]

Ocean Rig Partners LP

                 Common Units

Representing Limited Partner Interests

This is the initial public offering of the common units representing limited partner interests in Ocean Rig Partners LP. We are offering              of our common units. No public market currently exists for our common units.

We have applied to list our common units on the Nasdaq Global Select Market under the symbol “ORLP.”

We anticipate that the initial public offering price will be between $             and $             per share.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act (the “JOBS Act”). See “Summary—Implications of Being an Emerging Growth Company.”

Investing in our common units involves risk. See “Risk Factors” beginning on page 20 of this prospectus.

• OPCO’s, Initial Fleet consist of interests in only three drillships. Any limitation in the availability or operation of these vessels could have a material adverse effect on our business, results of operations and financial condition and could significantly reduce or eliminate our ability to pay the minimum quarterly distribution on our common units and subordinated units.

• Because our ownership interest in OPCO represents our only cash-generating asset, our cash flow initially will depend completely on OPCO’s ability to make distributions to us as one of its owners.

• We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay the minimum quarterly distribution on our common units and subordinated units.

• Our growth depends on the level of activity in the offshore oil and natural gas industry, which is significantly affected by, among other things, volatile oil and natural gas prices, and may be materially and adversely affected by a decline in the offshore oil and natural gas industry.

• Restrictions in OPCO’s financing agreements, including the New Senior Secured Term Loan Facility, may prevent it or us from paying distributions.

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

• Our General Partner and its affiliates, including our Sponsor, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of our Sponsor, and our Sponsor is under no obligation to adopt a business strategy that favors us.

• 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, and you could lose all or part of your investment.

• You will experience immediate and substantial dilution of $             per common unit.

• U.S. tax authorities could treat us as a “passive foreign investment company,” which would have adverse U.S. federal income tax consequences to U.S. unitholders.

	Per CommonUnit	Total
Price to the public	$	$
Underwriting discounts and commissions(1)	$	$
Proceeds to us (before expenses)	$	$

(1) See “Underwriting” for additional information regarding underwriting compensation.

We have granted the underwriters the option to purchase additional common units on the same terms and conditions set forth above if the underwriters sell more than sell more than              common units in this offering.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities orpassed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units on our about             , 2014

Barclays Credit Suisse Deutsche Bank Securities

Prospectus dated             , 2014.

[HIGH RESOLUTION INSIDE COVER ART TO BE INSERTED]

TABLE OF CONTENTS

PROSPECTUS SUMMARY	1
THE OFFERING	12
SUMMARY FINANCIAL AND OPERATING DATA	16
FORWARD-LOOKING STATEMENTS	18
RISK FACTORS	20
USE OF PROCEEDS	53
CAPITALIZATION	54
DILUTION	55
OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS	56
OCEAN RIG PARTNERS LP FORECASTED RESULTS OF OPERATIONS	60
OCEAN RIG PARTNERS LP FORECASTED CASH AVAILABLE FOR DISTRIBUTION	69
HOW WE MAKE CASH DISTRIBUTIONS	72
SELECTED HISTORICAL COMBINED FINANCIAL AND OPERATING DATA	85
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	87
THE OFFSHORE DRILLING INDUSTRY	96
SUMMARY OF CERTAIN INDUSTRY TERMS	111
BUSINESS	113
MANAGEMENT	128
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	132
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	133
CONFLICTS OF INTEREST AND FIDUCIARY DUTIES	143
DESCRIPTION OF THE COMMON UNITS	149
OUR PARTNERSHIP AGREEMENT	151
UNITS ELIGIBLE FOR FUTURE SALE	164
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS	165
NON-UNITED STATES TAX CONSIDERATIONS	171
UNDERWRITING	172
SERVICE OF PROCESS AND ENFORCEMENT OF CIVIL LIABILITIES	179
LEGAL MATTERS	179
EXPERTS	179
WHERE YOU CAN FIND ADDITIONAL INFORMATION	180
OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION	181
INDEX TO FINANCIAL STATEMENTS	F-1

You should rely only on information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to give any information or to make any representations other than those contained in this prospectus. Do not rely upon any information or representations made outside of this prospectus. This prospectus is not an offer to sell, and it is not soliciting an offer to buy, (1) any securities other than our common units or (2) our common units in any circumstances in which such an offer or solicitation is unlawful. The information contained in this prospectus may change after the date of this prospectus. Do not assume after the date of this prospectus that the information contained in this prospectus is still correct.

Through and including             , 2014 (the 25th day after the date of this prospectus), federal securities law may require all dealers that effect transactions in these securities, whether or not participating in this offering, to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. Unless we otherwise specify, all references to information and data in this prospectus about our business and fleet refer to our business and fleet immediately after the closing of this offering. You should read the entire prospectus carefully, including the historical financial statements and the notes to those financial statements. The information presented in this prospectus assumes, unless otherwise noted, (i) an initial public offering price of $         per common unit (based on the midpoint of the 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 more information about important risks that you should consider carefully before buying our common units. Unless otherwise indicated, all references to “dollars” and “$” in this prospectus are to, and amounts are presented in the lawful currency of the United States, U.S. Dollars.

All references in this prospectus to “Ocean Rig Partners,” “we,” “our,” “us,” and “the Partnership” refer to Ocean Rig Partners LP and its subsidiaries, as the context requires. References in this prospectus to “our General Partner” refer to Ocean Rig Partners GP LLC, our general partner, which holds a non-economic general partner interest in us. References in this prospectus to “our Sponsor” and “Ocean Rig” refer, as the context requires, to Ocean Rig UDW Inc. (NASDAQ: ORIG) and its subsidiaries, other than us. References in this prospectus to “DryShips” refer, depending on the context to DryShips Inc. (NASDAQ: DRYS), the parent company of Ocean Rig, and to any one or more of its subsidiaries, other than us. Following the completion of this offering, we will own a % limited partner interest in Ocean Rig Operating LP and its wholly-owned subsidiaries, which we refer to as “OPCO.” In connection with the closing of this offering, Drillships Ocean Ventures II Inc. and its subsidiaries, or “DOV II,” which are wholly owned by OPCO, will purchase from Ocean Rig and certain of its subsidiaries, among other things, the drillships Ocean Rig Athena, Ocean Rig Mylos and Ocean Rig Skyros, which we refer to as OPCO’s Initial Fleet. The subsidiaries of Ocean Rig that prior to the closing of this offering had interests in the entities that own and operate the drillships in OPCO’s Initial Fleet including Drillships Ocean Ventures Inc., or DOV I, and its subsidiaries which are wholly owned subsidiaries of Ocean Rig, are referred to as the “Ocean Rig Partners LP Predecessor.” In addition, we will own the non-economic general partner interest in OPCO through our 100% ownership in its general partner, Ocean Rig Operating GP LLC. All references in this prospectus to “OPCO” when used in a historical context refer to OPCO’s predecessor companies and their subsidiaries, and when used in the present tense or prospectively refer to OPCO and its subsidiaries, collectively, or to OPCO individually, as the context may require.

References in this prospectus to “Ocean Rig Management” are to Ocean Rig Management AS, a wholly owned subsidiary of Ocean Rig that provides management services to us, including to DOV II.

References in this prospectus to “Respol,” “Total,” “ConocoPhillips,” “ENI” and “Petrobras” refer to Repsol Sinopec Brasil S.A., Total E&P Angola, ConocoPhillips Angola 36 & ConocoPhillips Angola 37 Ltd., ENI Angola S.p.A. and Petrobras Brazil, respectively, and to certain of each of their subsidiaries that are our and our Sponsor’s customers.

Overview

We are a growth-oriented limited partnership recently formed by Ocean Rig to own, operate and acquire offshore drilling units, including through our ownership interest in OPCO. OPCO’s Initial Fleet consists of three ultra-deepwater drillships theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena, all of which are currently in operation. The drillships that comprise OPCO’s Initial Fleet are employed under multi-year contracts with affiliates of major oil companies, including Repsol, Total and Conoco Phillips with an average remaining term of approximately 4.0 years as of June 13, 2014. We intend to grow our per unit distributions and our exposure to the offshore drilling market initially by acquiring additional interests in OPCO and at a later

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stage by acquiring ownership interests in other drilling units of our Sponsor and third parties, subject to limitations in our and our Sponsor’s debt and other agreements. OPCO intends to leverage the relationships, expertise and reputation of our Sponsor to operate OPCO’s Initial Fleet in an efficient manner, to re-contract OPCO’s Initial Fleet under multi-year contracts and to identify opportunities to expand upon OPCO’s Initial Fleet through other acquisitions. We also plan to grow through the acquisition of Additional Fleet Interests (defined below) and other acquisitions. We believe our Sponsor will be motivated to facilitate our growth because of its significant ownership interest in us. See “—Our Relationship with our Sponsor.”

OPCO’s Initial Fleet

We believe that OPCO’s Initial Fleet is one of the most modern fleets in the offshore drilling industry and all of the drillships in OPCO’s Initial Fleet were built during or after the third quarter of 2013. Upon completion of this offering, we will own a % interest, through OPCO, in theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena.These drillships are “sister-drillships” constructed by Samsung Heavy Industries Co. Ltd., or “Samsung,” to the same high-quality and provenEnhanced SAIPEM 10000 vessel design and specifications and are capable of drilling in water depths of up to 12,000 feet. We believe that owning and operating “sister-drillships” helps OPCO maintain cost efficient operations through shared inventory and use of spare parts and the ability of offshore maritime crews to work seamlessly across all of OPCO’s drillships.

The following table provides information about OPCO’s Initial Fleet as of June 13, 2014:

Drilling Unit	Year Built / Generation	Water Depth to Welhead (ft)		Drilling Depth to Oil Field (ft)		Customer	Expected Contract Term	Contract Backlog		Drilling Location
Operating Drillships
Ocean Rig Mylos	Q3 2013/7th		12,000		40,000	Repsol	Q4 2013–Q4 2016(1)	$	445 million	Brazil
Ocean Rig Skyros	Q4 2013/7th		12,000		40,000	Total(2)	Q1 2014–Q4 2014	$	93 million	Angola
						Total E&P Angola(2)	Q4 2015–Q3 2021	$	1.234 billion	West Africa
Ocean Rig Athena	Q1 2014/7th		12,000		40,000	ConocoPhillips	Q2 2014–Q2 2017(3)	$	681 million	Angola

(1) On November 4, 2013 theOcean Rig Mylos commenced drilling operations with Repsol at an average maximum dayrate of approximately $507,804 over the term of the contract.

(2) TheOcean Rig Skyros commenced a five well contract for a minimum of 275 days for drilling offshore West Africa with Total on March 2, 2014, with a maximum dayrate of $546,250 plus a mobilization fee of $29.0 million. This drillship is also contracted on a six year contract with Total for drilling operations offshore Angola. Under the new contract, we are entitled to a maximum dayrate of approximately $555,723, which is the average maximum dayrate applicable during the initial six-year term of the contract, plus mobilization fees of $20 million. Under the contract, the initial maximum dayrate of $513,000 is subject to a fixed annual escalation of 2% during the contract period.

(3) On March 24, 2014, theOcean Rig Athena was delivered from the shipyard and commenced drilling operations on June 7, 2014, at an average maximum dayrate of $623,045, which is the average maximum dayrate applicable during the initial three- year term of the contract. Under the contract, the initial maximum dayrate of $601,825 is subject to a fixed annual escalation of approximately 2% during the contract period.

Pursuant to the omnibus agreement that we will enter into with our Sponsor and our General Partner upon the completion of this offering, or the Omnibus Agreement, we will have the following purchase rights:

• a right of first offer to purchase additional interests in OPCO, which we refer to as Additional Fleet Interests;

• a right to purchase from our Sponsor any drilling units it acquires or any of its existing drillships that it employs under contracts of four or more years, which we refer to as the Four-Year Drillships; and

• a right to purchase interests in four drillships owned by our Sponsor,Ocean Rig Corcovado,Ocean Rig Olympia,Ocean Rig Poseidon, andOcean Rig Mykonos, which we refer to as the Optional Drillship Interests.

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Rights to Purchase Additional Interests in OPCO’s Fleet

We will have a right of first offer to purchase the Additional Fleet Interests from our Sponsor at a purchase price to be determined pursuant to the terms and conditions of the Omnibus Agreement. These purchase rights will expire 24 months following the completion of this offering. Please see “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Rights to Purchase Additional Interests in OPCO’s Fleet” for information on how the purchase price will be calculated.

Rights of First Offer on Drillships

Under the Omnibus Agreement, our Sponsor will agree (and will cause their subsidiaries, other than us, to agree) to grant a right of first offer to us for any Four-Year Drillships they might own. These rights of first offer will not apply to a (a) sale, transfer or other disposition of drillships between or among any affiliated subsidiaries, or the (b) merger with or into, or sale of all or substantially all of the assets to, an unaffiliated third-party. Please see “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Rights of First Offer on Drillships”

Right to Purchase Interests in the Optional Drillships

Pursuant to the Omnibus Agreement, we will have the right to purchase ownership interests, including the related drilling contracts, or the Optional Drillship Interests, in four sixth generation advanced capability ultra-deepwater drillships, currently 100% owned by our Sponsor. The purchase price for the Optional Drillships Interests will be determined pursuant to the terms and conditions of the Omnibus Agreement. These purchase rights will expire 36 months following the completion of the offering. Please see “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Rights to Purchase Optional Drillship Interests” for information on how the purchase price will be calculated. Please see “Risk Factors—Our Sponsor may be unable to service its debt requirements and comply with the provisions contained in the debt agreements secured by the Optional Drillships. If our Sponsor fails to perform its obligations under its debt agreements, our business and expected plans for growth may be materially affected” and “–Our Sponsor’s debt agreements, including its aggregate principal amount $800 million 6.5% senior secured notes due 2017, or the Senior Secured Notes due 2017, contain restrictions that may limit our growth plans.”

The Optional Drillships

The Optional Drillships consist of theOcean Rig Corcovado, theOcean Rig Olympia, theOcean Rig Poseidonand theOcean Rig Mykonos, delivered in January 2011, March 2011, July 2011 and September 2011, respectively. The Optional Drillships are “sister-ships” constructed by Samsung to the same high-quality vessel design and specifications and are capable of drilling up to 40,000 feet in water depths of up to 10,000 feet.

The following table provides information about the Optional Drillships as of June 13, 2014:

Drilling Unit	Year Built / Generation		Water Depth to Welhead (ft)		Drilling Depth to Oil Field (ft)		Customer	Expected Contract Term	Average Maximum Dayrate		Contract Backlog		Drilling Location
Operating Drillships
Ocean Rig Corcovado		2011/6th		10,000		40,000	Petrobras	Q2 2012–Q2 2015(1)		459,954	$	154,255	Brazil
Ocean Rig Olympia		2011/6th		10,000		40,000	Total	Q3 2012–Q3 2015(2)		589,032	$	252,394	Angola
Ocean Rig Poseidon		2011/6th		10,000		40,000	Eni	Q2 2013–Q2 2016(3)		700,452	$	507,379	Angola
Ocean Rig Mykonos		2011/6th		10,000		40,000	Petrobras	Q1 2012–Q1 2015		454,954	$	127,301	Brazil

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(1) TheOcean Rig Corcovadois currently employed under a three-year drilling contract, plus a mobilization period, with Petrobras for drilling operations offshore Brazil at an average maximum dayrate of $459,954 (including average service fees of $85,796 per day, based on the contracted rate in Real per day and the June 13, 2014 exchange rate of Real$2.24:$1.00, plus a mobilization fee of $30.0 million. The contract is scheduled to be completed in the second quarter of 2015.

(2) TheOcean Rig Olympiacommenced a three-year drilling contract with Total in July 2012 for drilling operations offshore West Africa at an average maximum dayrate of $589,032, plus mobilization and demobilization fees of $9.0 million and $3.5 million, respectively, plus the cost of fuel.

(3) TheOcean Rig Poseidoncommenced a three-year drilling contract with ENI in May 2013 for drilling operations offshore Angola at an average maximum dayrate of $700,452, which is the average maximum dayrate applicable during the initial three-year term of the contract. During the term of the contract, the initial maximum dayrate of $670,000 will increase annually at a rate of 3%, beginning twelve months after the commencement date. The contract also includes a mobilization rate of $656,600 per day, plus reimbursement for the cost of fuel, and a demobilization fee of $5.0 million.

(4) TheOcean Rig Mykonoscommenced a three-year drilling contract, plus a mobilization period, with Petrobras, on September 30, 2011, for drilling operations offshore Brazil at an average maximum dayrate of $454,954 (including average service fees of $84,863 per day, based on the contracted rate in Real and the June 13, 2014 exchange rate of Real$2.24:$1.00), plus a mobilization fee of $30.0 million. The contract is scheduled to expire in March 2015.

Our Relationship with our Sponsor

Ocean Rig, a corporation organized under the laws of the Republic of the Marshall Islands, was formed in 2007 as a wholly-owned subsidiary of DryShips for the purpose of acquiring offshore drilling rigs and drillships. As of the date hereof, Ocean Rig’s fleet, including OPCO’s Initial Fleet, includes 13 offshore ultra deepwater drilling units, comprised of two ultra deepwater semisubmersible drilling rigs and nine ultra deepwater drillships, two of which are scheduled to be delivered during 2015 and two of which are scheduled to be delivered during 2017. Ocean Rig’s shares commenced trading on the NASDAQ Global Select Market under the symbol “ORIG” on October 6, 2011.

One of our principal strengths is our relationship with our Sponsor. We expect our relationship with our Sponsor to give us access to its long-standing relationships with major energy companies and shipbuilders and its technical, commercial and managerial expertise. In addition, we expect to have access to our Sponsor’s customer and supplier relationships which we believe will allow us to compete more effectively when seeking additional customers. However, we can provide no assurance that we will realize any benefits from our relationship with our Sponsor.

Upon completion of this offering, our Sponsor will own all of our incentive distribution rights, through our General Partner, and a    % ownership interest in us as well as a    % interest in OPCO and thus will have significant incentives to contribute to our success.

We will be managed by the board of directors and executive officers of our General Partner. Our General Partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Ocean Rig owns all of the membership interests in our General Partner. Our common unitholders will not be entitled to elect the directors of our General Partner or to participate directly or indirectly in our management or operations.

Business Strategies

Our primary business objective is to increase the quarterly cash distributions to our unitholders over time. We intend to accomplish this objective by executing the following strategies:

• Grow Through Strategic and Accretive Acquisitions. We initially intend to capitalize on growth opportunities by acquiring from time to time Additional Fleet Interests from our Sponsor. In addition, we plan to grow through acquisitions of other offshore drilling units owned by our Sponsor or third

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parties, subject to the limitations imposed in our and our Sponsor’s debt agreements. Pursuant to the terms of the Omnibus Agreement, we will have a right of first offer to acquire or a right to purchase from our Sponsor, as the case may be, Additional Fleet Interests, Four Year Drillships and Optional Drillship Interests. We will not be obligated to purchase the Additional Fleet Interests, the Four-Year Drillships or the Optional Drillship Interests at the determined prices and, accordingly, we may not complete the purchase of such interests or vessels, which may have an adverse effect on our expected plans for growth. In addition, our ability to purchase the Additional Fleet Interests, Four-Year Drillships or the Optional Drillship Interests, should we exercise our right to purchase such interests, is dependent on our ability to obtain additional financing to fund all or a portion of the purchase price of these acquisitions. As of the date of this prospectus, we have not secured any financing in connection with our potential acquisition of Additional Fleet Interests or Optional Drillship Interests. In addition, debt arrangements of us and our Sponsor may restrict our ability to complete these acquisitions. Please see “Risk Factors—Our Sponsor may be unable to service its debt requirements and comply with the provisions contained in the debt agreements secured by the Optional Drillships. If our Sponsor fails to perform its obligations under its debt agreements, our business and expected plans for growth may be materially affected” and “—Our Sponsor’s debt agreements, including its aggregate principal amount $800 million 6.5% senior secured notes due 2017, or the Senior Secured Notes due 2017, contain restrictions that may limit our growth plans.”

• Pursue Multi-year contracts and Maintain Stable Cash Flow. We will seek to maintain stable cash flows by continuing to pursue multi-year contracts and focusing on minimizing operational downtime. Our focus on multi-year contracts improves the stability and predictability of our operating cash flows, which we believe will enable us to access equity and debt capital markets on attractive terms and, therefore, facilitate our growth strategy.

• Maintain a Modern and Reliable Fleet. We believe OPCO has a modern and technologically advanced fleet. In addition, OPCO’s Initial Fleet consists solely of ultra-deepwater drillships with the ability to operate at water depths of up to 12,000 feet. OPCO intends to grow its Initial Fleet over time in order to continue to meet its customers’ demands while optimizing its fleet size from an operational and logistical perspective.

• Provide Excellent Customer Service and Continue to Prioritize Safety As A Key Element Of Our Operations. Our and our Sponsor’s mission is to become the preferred offshore drilling contractors in the ultra-deepwater regions of the world and to deliver excellent performance to our clients by exceeding their expectations for operational efficiency and safety standards. We seek to deliver exceptional performance to our customers by consistently meeting or exceeding their expectations for operational performance, including by maintaining high safety standards and minimizing downtime.

We can provide no assurance, however, that we will be able to implement our business strategies described above. For further discussion of the risks that we face, please read “Risk Factors.”

Competitive Strengths

We believe we are well positioned to achieve our primary business objectives and execute our business strategies based on the following competitive strengths:

• Relationship with our Sponsor. We expect to rely on our relationship with our Sponsor to facilitate our acquisition and growth strategy, and we also expect to benefit from our Sponsor’s operational expertise and relationships with suppliers and shipyards. There is no assurance however that our Sponor will be able to maintain these relationships or reap the benefits of these relationships in order to facilitate our acquisition and growth strategy.

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• Focused and established track record in ultra-deepwater drilling operations. We believe that our Sponsor has a well-established record of operating drilling units with a primary focus on ultra-deepwater offshore locations and has gained significant experience operating in challenging environments through the completion of 185 wells for 30 different customers to date. We believe we will be able to capitalize on our high-specification drillships and we believe that we, through our Sponsor, have earned a reputation for operating performance excellence, customer service and safety.

• Modern, Technologically Advanced UDW Fleet. We believe that OPCO’s Initial Fleet is one of the most modern, technologically advanced fleets in the offshore drilling industry. OPCO’s Initial Fleet was built during or after the third quarter of 2013, with an average age of approximately four months and consists of ultra deepwater drillships with the ability to operate at water depths of up to 12,000 feet. We believe that OPCO’s modern fleet enables customers to drill wells more efficiently and more reliably than older drilling units.

• “Sister- Drillship” Efficiencies.We believe that OPCO’s fleet of sister drillships, which are vessels of the same type and specification, will enable OPCO to benefit from more chartering opportunities, economies of scale and operating and cost efficiencies in crew training, crew rotation and shared spare parts.

• Multi-year contracts with High Quality Customers. All of our revenues and associated cash flows are derived from OPCO’s existing multi-year contracts with large investment grade oil companies. As of June 13, 2014, these contracts have an average remaining term of 4.0 years, and we believe these contracts enhance the stability and predictability of our revenues.

We can provide no assurance, however, that we will be able to utilize our strengths described above. For further discussion of the risks that we face in implementing our business strategy, please read “Risk Factors.”

Risk Factors

An investment in our common units involves risks associated with our business, our limited partner structure and the tax characteristics of our common units. Those risks are described under “Risk Factors” beginning on page 18 of this prospectus.

Implications of Being an Emerging Growth Company

Our predecessor had less than $1.0 billion in revenue during its last fiscal year, which means that we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act, or the JOBS Act. An emerging growth company may take advantage of specified reduced reporting and other burdens that are otherwise applicable generally to public companies. These provisions include:

• the ability to present only two years of audited financial statements and only two years of related Management’s Discussion and Analysis of Financial Condition and Results of Operations in the registration statement of their initial public offering;

• exemption from the auditor attestation requirement in the assessment of the emerging growth company’s internal control over financial reporting;

• exemption from new or revised financial accounting standards applicable to public companies until such standards are also applicable to private companies; and

• exemption from compliance with any new requirements adopted by the Public Company Accounting Oversight Board, or the PCAOB, requiring mandatory audit firm rotation or a supplement to our auditor’s report in which the auditor would be required to provide additional information about the audit and our financial statements.

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We may take advantage of these provisions until the end of the fiscal year following the fifth anniversary of our initial public offering or such earlier time that we are no longer an emerging growth company. We will cease to be an emerging growth company if we have more than $1.0 billion in annual revenues, have more than $700 million in market value of our common units held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period. We may choose to take advantage of some, but not all, of these reduced burdens. For as long as we take advantage of the reduced reporting obligations, the information that we provide unitholders may be different than information provided by other public companies. We are choosing to “opt out” of the extended transition period relating to the exemption from new or revised financial accounting standards and, as a result, we will comply with new or revised accounting standards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 107 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

Formation Transactions

We were formed by our Sponsor on April 16, 2014 as a Marshall Islands limited partnership to hold ownership interests in OPCO and its subsidiaries, including DOV II and its subsidiaries, which will own and operate OPCO’s Initial Fleet.

The following transactions will occur at or prior to the closing of this offering:

• Our Sponsor will form (i) Ocean Rig Holdings Inc. or “OPCO Holdings” as a Marshall Islands corporation, which will be wholly owned by our Sponsor;

• We will form OPCO as a Marshall Islands limited partnership and Ocean Rig Operating GP LLC, a Marshall Islands limited liability company, or OPCO GP LLC, as the general partner of OPCO;

• OPCO will form DOV II and its subsidiaries, which will be wholly owned by OPCO;

• OPCO, through DOV II and its subsidiaries, will acquire theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena from DOV I, and will assume approximately $1.3 billion of outstanding debt under the Senior Secured Term Loan Facility (defined below) and our Sponsor will be unconditionally released as guarantor under this facility (in addition, DOV II and its subsidiaries will acquire from DOV I and its subsidiaries certain operating subsidiaries);

• We will redeem the initial limited partner interests held by our Sponsor and will refund our Sponsor’s initial contribution in the amount of $         made in connection with our formation and will:

• issue to our Sponsor              Common Units and              Subordinated Units;

• issue to our General Partner the non-economic general partner interest in us and all of the incentive distribution rights; and

• cause OPCO to issue to OPCO Holdings     % of its limited partner interests.

• In this public offering, we will issue              common units representing an aggregate     % limited partner interest in us. We estimate that we will receive net proceeds from this offering of $         million, of which $             million will be paid to our Sponsor through DOV I partial consideration for our interests in OPCO’s Initial Fleet. See Use of Proceeds;

• We will grant the underwriters a 30-day option to purchase up to additional              common units; and

In addition, at or prior to the closing of this offering:

• we will enter into the Omnibus Agreement with our Sponsor and our General Partner governing, among other things, our rights of first offer to acquire or a right to purchase from our Sponsor, as the case may be, Additional Fleet Interest, Four-Year Drillships and Optional Drillship Interests and the extent to which our Sponsor may compete with us; and

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• we will enter into certain management and administrative services agreements pursuant to which Ocean Rig and its affiliates will agree to provide us with management, administrative, financial and other support services and/or personnel;

For further details on our agreements with our Sponsor and its affiliates, please see “Certain Relationships and Related Party Transactions.”

Borrowing Activities

On February 28, 2013, DOV I, as borrower, entered into a facilities agreement with, inter alia, DNB Bank ASA, as facility agent and security trustee, for up to $1.35 billion to fund a portion of the purchase price of OPCO’s Initial Fleet, or the Existing Senior Secured Loan Facility.

Ocean Rig, DOV I, and a financing subsidiary of DOV I, or the “Borrowers,” expect to enter into the new senior secured term loan facility that will initially provide for a $1.3 billion senior secured term loan and optional revolving credit obligations not exceeding $50.0 million, or the “New Senior Secured Term Loan Facility.” The New Senior Secured Term Loan Facility also will provide that, subject to certain conditions and limitations, the Borrowers may add one or more incremental term loan facilities in an aggregate principal amount not to exceed $150.0 million.

The New Senior Secured Term Loan Facility will have a maturity date in the third quarter of 2021. Borrowings under the New Senior Secured Term Loan Facility will bear interest at the applicable margin to the either base rate or the Eurodollar rate, as applicable.

The New Senior Secured Term Loan Facility will be fully and unconditionally guaranteed by our Sponsor and certain issuer subsidiary guarantors. The guarantee by Parent will be automatically released upon the consummation of this offering. The New Senior Secured Term Loan Facility will be secured, on a first priority basis by a security interest in theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena and a pledge of certain other assets of DOV I and certain of its subsidiary guarantors, subject to certain exceptions.

The proceeds from the New Senior Secured Term Loan Facility, together with cash on hand, will be used to refinance the outstanding amounts under the Existing Senior Secured Loan Facility and to pay related fees and expenses. The entry into the New Senior Secured Term Loan Facility is subject, among other things, to the negotiation and execution of definitive documentation.

In connection with the closing of this offering, OPCO, through DOV II will assume the debt of DOV I under the New Senior Secured Term Loan Facility and our Sponsor will be unconditionally released as guarantor under the New Senior Secured Term Loan Facility. For a complete description of our credit facilities and the financial and restrictive covenants contained therein, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Borrowing Activities.”

Our Corporate Structure

Ocean Rig Partners LP was organized as a limited partnership in the Republic of the Marshall Islands on April 16, 2014, as a wholly-owned subsidiary of Ocean Rig, our Sponsor. Upon the closing of this offering and the completion of the transactions described in “—Formation Transactions”, our Sponsor will own     % of our outstanding common units and all of our outstanding subordinated units, assuming the underwriters do not exercise their option to purchase additional common units in this offering and our General Partner will own all of the incentive distribution rights. Following the completion of this offering, we will own a     % limited partner interest and a non-economic general partner interest in OPCO, which will indirectly own all of the outstanding capital stock of the entities that own theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena.

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Organizational Chart

The following diagram provides a summary of our corporate and ownership structure after giving effect to this offering, assuming no exercise of the underwriters’ option to purchase additional units.

Our Management

We are managed by the board of directors and executive officers of our General Partner. Our Sponsor is the sole member of our General Partner and has the right to appoint the entire board of directors of our General Partner, including the independent directors appointed in accordance with the listing standards of the Nasdaq

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Global Select Market (“Nasdaq”). Unlike shareholders in a publicly traded corporation, our common unitholders are not entitled to elect our General Partner or the board of directors of our General Partner. Some of the executive officers and directors of our General Partner also may serve as executive officers of our Sponsor. For more information about the directors and executive officers of our General Partner, please read “Management—Directors and Executive Officers of the our General Partner.”

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 Sponsor and its affiliates, including our General Partner, have 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 our Sponsor 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, but we sometimes refer to these individuals in this prospectus as our employees because they provide services directly to us.

Summary of Conflicts of Interest and Fiduciary Duties

Under our partnership agreement, or our Partnership Agreement, our General Partner will have a duty to manage us in a manner it believes is not adverse to our best interests. However, because our General Partner is a wholly owned subsidiary of our Sponsor, the officers and directors of our General Partner also have a duty to manage the business of our General Partner in a manner that is not adverse to the best interests of our Sponsor. As a result of this relationship, 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 our Sponsor, on the other hand. For example, our General Partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common units, which in turn has an effect on whether our General Partner receives incentive cash distributions. In addition, our General Partner may determine to manage our business in a way that directly benefits our Sponsor’s business. However, all of these actions will be permitted under our partnership agreement and will not be a breach of any duty of our General Partner. For a more detailed description of the conflicts of interest and duties of our General Partner, please read “Risk Factors—Risks Inherent in an Investment in Us” and “Conflicts of Interest and Duties.” In particular:

• certain of the executive officers and directors of our General Partner also may serve as executive officers or directors of our Sponsor or its affiliates;

• Our Sponsor, our General Partner and its other affiliates may compete with us, subject to the restrictions contained in the Omnibus Agreement; and

• we may enter into arrangements, with our Sponsor and certain of its subsidiaries, relating to the purchase of additional drillships, the provision of certain services to us by our General Partner or Ocean Rig Management and other matters. In the performance of their obligations under these agreements, our Sponsor and its subsidiaries are generally held to a standard of care to our members as specified in these agreements.

For a more detailed description of our management structure, please read “Management—Directors,” “Management—Executive Officers” and “Certain Relationships and Related Party Transactions.”

The common unitholders will not have the right to elect the board of directors of our General Partner. The board of directors of our General Partner will have a conflicts committee composed of independent directors. The board of directors of our General Partner may, but is not obligated to, seek approval of the conflicts committee for resolutions of conflicts of interest that may arise as a result between the relationships between our General Partner and its affiliates, on the one hand, and us and our unaffiliated members, on the other.

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For a more detailed description of the conflicts of interest and duties of our directors and officers, please read “Conflicts of Interest and Fiduciary Duties.” For a description of our other relationships with our affiliates, please read “Certain Relationships and Related Party Transactions.”

Recent Developments

Delivery of the Ocean Rig Athena

On March 24, 2014, our Sponsor took delivery of theOcean Rig Athenaand drew down $450.0 million of the remaining balance under the $1.35 billion secured term loan. We have entered into a three-year contract with ConocoPhillips for drilling operations offshore Angola which is scheduled to commence in the second quarter of 2014.

Contract with Total for the Ocean Rig Skyros

In connection with the previously announced Letter of Award, our Sponsor and Total signed a six year contract for drilling operations offshore Angola for the ultra deepwater drillshipOcean Rig Skyros. Under the new contract, our Sponsor is entitled to a maximum dayrate of approximately $555,723, which is the average maximum dayrate applicable during the initial six-year term of the contract, plus mobilization fees of $20 million. Under the contract, the initial maximum dayrate of $513,000 is subject to a fixed annual escalation of 2% during the contract period.

New Senior Secured Term Loan Facility

Ocean Rig, DOV I and a financing subsidiary of DOV I, expect to enter into the New Senior Secured Term Loan Facility and optional revolving credit obligations not exceeding $50 million. The New Senior Secured Term Loan Facility also will provide that, subject to certain conditions and limitations, the Borrowers may add one or more incremental term loan facilities in an aggregate principal amount not to exceed $150.0 million. The New Senior Secured Term Loan Facility will have a maturity date in the third quarter of 2021. The proceeds from the New Senior Secured Term Loan Facility, together with cash on hand, will be used to refinance the outstanding amounts under the Existing Senior Secured Loan Facility and to pay related fees and expenses. The entry into the New Senior Secured Term Loan Facility is subject, among other things, to the negotiation and execution of definitive documentation.

In connection with the closing of this offering, OPCO, through DOV II will assume the debt of DOV I under the New Senior Secured Term Loan Facility and our Sponsor will be unconditionally released as guarantor under the New Senior Secured Term Loan Facility. For a complete description of our credit facilities and the financial and restrictive covenants contained therein, please see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Borrowing Activities.”

Principal Executive Offices and Internet Address; SEC Filing Requirements

We maintain our principal executive offices at c/o Ocean Rig Management Inc., 109 Kifisias Ave., and Sina Str.GR-15124, Amroussion, Athens, Greece and our telephone number at that address is 011 30 210 81 28 600. We expect to make our periodic reports and other information filed with or furnished to the United States Securities and Exchange Commission, or the SEC available, free of charge, through our website at www.                    .com, which will be operational after this offering, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Please see “Where You Can Find More Information” for an explanation of our reporting requirements as a foreign private issuer. Information contained on our website does not constitute part of this prospectus.

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THE OFFERING

Common units offered to the public              common units.

             common units if the underwriters exercise their option to purchase additional common units in full.

Units outstanding after this offering              common units and              subordinated units, representing a     % and     % limited partner interest in us, respectively.

             common units if the underwriters exercise their option to purchase additional common units in full

Use of proceeds We expect to receive net proceeds of approximately $         million from the sale of common units in this offering, assuming an initial public offering price of $         per unit (which is the midpoint of the range set forth on the cover of this prospectus) and after deducting estimated underwriting discounts and commissions and paying estimated offering expenses. Of this amount, $         million will be paid to our Sponsor through DOV I as partial consideration for our interests in OPCO’s Initial Fleet.

The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be used for general corporate purposes. See “Use of Proceeds.”

Cash distributions We intend to make minimum quarterly distributions of $         per common unit ($         per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our General Partner and its affiliates. In general, we will pay any cash distributions we make each quarter in the following manner:

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

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

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

We must distribute all of our cash on hand at the end of each quarter, less reserves established by our General Partner to provide for the proper conduct of our business, to comply with any applicable debt instruments or to provide funds for future distributions. We refer to this cash as “available cash,” and we define its meaning in our partnership agreement. The amount of available cash may be greater than or less than the aggregate amount of the minimum quarterly distribution to be distributed on all units. Within 45 days after the end

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of each fiscal quarter (beginning with the quarter ending             ), we will 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 closing of the offering through              based on the actual length of the period. Our ability to pay our 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.”

If cash distributions to our unitholders exceed $         per unit in a quarter, holders of our incentive distribution rights (initially, our General Partner) will receive increasing percentages, up to 50.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.”

We believe, based on the estimates contained in and the assumptions listed under “Our Cash Distribution Policy and Restrictions on Distributions—Forecasted Cash Available for Distribution,” that we will have sufficient cash available for distribution to enable us to pay the minimum quarterly distribution of $         on all of our common and subordinated units through September 30, 2015. However, unanticipated events may occur which could adversely affect the actual results we achieve during the forecast period. Consequently, our actual results of operations, cash flows and financial condition during the forecast period may vary from the forecast, and such variations may be material. Prospective investors are cautioned to not place undue reliance on the forecast and should make their own independent assessment of our future results of operations, cash flows and financial condition. Please read “Our Cash Distribution Policy and Restrictions on Distributions—Forecasted Cash Available for Distribution.”

Subordinated units Our Sponsor will initially 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 the subordinated units are entitled to receive the minimum quarterly distribution of $         per unit only after the common units have received the minimum quarterly distribution and arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages. The subordination period generally will end if we have earned and paid at least $         on each outstanding common and subordinated unit for any three consecutive four-quarter periods ending on or after 2019.

Our General Partner’s right to reset the target distribution levels Our General Partner, as the initial holder of all of our incentive distribution rights, has the right, at a time when there are no subordinated units outstanding and our General Partner has received incentive distributions at the highest level to which it is entitled (50.0%) for each of the prior four consecutive fiscal quarters and the amount of such distribution did not exceed adjusted operating surplus,

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to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election, and to receive common units in connection with this reset.

For a more detailed description of our General Partner’s right to reset the target distribution levels upon which the incentive distribution payments are based and the concurrent right of our General Partner to receive common units in connection with this reset, please read “How We Make Cash Distributions—Our General Partner’s Right to Reset Incentive Distribution Levels.”

Issuance of additional units We can issue an unlimited number of additional units, including units that are senior to the common units in rights of distribution, liquidation and voting, on the terms and conditions determined by the board of directors of our General Partner, without the consent of our unitholders. Please read “Units Eligible for Future Sale” and “The Operating Agreement—Issuance of Additional Interests.”

Board of directors We will be managed by the board of directors and executive officers of our General Partner. Our General Partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Our Sponsor owns all of the membership interests in our General Partner. Our common unitholders will not be entitled to elect the directors of our General Partner or to participate directly or indirectly in our management or operations.

Following the closing of this offering, we expect that our General Partner will have at least five directors. Our Sponsor will appoint all members to the board of directors of our General Partner. In accordance with the Nasdaq’s rules, which defer to the laws of the home country, we will have at least one independent director on the date that our common units are first listed on the Nasdaq. The majority of our directors will be non-United States citizens or residents.

Voting rights Each outstanding common unit is entitled to one vote on matters subject to a vote of common unitholders

You will have no right to elect our General Partner on an annual or other continuing basis. Our General Partner may not be removed except by a vote of the holders of at least 80% of the outstanding units, including any units owned by our Sponsor and its affiliates, voting together as a single class. Upon consummation of this offering, Ocean Rig will own of our common units and all of our subordinated units, representing a     % limited partner interest in us (or a     % limited partner interest in us if the underwriters’ option to purchase additional common units is exercised in full). As a result, you will initially be unable to remove our General Partner without our Sponsor’s consent because Ocean Rig will own sufficient common units upon completion of this offering to be able to prevent our General Partner’s removal. Please read “The Partnership Agreement—Voting Rights.”

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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, but not less than all, of the remaining common units at a price equal to the greater of (x) the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before the notice of exercise of the call right is first mailed and (y) the highest 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. our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon the exercise of this limited call right.

U.S. federal income tax considerations We are organized as a limited partnership that will elect to be treated as a corporation for U.S. federal income tax purposes. Consequently, all or a portion of the distributions you receive from us will constitute dividends for such purposes. The remaining portion of such distributions will be treated first as a non-taxable return of capital to the extent of your tax basis in your common units and, thereafter, as capital gain. We estimate that if you hold the common units that you purchase in this offering through the period ending             , the distributions you receive, on a cumulative basis, that will constitute dividends for U.S. federal income tax purposes will be approximately     % of the total cash distributions received during that period. Please read “Material U.S. Federal Income Tax Considerations—U.S. Federal Income Taxation of U.S. Holders—Ratio of Dividend Income to Distributions” for the basis for this estimate. Please also read “Risk Factors—Tax Risks” for a discussion relating to the taxation of dividends. For a discussion of other material U.S. 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 Considerations,” and for a discussion of material income tax consequences that may be relevant to prospective unitholders under Marshall Islands law, please read “Non-United States Tax Considerations.”

Exchange listing We will apply to list the common units on the NASDAQ Global Select Market under the symbol “ORLP”.

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SUMMARY FINANCIAL AND OPERATING DATA

We were formed on April 16, 2014 by our Sponsor as a growth-oriented limited partnership to own, operate and acquire offshore drilling units, including through our ownership of OPCO. OPCO’s Initial Fleet consists of three ultra-deepwater drillships theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena, all of which are currently employed or will be employed on multi-year drilling contracts with affiliates of major oil companies. Upon the closing of this offering we will acquire from our Sponsor interests in OPCO’s Initial Fleet. In addition, prior to the completion of this offering, we will complete a series of other formation transactions that are described in the section of the prospectus entitled “Summary—Formation Transactions.” Our business will be a direct continuation of the Ocean Rig Partners LP Predecessor. We do not intend to engage in any business or other activities prior to the closing of the offering, except in connection with our formation. The Ocean Rig Partners LP Predecessor includes subsidiaries of our Sponsor that had interests in the entities that own and operate the drillships in OPCO’s initial fleet prior to the completion of this offering.

The summary historical financial data of Ocean Rig Partners LP Predecessor as of and for the years ended December 31, 2012 and 2013 have been derived from the audited Combined Carve-out Financial Statements of Ocean Rig Partners LP Predecessor, prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP), which are included elsewhere in this prospectus. Our independent registered accounting firm’s report included in this prospectus relate to the historical Combined Carve-out Financial Statements of Ocean Rig Partners LP Predecessor. That report does not extend to the tables and the related forecasted financial information contained in this prospectus and should not be read to do so.

The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical Combined Carve-out Financial Statements of Ocean Rig Partners LP Predecessor and the notes thereto, and our forecasted results of operations, in each case included elsewhere in this prospectus.

Our financial position, results of operations and cash flows could differ from those that would have resulted if we operated autonomously or as an entity independent of Ocean Rig in the periods for which historical financial data are presented below, and such data may not be indicative of our future operating results or financial performance.

(U.S. Dollars in thousands)	For the year ended December 31,
	2012			2013
Income statement data:
Total revenues	$	—		$	37,325
Expenses:
Drillships operating expenses		—			13,576
Depreciation		—			11,740
General and administrative expenses		6,720			25,827
Operating loss		(6,720	)		(13,818	)
Other Income/(Expenses)
Interest and finance costs		(3	)		(21,022	)
Interest income		—			90
Gain/(loss) on interest rate swaps, net		(3,674	)		8,510
Other, net		(219	)		613
Total other expenses, net		(3,896	)		(11,809	)
Loss before income taxes		(10,616	)		(25,627	)
Income taxes		—			—
Net loss	$	(10,616	)	$	(25,627	)

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(U.S. Dollars in thousands)	As of December 31,
	2012		2013
Balance sheet data:
Cash and cash equivalents	$	1,452	$	6,083
Other current assets		14,000		119,156
Total current assets		15,452		125,239
Drillships, machinery and equipment, net				1,412,164
Other non current assets		935		104,839
Advances for drillships under construction and related costs		770,858		292,692
Total assets		787,245		1,934,934
Current liabilities, including current portion of long term debt, net of deferred financing costs		5,961		221,514
Long term debt, net of current portion and deferred financing costs				797,114
Other non current liabilities		3,106		101,129
Total liabilities		9,067		1,119,757
Total stockholders’ equity		778,178		815,177
Common Stock		184		184
Total liabilities and stockholders’ equity	$	787,245	$	1,934,934

(U.S. Dollars in thousands, except for operating data)	Year Ended December 31,
	2012			2013
Cash flow data:
Net cash provided by / (used in):
Operating activities	$	(3,779	)	$	83,375
Investing activities		(45,284	)		(989,738	)
Financing activities		50,515			910,994
Other financial data
EBITDA(1)		(10,613	)		7,045
Cash paid for interest		—			(4,282	)
Capital expenditures		—			(58,267	)
Payments for drillships under construction		(39,284	)		(887,471	)
Operating data, when on hire
Operating units		0			2

(1) EBITDA represents net income before interest, taxes, depreciation and amortization. EBITDA is a non-U.S. GAAP measure and does not represent and should not be considered as an alternative to net income or cash flow from operations, as determined by GAAP or other GAAP measures, and our calculation of EBITDA may not be comparable to that reported by other companies. EBITDA is included herein because it is a basis upon which we measure our operations.

(U.S. Dollars in thousands)	Year Ended December 31,
	2012			2013
EBITDA reconciliation
Net loss	$	(10,616	)		(25,627	)
Add: Depreciation		—			11,740
Add: Net interest expense		3			20,932
Add: Income taxes		—
EBITDA	$	(10,613	)		7,045

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FORWARD-LOOKING STATEMENTS

Some of the information included in this prospectus (including our financial forecast and any other statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto, including statements and assumptions concerning OPCO or DOV II) contains forward-looking statements. In addition, we and our representatives may from time to time make other oral or written statements which are also forward-looking statements. Such statements include, in particular, statements about our plans, strategies, business prospects, changes and trends in our business, and the markets in which we operate as described in this prospectus. In some cases, you can identify the forward-looking statements by the use of words such as “may,” “could,” “should,” “would,” “expect,” “plan,” “anticipate,” “intend,” “forecast,” “believe,” “estimate,” “predict,” “propose,” “potential,” “continue” or the negative of these terms or other comparable terminology.

All statements in this prospectus that are not statements of either historical or current facts are forward-looking statements. Forward-looking statements appear in a number of places and include statements with respect to, among other things:

• forecasts of our ability to make cash distributions on our units and the amount of any borrowings that may be necessary to make such distributions;

• future financial conditions or results of operations and future revenues and expenses;

• the repayment of debt;

• expected compliance with financing agreements and the expected effect of restrictive covenants in such agreements;

• the failure of the drillships in OPCO’s Initial Fleet to perform satisfactorily or to our expectations;

• fluctuations in the international price of oil;

• discoveries of new sources of oil that do not require deepwater drillships;

• the development of alternative sources of fuel and energy;

• technological advances, including in production, refining and energy efficiency;

• severe weather events and natural disasters;

• our ability to meet any future capital expenditure requirements;

• our ability to maintain operating expenses at adequate and profitable levels;

• incurrence of cost overruns in the maintenance or other work performed on OPCO’s Initial Fleet;

• our ability to conduct and obtain investment for business activities involving U.S. sanctioned countries, entities and individuals;

• our ability to leverage our Sponsor’s relationship and reputation in the offshore drilling industry;

• increasing our ownership interest in OPCO and acquiring additional drillship interests;

• delay in payments by or disputes with our customers under our drilling contracts;

• our ability to comply with, maintain, renew or extend our existing drilling contracts;

• our ability to re-deploy our drillships upon termination of our existing drilling contracts at profitable dayrates;

• our ability to respond to new technological requirements in the areas in which we operate;

• the occurrence of any accident involving OPCO’s Initial Fleet or other drillships in the industry;

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• changes in governmental regulations that affect us and the interpretations of those regulations, particularly those that relate to environmental matters, export or import and economic sanctions or trade embargo matters, regulations applicable to the oil industry and tax and royalty legislation;

• increased competition in the offshore drilling industry and other actions of competitors, including decisions to deploy drillships in the areas in which OPCO’s Initial Fleet currently operates;

• the increased availability on a timely basis of drillships, supplies, personnel and oil field services in the areas in which OPCO’s Initial Fleet operates;

• general economic, political and business conditions globally;

• military operations, terrorist acts, wars or embargoes;

• potential disruption of operations due to accidents, political events, piracy or acts by terrorists;

• our or OPCO’s ability to obtain financing in sufficient amounts and on adequate terms;

• workplace safety regulation and employee claims;

• the cost and availability of adequate insurance coverage;

• our anticipated incremental general and administrative expenses as a publicly traded limited partnership and our fees and expenses payable under the advisory, technical and administrative services agreements and the management and administrative services agreements;

• the anticipated taxation of our company and distributions to our unitholders;

• future sales of our common units in the public market; and

• our business strategy and other plans and objectives for future operations.

These and other forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties, including those risks discussed in “Risk Factors.” The risks, uncertainties and assumptions involve known and unknown risks and are inherently subject to significant uncertainties and contingencies, many of which are beyond our control. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of these factors. Further, we cannot assess the impact of each such factor on our business or the extent to which any factor, or combination of factors, may cause actual results to be materially different from those contained in any forward-looking statement.

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RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should consider carefully the following risk factors, as well as the other information contained in this prospectus, before making an investment in our common units. Any of the risk factors described below could significantly and negatively affect our business, financial condition or operating results, which may reduce our ability to pay distributions and lower the trading price of our common units. You may lose part or all of your investment.

Risks Related to Our Partnership

OPCO’s Initial Fleet consist of interests in only three drillships. Any limitation in the availability or operation of these vessels could have a material adverse effect on our business, results of operations and financial condition and could significantly reduce or eliminate our ability to pay the minimum quarterly distribution on our common units and subordinated units.

OPCO’s Initial Fleet consist of interests in only three drillships. If any of OPCO’s vessels are unable to generate revenues as a result of off-hire time, early termination of the applicable time charter or otherwise, our business, results of operations financial condition and ability to make minimum quarterly distributions to unitholders could be materially adversely affected.

Because our ownership interest in OPCO represents our only cash-generating asset, our cash flow initially will depend completely on OPCO’s ability to make distributions to us as one of its owners.

Our cash flow initially will depend completely on OPCO’s distributions to us as one of its owners. The amount of cash OPCO can distribute to its owners will principally depend upon the amount of cash it generates from its operations, which may fluctuate from quarter to quarter based on, among other things:

• the dayrates it obtains under its drilling contracts;

• the level of its drillship operating costs, such as the cost of crews, repair, maintenance and insurance;

• the levels of reimbursable revenues and expenses;

• its ability to re-contract its drillships upon expiration or termination of an existing drilling contract and the dayrates it can obtain under such contracts;

• delays in the delivery of any new drillships and the beginning of payments under drilling contracts relating to those drillships;

• the timeliness of payments from customers under drilling contracts;

• prevailing global and regional economic and political conditions;

• time spent mobilizing drillships to the customer location;

• changes in local income tax rates;

• currency exchange rate fluctuations and currency controls; and

• the effect of governmental regulations and maritime self-regulatory organization standards on the conduct of its business.

The actual amount of cash OPCO will have available for distribution also will depend on other factors such as:

• the level of capital and operating expenditures it makes, including for maintaining and replacing drillships or modifying existing drillships to meet customer requirements and complying with regulations or to upgrade technology on OPCO’s drillships;

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• its debt service requirements, including fluctuations in interest rates, and restrictions on distributions contained in its debt instruments;

• fluctuations in its working capital needs;

• number of days of drillship downtime or less than full utilization, which would result in a reduction of revenues under a drilling contract;

• the amount of any cash reserves, including reserves for future maintenance and replacement capital expenditures, working capital and other matters, established by the board of directors of our General Partner.

OPCO’s partnership agreement will provide that it will distribute its available cash to its owners on a quarterly basis. OPCO’s available cash includes cash on hand less any reserves that may be appropriate for operating its business. The amount of OPCO’s quarterly distributions, including the amount of cash reserves not distributed, will be determined by the board of directors of our General Partner.

The amount of cash OPCO generates from operations may differ materially from its profit or loss for the period, which will be affected by non-cash items. As a result of this and the other factors mentioned above, OPCO may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records net income.

Further, the amount of distributions OPCO can make to us depends on its financing arrangements.

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay the minimum quarterly distribution on our common units and subordinated units.

The source of our earnings and cash flow initially will consist exclusively of cash distributions from OPCO. Therefore, the amount of cash distributions we are able to make to our unitholders will fluctuate, initially, based on the level of distributions made by OPCO to its owners, including us, and, in the future, based on the level of cash distributions made by OPCO and any other subsidiaries through which we later conduct operations. OPCO or any such operating subsidiaries may make quarterly distributions at levels that will not permit us to make distributions to our common unitholders at the minimum quarterly distribution level or to increase our quarterly distributions in the future. In addition, while we would expect to increase or decrease distributions to our unitholders if OPCO increases or decreases distributions to us, the timing and amount of any such increased or decreased distributions will not necessarily be comparable to the timing and amount of the increase or decrease in distributions made by OPCO to us.

Our ability to distribute to our unitholders any cash we may receive from OPCO or any future operating subsidiaries is or may be limited by a number of factors, including, among others:

• interest expense and principal payments on any indebtedness we incur;

• restrictions on distributions contained in any of our current or future debt agreements;

• fees and expenses, including fees and expenses of our General Partner, its affiliates or third parties we are required to reimburse or pay, including expenses we will incur as a result of being a public company; and

• reserves the board of directors of our General Partner believes are prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

Many of these factors will reduce the amount of cash we may otherwise have available for distribution. We may not be able to pay distributions, and any distributions we make may not be at or above our minimum quarterly distribution. The actual amount of cash that is available for distribution to our unitholders will depend on several factors, many of which are beyond our control.

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We will depend on certain affiliates of our Sponsor and its subsidiaries to assist us and OPCO in operating, managing, and expanding our business.

Our ability and that of OPCO to enter into new drilling contracts and expand our customer and supplier relationships will depend largely on our ability to leverage our relationship with our Sponsor and its reputation and relationships in the offshore drilling industry. If our Sponsor suffers material damage to its reputation or relationships, it may harm our ability to:

• renew existing drilling contracts upon their expiration;

• obtain new drilling contracts;

• efficiently and productively carry out our drilling activities;

• successfully interact with shipyards;

• obtain financing and maintain insurance on commercially acceptable terms;

• maintain access to capital under the Sponsor Credit Facility we expect to enter into prior to the closing of this offering; or

• maintain satisfactory relationships with suppliers and other third parties.

In addition, pursuant to the management and administrative services agreements, our Sponsor and its affiliates will provide us with significant management, administrative, financial and other support services and/or personnel. In addition, affiliates of our Sponsor will provide advisory, technical and administrative services to OPCO’s Initial Fleet pursuant to vessel management agreements. Our and OPCO’s operational success and ability to execute our growth strategy will depend significantly upon the satisfactory performance of these services. Our business will be harmed if our Sponsor and its affiliates fail to perform these services satisfactorily, if they cancel their agreements with us or if they stop providing these services to us. Please read “Certain Relationships and Related Party Transactions.”

OPCO’s drilling contracts may not permit OPCO to fully recoup its costs in the event of a rise in expenses.

OPCO’s drilling contracts have dayrates that are fixed over the term of the contract year. In order to mitigate the effects of inflation on revenues from these term contracts, all of OPCO’s drilling contracts include escalation provisions. These provisions allow OPCO to adjust the dayrates based on certain published indices or certain fixed percentages. These indices are designed to recompense OPCO for certain cost increases, including wages, insurance and maintenance costs. However, actual cost increases may result from events or conditions that do not cause correlative changes to the applicable indices. Furthermore, certain indices are updated semi-annually, and therefore may be outdated at the time of adjustment. In addition, the adjustments are normally performed on a semi-annual or annual basis. For these reasons, the timing and amount received as a result of the adjustments may differ from the timing and amount of expenditures associated with actual cost increases, which could adversely affect OPCO’s and our cash flow and ability to make cash distributions.

The assumptions underlying our forecast of cash available for distribution are inherently uncertain and are subject to 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 forecast of operating results and cash flows for the twelve months ending June 30, 2015. The financial forecast has been prepared by management and we have not received an opinion or report on it from our or any independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, 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.

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The amount of available cash we need to pay the minimum quarterly distribution for four quarters on the common units and the subordinated units to be outstanding immediately after this offering is $         million. During the years ended December 31, 2013 and December 31, 2012, we would have had cash available for distribution of $         million, and $         million, respectively, which would not have been sufficient to pay the minimum quarterly distribution on all of our common units and subordinated units, as the historical periods did not include results, for theOcean Rig Athena, commenced operations in the second quarter of 2014, and theOcean Rig Skyros which was delivered in December 2013, and include, partial results for theOcean Rig Mylos, which commenced operations in November 2013. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Items You Should Consider When Evaluating Our Historical Financial Performance and Assessing Our Future Prospects.” For a forecast of our ability to pay the full minimum quarterly distribution on our common units and subordinated units for the twelve months ending June 30, 2015, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Our ability to grow may be adversely affected by our cash distribution policy. OPCO’s ability to meet its financial needs and grow may be adversely affected by its cash distribution policy.

Our cash distribution policy, which is consistent with our Partnership Agreement, requires us to distribute all of our available cash each quarter. Accordingly, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations.

In addition, OPCO’s cash distribution policy will require it to distribute all of its available cash each quarter. In determining the amount of cash available for distribution by OPCO, the board of directors of our General Partner will approve the amount of cash reserves to set aside for us and OPCO, including reserves for anticipated maintenance and replacement capital expenditures, working capital and other matters. OPCO will also rely upon external financing sources, including commercial borrowings, to fund its capital expenditures. Accordingly, to the extent OPCO does not have sufficient cash reserves or is unable to obtain financing, its cash distribution policy may significantly impair its ability to meet its financial needs or to grow.

If capital expenditures are financed through cash from operations or by issuing debt or equity securities, our ability to make cash distributions may be diminished, our financial leverage could increase or our unitholders could be diluted.

Use of cash from operations to expand or maintain OPCO’s fleet will reduce cash available for OPCO to distribute to us and us to distribute to our unitholders. Our ability and that of OPCO to obtain bank financing or our ability to access debt and equity capital markets may be limited by our financial condition or that of OPCO, respectively, at the time of any such financing or offering as well as by adverse market conditions resulting from, among other things, general economic conditions, changes in the offshore drilling industry and contingencies and uncertainties that are beyond our control. Failure to obtain the funds for future capital expenditures could have a material adverse effect on our business, results of operations and financial condition and on our ability to make cash distributions. Even if we are successful in obtaining necessary funds, the terms of any debt financings could limit OPCO’s ability to pay distributions to us and our ability to pay cash distributions to unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional equity securities may result in significant unitholder dilution and would increase the aggregate amount of cash required to pay the minimum quarterly distribution to unitholders, both of which could have a material adverse effect on our ability to make cash distributions.

OPCO’s debt levels may limit its or our flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions to unitholders.

Upon completion of this offering and the related transactions, we estimate that our combined debt (including indebtedness outstanding under OPCO’s financing agreements, including the New Senior Secured Term Loan Facility) will be approximately $ billion. Following this offering, we will continue to have the ability to incur

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additional debt. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

OPCO’s level of debt could have important consequences to it and us, including the following:

• the ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be limited or such financing may not be available on favorable terms;

• OPCO will need a substantial portion of its cash flow to make principal (including amortization payments as required by OPCO’s financing agreements, including the New Senior Secured Term Loan Facility) and interest payments on its debt, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to us and ultimately our unitholders;

• such debt may make us each more vulnerable to competitive pressures or a downturn in our business or the economy generally than our competitors with less debt; and

• such debt may limit our and OPCO’s flexibility in responding to changing business and economic conditions.

Our ability to service our combined 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 our combined current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our combined debt, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms, or at all.

Furthermore, the New Senior Secured Term Loan Facility contains cross-default clauses which are linked to other indebtedness of our Sponsor. In the event of a default by our Sponsor under one of its other credit facilities, we could be adversely affected by the cross-default clauses, even if our Sponsor cures any such default.

Restrictions in OPCO’s financing agreements, including the New Senior Secured Term Loan Facility, may prevent it or us from paying distributions.

The payment of principal and interest on OPCO’s debt will reduce cash available for distribution to us and to our unitholders. In addition, OPCO’s financing agreements, including the New Senior Secured Term Loan Facility, contain provisions that, upon the occurrence of certain events, permit lenders to accelerate the outstanding debt and declare all amounts due and payable, which may prevent us from paying distributions to our unitholders.

The New Senior Secured Term Loan Facility will contain customary covenants, including restrictive covenants, which include restrictions on, among other things, (i) OPCO’s ability to enter into affiliate transactions, (ii) the creation of liens on our assets, (iii) mergers or consolidations without the prior consent of the lenders, (iv) the sale, lease, transfer or other disposition of the collateral securing the facility other than for market value on an arm’s length basis and in compliance with the terms of the facility, (v) the incurrence of additional indebtedness and (vi) the making of additional investments.

In addition, the New Senior Secured Term Loan Facility will restrict OPCO’s ability to pay dividends or make other distributions or distributions in respect of our capital stock. Such restrictions will change depending on, among other things, whether this offering has been consummated, certain financial tests, and the cash available (as calculated in accordance with the New Senior Secured Term Loan Facility).

The New Senior Secured Term Loan Facility will contain customary events of default, including non-payment of principal or interest, breach of covenants or material representations and the declaration of bankruptcy and imposes insurance requirements and restrictions on the employment of the drillships in OPCO’s

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Initial Fleet. In addition, the New Senior Secured Term Loan Facility will contain a cross-default provision that is triggered when any of DOV II’s other financial indebtedness is not paid when due or is declared to be, or otherwise becomes, due and payable prior to its specified maturity as a result of an event of default and in each case such amount equals or exceeds $25.0 million. In these situations the lenders may accelerate the indebtedness under the New Senior Secured Term Loan Facility.

For more information regarding these financing agreements, please read “Management’s Discussion and Analysis of Financial Conditions and Results of Operations—Liquidity and Capital Resources—Borrowing Activities.”

Our Sponsor may be unable to service its debt requirements and comply with the provisions contained in the debt agreements secured by the Optional Drillships. If our Sponsor fails to perform its obligations under its debt agreements, our business and expected plans for growth may be materially affected.

Our Sponsor may be unable to service its debt requirements and comply with the provisions contained in the debt agreements secured by the Optional Drillships. Failure on behalf of our Sponsor to perform its obligations under its debt agreements, including paying scheduled installments and complying with certain covenants, may constitute an event of default under these secured debt agreements. If an event of default occurs under these debt agreements, our Sponsor’s lenders could accelerate the outstanding loans and declare all amounts borrowed due and payable. In this case, if our Sponsor is unable to obtain a waiver or amendment or does not otherwise have enough cash on hand to repay the outstanding borrowings, its lenders may, among other things, foreclose their liens on the Optional Drillships. In this case, we may not be able to exercise our rights under the Omnibus Agreement to acquire the Optional Drillships, which would likely have a material adverse effect on our business and our expected plans for growth.

Our Sponsor’s debt agreements, including its aggregate principal amount $800 million 6.5% senior secured notes due 2017, or the Senior Secured Notes due 2017, contain restrictions that may limit our growth plans.

Our Sponsor’s debt agreements contain restrictions that may limit our growth plans. Under the indenture relating to the Senior Secured Notes due 2017, certain subsidiaries of our Sponsor, including us and our subsidiaries, may not hold interests in subsidiaries of our Sponsor that are classified as “Restricted Subsidiaries” as such term is defined therein. This means that we are unable to acquire Optional Drillship Interests until the Senior Secured Notes Due 2017 are repaid, refinanced or amended to remove this restrictive provision.

The failure to consummate or integrate acquisitions in a timely and cost-effective manner could have an adverse effect on our financial condition and results of operations.

Acquisitions that expand our drilling operations are an important component of our business strategy. We believe that acquisition opportunities may arise from time to time, and any such acquisition could be significant. Any acquisition could involve the payment by us of a substantial amount of cash, the incurrence of a substantial amount of debt or the issuance of a substantial amount of equity. Certain acquisition and investment opportunities may not result in the consummation of a transaction. In addition, we may not be able to obtain acceptable terms for the required financing for any such acquisition or investment that arises. We cannot predict the effect, if any, that any announcement or consummation of an acquisition would have on the trading price of our common units. Our future acquisitions could present a number of risks, including the risk of incorrect assumptions regarding the future results of acquired operations or assets or expected cost reductions or other synergies expected to be realized as a result of acquiring operations or assets, the risk of failing to successfully and timely integrate the operations or management of any acquired businesses or assets and the risk of diverting management’s attention from existing operations or other priorities. We may also be subject to additional costs related to compliance with various international laws in connection with such acquisition. If we fail to consummate and integrate our acquisitions in a timely and cost-effective manner, our financial condition, results of operations and cash available for distribution could be adversely affected.

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We and our Sponsor may incur additional debt, which could exacerbate the risks associated with our substantial leverage.

Even with the existing level of debt, we and our Sponsor may incur additional indebtedness in the future. Our Sponsor expects to enter into the New Senior Secured Term Loan Facility to refinance outstanding indebtedness used to fund a portion of the construction costs of OPCO’s’s Initial Fleet. Although the terms of our existing debt agreements, and any future debt agreements we enter into, will limit our ability to incur additional debt, these terms may not prohibit us from incurring substantial amounts of additional debt for specific purposes or under certain circumstances.

The agreements and instruments governing OPCO’s indebtedness contain restrictions and limitations that could significantly impact our ability to operate our business.

OPCO’s credit facility imposes, and future financial obligations may impose, certain operating and financial restrictions on us. These restrictions prohibit or otherwise may limit our ability to, among other things:

• enter into other financing arrangements;

• incur or guarantee additional indebtedness;

• create or permit liens on our assets;

• consummate a merger, consolidation or sale of our drillships or the shares of our subsidiaries;

• make investments;

• change the general nature of our business;

• pay dividends, redeem capital stock or subordinated indebtedness or make other restricted payments;

• incur dividend or other payment restrictions affecting restricted subsidiaries;

• change the management and/or ownership of our drillships;

• enter into transactions with affiliates;

• transfer or sell assets;

• amend, modify or change our organizational documents;

• make capital expenditures; and

• compete effectively to the extent our competitors are subject to less onerous restrictions.

In addition, OPCO’s existing credit facility requires us to maintain specified financial ratios and satisfy various financial covenants, including covenants related to the market value of our drillships, capital expenditures and maintenance of a minimum amount of total available cash. Any future credit agreement or amendment or debt instrument we enter into may contain similar or more restrictive covenants. Events beyond our control, including changes in the economic and business conditions in the deepwater offshore drilling market in which we operate, may affect our ability to comply with these ratios and covenants. Our ability to maintain compliance will also depend substantially on the value of our assets, our dayrates, our ability to obtain drilling contracts, our success at keeping our costs low and our ability to successfully implement our overall business strategy. We cannot guarantee that OPCO would be able to obtain its lenders’ waiver or consent with respect to any noncompliance with the specified financial ratios and financial covenants under its credit facility or future financial obligations or that we or OPCO would be able to refinance any such indebtedness in the event of default.

These restrictions, ratios and financial covenants in our debt agreements could limit our ability to fund our operations or capital needs, make acquisitions or pursue available business opportunities, which in turn may adversely affect our financial condition. A violation of any of these provisions could result in a default under our

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existing and future debt agreements which could allow all amounts outstanding thereunder to be declared immediately due and payable. This would likely in turn trigger cross-acceleration and cross-default rights under the terms of our indebtedness outstanding at such time. If the amounts outstanding under our indebtedness were to be accelerated or were the subject of foreclosure actions, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

OPCO may not be able to generate sufficient cash flow and distribute enough funds to us to meet our debt service and other obligations due to events beyond our control.

OPCO’s financial and operating performance, and its ability to service its indebtedness, is dependent on its subsidiaries’ ability to make distributions to it, whether in the form of dividends, loans or otherwise. The timing and amount of such distributions will depend on our earnings, financial condition, cash requirements and availability, fleet renewal and expansion, restrictions in our various debt agreements, the provisions of Marshall Islands law affecting the payment of dividends and other factors. Further, Marshall Islands law generally prohibits the payment of dividends other than from surplus or while a company is insolvent or would be rendered insolvent upon the payment of such dividends, or if there is no surplus, dividends may be declared or paid out of net profits for the fiscal year.

If OPCO’s operating cash flows are insufficient to service its debt including the debt of its subsidiaries and to fund its other liquidity needs, OPCO may be forced to take actions such as reducing or delaying capital expenditures, selling assets, restructuring or refinancing its indebtedness, seeking additional capital, or any combination of the foregoing. We cannot assure you that any of these actions could be effected on satisfactory terms, if at all, or that they would yield sufficient funds to make required payments on OPCO’s, including its subsidiaries’, outstanding indebtedness and to fund its other liquidity needs. Also, the terms of existing or future debt agreements may restrict OPCO from pursuing any of these actions. Furthermore, reducing or delaying capital expenditures or selling assets could impair future cash flows and our ability to service its debt in the future.

If for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing such indebtedness, which would allow creditors at that time to declare all such indebtedness then outstanding to be due and payable. This would likely in turn trigger cross-acceleration or cross-default rights among our other debt agreements. Under these circumstances, lenders could compel us to apply all of our available cash to repay borrowings or they could prevent us from making payments on the notes. If the amounts outstanding under our existing and future debt agreements were to be accelerated, or were the subject of foreclosure actions, we cannot assure you that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.

We or OPCO may be unable to secure ongoing drilling contracts for drillships which we may acquire in the future, due to strong competition, and the contracts that we enter into may not provide sufficient cash flow to meet our or OPCO’s debt service obligations with respect to our or OPCO’s indebtedness.

We cannot guarantee that we or OPCO will enter into drilling contracts for drillships which we may acquire in the future. Our ability to obtain drilling contracts will depend on prevailing market conditions at the time. In particular, if the price of crude oil is low, or it is expected that the price of crude oil will decrease in the future, at a time when we are seeking to arrange drilling contracts for our drillships, we may not be able to obtain drilling contracts at attractive rates or at all.

If the rates we receive for the reemployment of our drillships upon the expiration or termination of our existing drilling contracts are lower than the rates under our existing contracts, we will recognize less revenue from the operations of our drillships. In addition, delays under existing drilling contracts could cause us to lose future contracts if a drilling unit is not available to start work at the agreed date. Our ability to meet our cash flow obligations will depend on our ability to consistently secure drilling contracts for our drillships at sufficiently high dayrates. We cannot predict the future level of demand for our services or future conditions in the oil and

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gas industry. If oil and gas companies do not continue to increase exploration, development and production expenditures, we may have difficulty securing drilling contracts or we may be forced to enter into drilling contracts at unattractive dayrates. Either of these events could impair our ability to generate sufficient cash flow to make principal and interest payments under our indebtedness and meet our capital expenditure and other obligations.

Our Sponsor and its affiliates may compete with us.

Pursuant to the Omnibus Agreement that we will enter into with our Sponsor and General Partner in connection with the closing of this offering, our Sponsor and its controlled affiliates (other than us, our General Partner and our subsidiaries) generally will agree not to acquire, own, operate or contract for Four Year Drillships. The Omnibus Agreement, however, contains significant exceptions that may allow our Sponsor or any of its controlled affiliates to compete with us, which could harm our business. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Noncompetition.”

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

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our General Partner or the 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 board of directors of our General Partner is chosen by the member of our general partner, which is a wholly owned subsidiary of our Sponsor. 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 our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Our general partner and its affiliates, including our Sponsor, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of our Sponsor, and our Sponsor is under no obligation to adopt a business strategy that favors us.

Following the offering, our Sponsor will own a     % limited partner interest in us (or     % if the underwriters’ option to purchase additional common units is exercised in full) and will own and control our General Partner. Although our General Partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is not adverse to the best interests of its owner, our Sponsor. Conflicts of interest may arise between our Sponsor and its affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates, including our Sponsor, over the interests of our common unitholders. These conflicts include, among others, the following situations:

• neither our partnership agreement nor any other agreement requires our Sponsor to pursue a business strategy that favors us or utilizes our assets;

• Our Sponsor’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of our Sponsor, which may be contrary to our interests; in addition, many of the officers and directors of our General Partner are also officers and/or directors of our Sponsor and will owe fiduciary duties to our Sponsor and its stockholders;

• Our Sponsor may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

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• our partnership agreement replaces the fiduciary duties that would otherwise be owed by our General Partner with contractual standards governing its duties, limiting our General Partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

• except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;

• disputes may arise under our commercial agreements with our Sponsor;

• our General Partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

• our General Partner will determine the amount and timing of many of our capital expenditures and whether a capital expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our 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 into common units;

• our General Partner will determine which costs incurred by it are reimbursable by us;

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

• our Partnership Agreement permits us to classify 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 to our General Partner in respect of the incentive distribution rights;

• our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

• our General Partner intends to limit its liability regarding our contractual and other obligations;

• our General Partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 80% of the common units (at the closing of this offering, our Sponsor will own     % of our common units, and as a result, our Sponsor will not have the ability to exercise the limited call right);

• our General Partner controls the enforcement of obligations owed to us by our General Partner and its affiliates, including under the omnibus agreement and our commercial agreements with our Sponsor;

• our General Partner decides whether to retain separate counsel, accountants or others to perform services for us; and

• our General Partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our General Partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our General Partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Under the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself,

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directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement” and “Conflicts of Interest and Duties.”

Certain of our officers face conflicts in the allocation of their time to our business.

Certain of the officers of our General Partner will not be required to work full-time on our affairs and also perform services for other companies, including our Sponsor. These other companies conduct substantial businesses and activities of their own in which we have no economic interest. As a result, there could be material competition for the time and effort of our officers who also provide services to other companies, which could have a material adverse effect on our business, results of operations and financial condition. Please read “Management.”

Our Partnership Agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our Partnership Agreement contains provisions that eliminate the fiduciary standards to which our General Partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. 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, free of any 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 partners where the language in the Partnership Agreement does not provide for a clear course of action. This provision entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

• how to allocate corporate opportunities among us and its other affiliates;

• whether to exercise its limited call right;

• whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;

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

• whether to exercise its registration rights;

• whether to elect to reset target distribution levels;

• whether to transfer the incentive distribution rights to a third party; and

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

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Duties—Duties of Our General Partner.”

Fees and cost reimbursements, which our Sponsor and its other affiliates will receive for services provided to us, OPCO and its subsidiaries, will be substantial, will be payable regardless of our profitability and will reduce our cash available for distribution to you.

Pursuant to the vessel management agreements, OPCO will pay fees for services provided to OPCO and its subsidiaries by certain affiliates of our Sponsor, and OPCO and its subsidiaries will reimburse these entities for

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all expenses they incur on their behalf. These fees and expenses will include all costs and expenses incurred in providing certain advisory, technical and administrative services to OPCO’s subsidiaries. We expect the amount of these fees and expenses to be approximately $         million for the twelve months ending June 30, 2015.

In addition, pursuant to the management and administrative services agreements, our Sponsor and its affiliates will provide us with significant management, administrative, financial and other support services and/or personnel. We will reimburse our Sponsor and its affiliates for the reasonable costs and expenses incurred in connection with the provision of these services. In addition, we will pay our Sponsor and its affiliates a management fee equal to     % of the costs and expenses incurred in connection with providing services to us. We expect that we will pay approximately $         million in total under the management and administrative services agreements for the twelve months ending June 30, 2015.

There is no cap on the amount of fees and cost reimbursements that OPCO and its subsidiaries may be required to pay such affiliates of our Sponsor pursuant to the advisory, technical and administrative service agreements, or that we may be required to pay under the management and administrative services agreements. For a description of the advisory, technical and administrative service agreements and the management and administrative services agreements, please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions.” The fees and expenses payable pursuant to the advisory, technical and administrative service agreements and the management and administrative services agreements will be payable without regard to our financial condition or results of operations. The payment of fees to and the reimbursement of expenses of our Sponsor and its affiliates could adversely affect our ability to pay cash distributions to you.

Our Partnership Agreement will contain provisions that may have the effect of discouraging a person or group from attempting to remove our General Partner, and even if public unitholders are dissatisfied, they will be unable to remove our General Partner without our Sponsor’s consent, unless our Sponsor’s ownership interest in us is decreased; all of which could diminish the trading price of our common units.

Our Partnership Agreement will contain provisions that may have the effect of discouraging a person or group from attempting to remove our current management or our General Partner.

• 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 completion of this offering to be able to prevent its removal. The vote of the holders of at least 80% of all outstanding common and subordinated units voting together as a single class is required to remove our General Partner. Following the closing of this offering, our Sponsor will own     % of the outstanding common and subordinated units, assuming no exercise of the underwriters’ option to purchase additional common units.

• If our General Partner is removed without “cause” during the subordination period and units held by our General Partner and our Sponsor are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units, any existing arrearages on the common units will be extinguished, and our General Partner will have the right to convert its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at the time. 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. Any conversion of our General Partner’s incentive distribution rights would be dilutive to existing unitholders. Furthermore, any cash payment in lieu of such conversion could be prohibitively expensive. “Cause” is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our General Partner liable for actual fraud or willful or wanton misconduct. Cause does not include most cases of charges of poor business decisions, such as charges of poor management of our business by the directors appointed by our General Partner, so the removal of our General Partner because of the unitholders’ dissatisfaction with our General Partner’s decisions in this regard would most likely result in the termination of the subordination period.

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• Our Sponsor in its sole discretion will appoint the board of directors of our General Partner.

• Our Partnership Agreement will contain provisions limiting the ability of unitholders to call meetings of unitholders, to nominate directors and to acquire information about our operations as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

• There are no restrictions in our Partnership Agreement on our ability to issue additional equity securities.

The effect of these provisions may be to diminish the price at which the common units will trade.

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

Our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. In addition, our Partnership Agreement does not restrict the ability of the members of our General Partner from transferring their respective limited liability company interests in our General Partner to a third party.

If we cease to control OPCO, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control OPCO and are deemed to be an investment company under the Investment Company Act of 1940 because of our ownership of OPCO interests, we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add additional directors who are independent of us or our affiliates.

Risks Relating to Our Business

Our growth depends on the level of activity in the offshore oil and natural gas industry, which is significantly affected by, among other things, volatile oil and natural gas prices, and may be materially and adversely affected by a decline in the offshore oil and natural gas industry.

The offshore drilling industry is cyclical and volatile. Our growth strategy focuses on expansion in the offshore drilling sector, which depends on the level of activity in oil and natural gas exploration, development and production in offshore areas worldwide. The availability of quality drilling prospects, exploration success, relative production costs, the stage of reservoir development and political and regulatory environments affect customers’ drilling programs. Oil and natural gas prices and market expectations of potential changes in these prices also significantly affect this level of activity and demand for drillships.

Oil and natural gas prices are extremely volatile and are affected by numerous factors beyond our control, including the following:

• worldwide production and demand for oil and natural gas;

• the cost of exploring for, developing, producing and delivering oil and natural gas;

• expectations regarding future energy prices;

• advances in exploration, development and production technology;

• the ability of the Organization of Petroleum Exporting Countries, or OPEC, to set and maintain levels and pricing;

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• the level of production in non-OPEC countries;

• government regulations, including restrictions on offshore transportation of oil and natural gas;

• local and international political, economic and weather conditions;

• domestic and foreign tax policies;

• development and exploitation of alternative fuels;

• the policies of various governments regarding exploration and development of their oil and natural gas reserves;

• accidents, severe weather, natural disasters and other similar incidents relating to the oil and natural gas industry; and

• the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities or other crises in the Middle East or other geographic areas or further acts of terrorism in the United States, or elsewhere.

Declines in oil and natural gas prices for an extended period of time, or market expectations of potential decreases in these prices, could negatively affect our future growth. Sustained periods of low oil and natural gas prices typically result in reduced exploration and drilling because oil and natural gas companies’ capital expenditure budgets are subject to cash flow from such activities and are therefore sensitive to changes in energy prices. These changes in commodity prices can have a dramatic effect on drillship demand, and periods of low demand can cause excess drillship supply and intensify the competition in the industry which often results in drillships, particularly older and less technologically-advanced drillships, being idle for long periods of time. We cannot predict the future level of demand for drillships or future conditions of the oil and natural gas industry. Any decrease in exploration, development or production expenditures by oil and natural gas companies could reduce our revenues and materially harm our business, results of operations and cash available for distribution.

In addition to oil and natural gas prices, the offshore drilling industry is influenced by additional factors, including:

• the availability of competing offshore drillships;

• the level of costs for associated offshore oilfield and construction services;

• oil and natural gas transportation costs;

• the level of rig operating costs including crew and maintenance;

• the discovery of new oil and natural gas reserves; and

• regulatory restrictions on offshore drilling.

Any of these factors could reduce demand for drillships and adversely affect our business and results of operations.

An increase in operating and maintenance costs could materially and adversely affect our financial performance.

Our and OPCO’s operating expenses and maintenance costs depend on a variety of factors including crew costs, provisions, equipment, insurance, maintenance and repairs and shipyard costs, many of which are beyond our control and affect the entire offshore drilling industry. During periods after which a drillship becomes idle, we may decide to “warm stack” the drillship, which means the drillship is kept fully operational and ready for redeployment, and maintains most of its crew. As a result, our operating expenses during a warm stacking will not be substantially different than those we would incur if the drillship remained active. We may also decide to “cold stack” the drillship, which the means the drillship is stored in a harbor, shipyard or a designated offshore area, and the crew is assigned to an active drillship or dismissed. However, reductions in costs following the

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decision to cold stack a drillship may not be immediate, as a portion of the crew may be required to prepare the drillship for such storage. Moreover, as our drillships are mobilized from one geographic location to another, the labor and other operating and maintenance costs can vary significantly. Operating and maintenance costs will not necessarily fluctuate in proportion to changes in operating revenues. Operating revenues may fluctuate as a function of changes in supply of offshore drillships and demand for contract drilling services, which in turn, affect dayrates, and the economic utilization and performance of OPCO’s fleet of drillships. However, operating costs are generally related to the number of drillships in operation and the cost level in each country or region where such drillships are located. In addition, equipment maintenance costs fluctuate depending upon the type of activity that the drillship is performing and the age and condition of the equipment. Escalation provisions contained in OPCO’s drilling contracts may not be adequate to substantially mitigate these increased operating and maintenance costs. In connection with new assignments, OPCO might incur expenses relating to preparation for operations under a new contract. The expenses may vary based on the scope and length of such required preparations and the duration of the contractual period over which such expenditures are amortized. In situations where OPCO’s drillships incur idle time between assignments, the opportunity to reduce the size of its crews on those drillships is limited as the crews will be engaged in preparing the drillship for its next contract. When a drillship faces longer idle periods, reductions in costs may not be immediate as some of the crew may be required to prepare drillships for stacking and maintenance in the stacking period. Should drillships be idle for a longer period, OPCO may not be successful in redeploying crew members, who are not required to maintain the drillships, and therefore may not be successful in reducing our costs in such cases.

Any limitation in the availability or operation of the Initial Fleet could have a material adverse effect on our business, results of operations and financial condition and could significantly reduce our ability to make distributions to our unitholders.

OPCO’s Initial Fleet currently consists of three drillships. If any of the drillships in OPCO’s Initial Fleet are unable to generate revenues as a result of the expiration or termination of its drilling contracts or sustained periods of downtime, our results of operations and financial condition could be materially adversely affected. Some of OPCO’s customers have the right to terminate their drilling contracts without cause upon the payment of an early termination fee. However, such payments may not fully compensate OPCO for the loss of the drilling contract. Under certain circumstances OPCO’s contracts may permit customers to terminate contracts early without the payment of any termination fees as a result of non-performance, total loss of the drillships, extended periods of downtime or impaired performance caused by equipment or operational issues, or sustained periods of downtime due to force majeure events beyond OPCO’s control. During periods of challenging market conditions, OPCO may be subject to an increased risk of its customers seeking to repudiate their contracts, including through claims of non-performance. OPCO’s customers’ ability to perform their obligations under their drilling contracts may also be negatively impacted by the prevailing uncertainty surrounding the development of the world economy and the credit markets. If a customer cancels its contract, and OPCO is unable to secure a new contract on a timely basis and on substantially similar terms, or if a contract is suspended for an extended period of time or if a contract is renegotiated on different terms, it could adversely affect our business, results of operations and financial condition and may reduce the amount of cash OPCO has available to distribute to us and that we have available for distribution to our unitholders. For more information regarding the termination provisions of OPCO’s drilling contracts, please read “Business—Drilling Contracts.”

OPCO currently derives all its revenue from three customers, and the loss of any of these customers could result in a significant loss of revenues and cash flow.

OPCO currently derives all of its revenues and cash flow from three customers. For the year ended December 31, 2013, Repsol accounted for 93%, Total accounted for 6% and ConocoPhillips accounted for 1% of OPCO’s total revenues, respectively. All of OPCO’s drilling contracts have fixed terms, but may be terminated early due to certain events or might nevertheless be lost in the event of unanticipated developments, such as the deterioration in the general business or financial condition of a customer, resulting in its inability meet its obligations under our contracts.

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If any of OPCO’s drilling contracts are terminated, OPCO may be unable to re-deploy the drillship subject to such terminated contract on terms as favorable to it as its current drilling contracts. If OPCO is unable to re-deploy a drillship for which the drilling contract has been terminated, OPCO will not receive any revenues from that drillship, but it will be required to pay expenses necessary to maintain the drillship in proper operating condition. This may cause OPCO to receive decreased revenues and cash flows from having fewer drillships operating in its fleet. The loss of any customers, drilling contracts or drillships, or a decline in payments under any of OPCO’s drilling contracts, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

In addition, our drilling contracts subject us to counterparty risks. The ability of each of our counterparties to perform its obligations under a contract with us will depend on a number of factors that are beyond our control and may include, among other things, general economic conditions, the condition of the offshore drilling industry, prevailing prices for oil and natural gas, the overall financial condition of the counterparty, the dayrates received for specific types of drillships and the level of expenses necessary to maintain drilling activities. In addition, in depressed market conditions, our customers may no longer need a drillship that is currently under contract or may be able to obtain a comparable drillship at a lower dayrate. Should a counterparty fail to honor its obligations under an agreement with us, we could sustain losses, which could have a material adverse effect on our business, financial condition, results of operations and cash available for distribution.

Competition within the offshore drilling industry may adversely affect us and OPCO.

The offshore drilling industry is highly competitive and fragmented and includes several large companies, as well as smaller companies, that compete in the markets OPCO serves. Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, drillship availability, drillship location, condition and integrity of equipment, its record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations. OPCO’s operations may be adversely affected if its current competitors or new market entrants introduce new drillships with better features, performance, price or other characteristics in comparison to OPCO’s drillships, or expand into service areas where OPCO operates. In addition, mergers among oil and natural gas exploration and production companies have reduced, and may from time to time further reduce, the number of available customers, which would increase the ability of potential customers to achieve pricing terms favorable to them. Competitive pressures or other factors may also result in significant price competition, particularly during industry downturns, which could have a material adverse effect on our financial position, results of operations, cash flows and ability to make distributions to our unitholders.

The current state of global financial markets and current economic conditions may adversely impact our ability to obtain additional financing on acceptable terms, which may hinder or prevent us from expanding our business.

Global financial markets and economic conditions have been, and continue to be, volatile. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions, have made, and will likely continue to make, it difficult to obtain additional financing. The current state of global financial markets and current economic conditions might adversely impact our ability to issue additional equity at prices which will not be dilutive to our existing shareholders or preclude us from issuing equity at all.

Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets has increased as many lenders have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at all or on terms similar to current debt and reduced, and in some cases ceased, to provide funding to borrowers. Due to these factors, we cannot be certain that additional financing will be available if needed and to the extent required,

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on acceptable terms or at all. If additional financing is not available when needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to enhance our existing business, complete additional drillship acquisitions or otherwise take advantage of business opportunities as they arise.

As of the date of this prospectus, we have not secured any financing in connection with the potential acquisition of the Additional Fleet Interests or the Optional Drillship Interests, since it is uncertain if and when such purchase options will be exercised. These acquisitions depend on many external factors beyond the Partnership’s control such as the Partnership’s future ability to finance these acquisitions through the issuance of equity and debt.

In addition, volatility and uncertainty concerning current global economic conditions may cause our customers to defer projects in response to tighter credit, decreased capital availability and declining customer confidence, which may negatively impact the demand for our drillships and services and could also result in defaults under our charters. A tightening of the credit markets may further negatively impact our operations by affecting the solvency of our suppliers or customers which could lead to disruptions in delivery of supplies such as equipment for conversions, cost increases for supplies, accelerated payments to suppliers, customer bad debts or reduced revenues.

Our future contracted revenue for OPCO’s Initial Fleet of drillships may not be ultimately realized.

As of June 13, 2014, the future contracted revenue for OPCO’s Initial Fleet of drillships, or our contract backlog, was approximately $2.5 billion under firm commitments. We may not be able to perform under our drilling contracts due to events beyond our control, and our customers may seek to cancel or renegotiate our drilling contracts for various reasons, including adverse conditions, resulting in lower daily rates. In addition, some of our customers could experience liquidity issues or could otherwise be unwilling or unable to perform under the contract, which could ultimately lead a customer to go into bankruptcy or otherwise encourage a customer to seek to repudiate, cancel or renegotiate a contract. Our inability, or the inability of our customers, to perform under the respective contractual obligations may have a material adverse effect on our financial position, results of operations and cash flows.

Failure to obtain or retain highly skilled personnel could adversely affect OPCO’s operations.

We believe that competition for skilled and other labor required for OPCO’s drilling operations has increased in recent years as the number of drillships activated or added to worldwide fleets has increased. Under certain of OPCO’s drilling contracts, we are required to have a minimum number of local crew members on our drillships. Competition for the labor required for drilling operations has intensified as the number of drillships activated, added to worldwide fleets or under construction has increased, leading to shortages of qualified personnel in the industry and creating upward pressure on wages and higher turnover. If turnover increases, we could see a reduction in the experience level of our personnel, which could lead to higher downtime, more operating incidents and personal injury and other claims, which in turn could decrease revenues and increase costs. In response to these labor market conditions, we are increasing efforts in our recruitment, training, development and retention programs as required to meet our anticipated personnel needs. If these labor trends continue, we may experience further increases in costs or limits on our offshore drilling operations.

Currently, some of our employees are covered by collective bargaining agreements. In the future, some of our employees or contracted labor may also be covered by collective bargaining agreements in certain jurisdictions. As part of the legal obligations in some of these agreements, we may be required to contribute certain amounts to retirement funds and pension plans and have restricted ability to dismiss employees. In addition, many of these represented individuals could be working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs, other increased costs or increased operating restrictions that could adversely affect our financial performance. Labor disruptions could hinder our

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operations from being carried out normally and if not resolved in a timely cost-effective manner, could have a material impact our business. If we choose to cease operations in one of those countries or if market conditions reduce the demand for our drilling services in such a country, we would incur costs, which may be material, associated with workforce reductions.

Construction of drillships is subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.

From time to time in the future, we may undertake additional new construction projects and conversion projects. In addition, we may make significant upgrade, refurbishment, conversion and repair expenditures for OPCO’s Initial Fleet from time to time, particularly as our drillships become older. Some of these expenditures are unplanned. These projects together with our existing construction projects and other efforts of this type, are subject to risks of cost overruns or delays inherent in any large construction project as a result of numerous factors, including the following:

• shipyard unavailability;

• shortages of equipment, materials or skilled labor for completion of repairs or upgrades to our equipment;

• unscheduled delays in the delivery of ordered materials and equipment or shipyard construction;

• financial or operating difficulties experienced by equipment vendors or the shipyard;

• unanticipated actual or purported change orders;

• local customs strikes or related work slowdowns that could delay importation of equipment or materials;

• engineering problems, including those relating to the commissioning of newly designed equipment;

• design or engineering changes;

• latent damages or deterioration to the hull, equipment and machinery in excess of engineering estimates and assumptions;

• work stoppages;

• client acceptance delays;

• weather interference, storm damage or other events of force majeure;

• disputes with shipyards and suppliers;

• shipyard failures and difficulties;

• failure or delay of third-party equipment vendors or service providers;

• unanticipated cost increases; and

• difficulty in obtaining necessary permits or approvals or in meeting permit or approval conditions.

These factors may contribute to cost variations and delays in the delivery of any newbuilding drillships in the future. Delays in the delivery of these newbuilding drillships or the inability to complete construction in accordance with their design specifications may, in some circumstances, result in a delay in drilling contract commencement, resulting in a loss of revenue to us, and may also cause customers to renegotiate, terminate or shorten the term of a drilling contract pursuant to applicable late delivery clauses. In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms or at all. Additionally, capital expenditures for drillship upgrades, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, drillships that undergo upgrade, refurbishment and repair may not earn a dayrate during the periods they are out of service. In addition, in the event of a

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shipyard failure or other difficulty, we may be unable to enforce certain provisions under our newbuilding contracts such as a refund guarantee, to recover amounts paid as installments under such contracts. The occurrence of any of these events may have a material adverse effect on our results of operations, financial condition or cash flows.

We may be unable to obtain, maintain, and/or renew permits necessary for our operations or experience delays in obtaining such permits, which could have a material effect on our operations.

The operation of OPCO’s Initial Fleet is subject to certain governmental approvals and permits, including work permits. The permitting rules in most jurisdictions, and the interpretations of those rules, are complex, subject to change, including their interpretations by regulators, all of which may make compliance more difficult or impractical, and may increase the length of time it takes to receive regulatory approval for offshore drilling operations. In many jurisdictions, substantive requirements under environmental laws are implemented through permits and permit renewals. If we fail to timely secure the necessary approvals or permits, OPCO’s customers may have the right to terminate or seek to renegotiate their drilling contracts to OPCO’s detriment. In the future, the amendment or modification of existing laws and regulations or the adoption of new laws and regulations curtailing or further regulating exploratory or development drilling and production of oil and gas or increasing the time needed to obtain necessary environmental permits, could have a material adverse effect on our business, operating results or financial condition.

Certain work stoppages or maintenance or repair work may cause OPCO’s customers to suspend or reduce payment of dayrates until operation of the respective drillship is resumed, which may lead to termination or renegotiation of the drilling contract.

Compensation under OPCO’s drilling contracts is based on daily performance and/or availability of each drillship in accordance with the requirements specified in the applicable drilling contract. For instance, when OPCO’s drillships are idle, but available for operation, OPCO’s customers are entitled to pay a waiting rate lower than the operational rate.

Several factors could cause an interruption of operations, including:

• breakdowns of equipment and other unforeseen engineering problems;

• work stoppages, including labor strikes;

• shortages of material and skilled labor;

• delays in repairs by suppliers;

• surveys by government and maritime authorities;

• periodic classification surveys;

• severe weather, strong ocean currents or harsh operating conditions; and

• force majeure events.

In addition, if OPCO’s drillships are taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in its drilling contracts, OPCO will not be entitled to payment of dayrates until the relevant rig is available for deployment. If the interruption of operations were to exceed a determined period due to an event of force majeure, OPCO’s customers have the right to pay a rate (the “force majeure rate”) that is significantly lower than the waiting rate for a period of time, and, thereafter, may terminate the drilling contracts related to the subject drillship. For more details on OPCO’s drilling contracts, see “Business—Drilling Contracts” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Our Results of Operation.” Suspension of drilling contract payments, prolonged payment of reduced rates or termination of any drilling contract agreements as a result of an interruption of operations as described herein could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders.

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OPCO’s business and operations involve numerous operating hazards, and its insurance and indemnities from its customers may not be adequate to cover potential losses from its operations.

OPCO’s operations are subject to hazards inherent in the offshore drilling industry, such as blowouts, reservoir damage, loss of production, loss of well control, lost or stuck drill strings, equipment defects, punch-throughs, craterings, fires, explosions and pollution. Contract drilling requires the use of heavy equipment and exposure to hazardous conditions, which may subject us to liability claims by employees, customers and third parties. These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment, pollution or environmental damage, claims by third parties or customers and suspension of operations. OPCO’s offshore fleet is also subject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding, collision, piracy, damage from severe weather and marine life infestations. Operations may also be suspended because of machinery breakdowns, abnormal drilling conditions, failure of subcontractors to perform or supply goods or services or personnel shortages. OPCO customarily provides contract indemnity to its customers for claims that could be asserted by OPCO relating to damage to or loss of our equipment, including drillships, and claims that could be asserted by OPCO or its employees relating to personal injury or loss of life.

Damage to the environment could also result from OPCO’s operations, particularly through spillage of hydrocarbons, fuel, lubricants or other chemicals and substances used in drilling operations, or extensive uncontrolled fires. OPCO may also be subject to property damage, environmental indemnity and other claims by oil and natural gas companies. OPCO’s insurance policies and drilling contracts contain rights to indemnity that may not adequately cover its losses, and OPCO does not have insurance coverage or rights to indemnity for all risks. There are certain risks, including risks associated with the loss of control of a well (such as blowout, cratering, the cost to regain control of or re-drill the well and remediation of associated pollution), for which OPCO’s customers may be unable or willing to indemnify OPCO. We generally indemnify our customers against pollution from substances in our control that originate from the drilling unit (e.g., diesel used onboard the unit or other fluids stored onboard the unit and above the water surface). However, our drilling contracts are individually negotiated, and the degree of indemnification we receive from the customer against the liabilities discussed above can vary from contract to contract, based on market conditions and customer requirements existing when the contract was negotiated. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations. We maintain insurance coverage for property damage, occupational injury and illness, and general and marine third-party liabilities. However, pollution and environmental risks generally are not totally insurable. Furthermore, we have no insurance coverage for named storms in the Gulf of Mexico and while trading within war risks excluded areas.

Our insurance may not be sufficient to cover losses that may occur to our property or as a result of our operations.

The operation of drillships is inherently risky. All risks may not be adequately insured against, and any particular claim may not be paid by insurance. Any claims relating to our operations covered by insurance would be subject to deductibles, and since it is possible that a large number of claims may be brought, the aggregate amount of these deductibles could be material. Certain insurance is maintained through mutual protection and indemnity associations, and as a member of such associations we may be required to make additional payments over and above budgeted premiums if member claims exceed association reserves. Moreover, our insurance provides for premium adjustments based on claims and is subject to deductibles and aggregate recovery limits. In the case of pollution liabilities, our deductible is $10,000 per event and $250,000 for protection and indemnity claims brought before any U.S. jurisdiction. Our aggregate recovery limit is $500.0 million for all claims arising out of any event covered by our protection and indemnity insurance. Our deductible is $1.5 million per hull and machinery insurance claim in OPCO’s Initial Fleet.

We may be unable to procure adequate insurance at commercially reasonable rates in the future. For example, more stringent environmental regulations have led in the past to increased costs for, and in the future

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may result in the lack of availability of, insurance against risks of environmental damage or pollution. A catastrophic oil spill or marine disaster could exceed the insurance, and any uninsured or underinsured loss could harm our business, financial condition, results of operations and ability to make cash distributions to our unitholders. In addition, the insurance may be voidable by the insurers as a result of certain actions, such as vessels failing to maintain certification with applicable maritime self-regulatory organizations.

Changes in the insurance markets attributable to terrorist attacks may also make certain types of insurance more difficult to obtain. In addition, the insurance that may be available may be significantly more expensive than existing coverage.

An over-supply of drillships may lead to a reduction in dayrates and therefore may materially impact OPCO’s profitability.

During the recent period of high utilization and high dayrates, industry participants have increased the supply of drillships by ordering the construction of new drillships. Historically, this has resulted in an over-supply of drillships and has caused a subsequent decline in utilization and dayrates when the drillships enter the market, sometimes for extended periods of time until the units have been absorbed into the active fleet. According to Drewry Maritime Research, the worldwide fleet of ultra deepwater drilling units as of April 4, 2014 consisted of 143 units, comprised of 67 semi-submersible rigs and 76 drillships. An additional 14 semi-submersible rigs and 66 drillships were under construction or on order as of April 4, 2014, which would bring the total fleet to 223 ultra deepwater drilling units by the end of 2020, assuming no scrappage. A relatively large number of the drillships currently under construction have been contracted for future work, which may intensify price competition as scheduled delivery dates occur. The entry into service of these new, upgraded or reactivated drillships will increase supply and has already led to a reduction in dayrates as drillships are absorbed into the active fleet. Lower utilization and dayrates could adversely affect our and OPCO’s revenues and profitability. Prolonged periods of low utilization and dayrates could also result in the recognition of impairment charges on OPCO’s drillships if future cash flow estimates, based upon information available to management at the time, indicate that the carrying value of these drillships may not be recoverable.

The market value of OPCO’s current drillships and those vessels we or OPCO acquire in the future may decrease, which could cause us to incur losses if we decide to sell them following a decline in their market values.

If the offshore drilling industry suffers adverse developments in the future, the fair market value of OPCO’s drillships may decline. The fair market value of the drillships that OPCO currently owns, or that we or OPCO may acquire in the future, may increase or decrease depending on a number of factors, including:

• general economic and market conditions affecting the offshore drilling industry, including competition from other offshore contract drilling companies;

• types, sizes and ages of drillships;

• supply and demand for drillships;

• costs of newbuilds;

• prevailing level of drilling services contract dayrates;

• governmental or other regulations; and

• technological advances.

If we or OPCO sell any drillship at a time when prices for drillships have fallen, such a sale may result in a loss. Such a loss could materially and adversely affect our business prospects, financial condition, liquidity, results of operations and ability of OPCO to pay distributions to us and us to our unitholders.

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Consolidation and government regulation of suppliers may increase the cost of obtaining supplies or restrict OPCO’s ability to obtain needed supplies, which may have a material adverse effect on our results of operations and financial condition.

We rely on certain third parties to provide supplies and services necessary for our operations, including, but not limited to, drilling equipment suppliers and catering and machinery suppliers. Recent mergers have reduced the number of available suppliers, resulting in fewer alternatives for sourcing key supplies. Such consolidation, combined with a high volume of drillships under construction, may result in a shortage of supplies and services, thereby increasing the cost of supplies and/or potentially inhibiting the ability of suppliers to deliver on time, or at all. These cost increases, delays or unavailability could have a material adverse effect on our results of operations and result in drilling unit downtime and delays in the repair and maintenance of our drillships.

OPCO’s international operations involve additional risks, which could adversely affect our business.

As a result of OPCO’s international operations, we may be exposed to political and other uncertainties, including risks of:

• terrorist acts, armed hostilities, war and civil disturbances;

• acts of piracy, which have historically affected ocean-going drilling units trading in regions of the world such as the South China Sea, the Gulf of Aden off the coast of Somalia, where piracy has increased significantly in frequency since 2008, and off the west coast of Africa;

• significant governmental influence over many aspects of local economies;

• seizure, nationalization or expropriation of property or equipment;

• repudiation, nullification, modification or renegotiation of contracts;

• limitations on insurance coverage, such as war risk coverage, in certain areas;

• political unrest;

• foreign and U.S. monetary policy and foreign currency fluctuations and devaluations;

• the inability to repatriate income or capital;

• complications associated with repairing and replacing equipment in remote locations;

• import-export quotas, wage and price controls, imposition of trade barriers;

• U.S. and foreign sanctions or trade embargoes;

• regulatory or financial requirements to comply with foreign bureaucratic actions;

• changing taxation policies, including confiscatory taxation;

• other forms of government regulation and economic conditions that are beyond our control; and

• governmental corruption.

In addition, international contract drilling operations are subject to various laws and regulations of the countries in which OPCO operates, including laws and regulations relating to:

• the equipping and operation of drillships;

• exchange rates or exchange controls;

• oil and natural gas exploration and development;

• taxation of offshore earnings and the earnings of expatriate personnel; and

• use and compensation of local employees and suppliers by foreign contractors.

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Fluctuations in exchange rates or exchange controls could result in losses to us.

As a result of OPCO’s international operations, we are exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than U.S. dollars. Accordingly, we may experience currency exchange losses if we have not fully hedged our exposure to a foreign currency, or if revenues are received in currencies that are not readily convertible. We may also be unable to collect revenues because of a shortage of convertible currency available to the country of operation, controls over the repatriation of income or capital or controls over currency exchange.

OPCO and the majority of its subsidiaries use the U.S. Dollar as their functional currency because the majority of their revenues and expenses are denominated in U.S. Dollars. Accordingly, our reporting currency is also US dollars. We do, however, earn revenue and incur expenses in other currencies and there is a risk that currency fluctuations could have an adverse effect on our statements of operations and cash flows.

If OPCO’s business activities involve countries, entities and individuals that are subject to restrictions imposed by the U.S. or other governments, we could be subject to enforcement action and our reputation and the market for our common units could be adversely affected.

Although none of OPCO’s drillships have operated in countries subject to sanctions and embargoes imposed by the U.S. government and other authorities or countries identified by the U.S. government or other authorities as state sponsors of terrorism, including Cuba, Iran, Sudan and Syria, in the future our drillships may operate in these countries from time to time on our customers’ instructions. The U.S. sanctions and embargo laws and regulations vary in their application, as they do not all apply to the same covered persons or proscribe the same activities, and such sanctions and embargo laws and regulations may be amended or strengthened over time. In 2010, the U.S. enacted the Comprehensive Iran Sanctions Accountability and Divestment Act, or CISADA, which expanded the scope of the Iran Sanctions Act. Among other things, CISADA expands the application of the prohibitions to companies such as ours and introduces limits on the ability of companies and persons to do business or trade with Iran when such activities relate to the investment, supply or export of refined petroleum or petroleum products. In addition, in 2012, President Obama signed Executive Order 13608 which prohibits foreign persons from violating or attempting to violate, or causing a violation of any sanctions in effect against Iran or facilitating any deceptive transactions for or on behalf of any person subject to U.S. sanctions. Any persons found to be in violation of Executive Order 13608 will be deemed a foreign sanctions evader and will be banned from all contacts with the United States, including conducting business in U.S. dollars. Also in 2012, President Obama signed into law the Iran Threat Reduction and Syria Human Rights Act of 2012, or the Iran Threat Reduction Act, which created new sanctions and strengthened existing sanctions. Among other things, the Iran Threat Reduction Act intensifies existing sanctions regarding the provision of goods, services, infrastructure or technology to Iran’s petroleum or petrochemical sector. The Iran Threat Reduction Act also includes a provision requiring the President of the United States to impose five or more sanctions from Section 6(a) of the Iran Sanctions Act, as amended, on a person the President determines is a controlling beneficial owner of, or otherwise owns, operates, or controls or insures a vessel that was used to transport crude oil from Iran to another country and (1) if the person is a controlling beneficial owner of the vessel, the person had actual knowledge the vessel was so used or (2) if the person otherwise owns, operates, or controls, or insures the vessel, the person knew or should have known the vessel was so used. Such a person could be subject to a variety of sanctions, including exclusion from U.S. capital markets, exclusion from financial transactions subject to U.S. jurisdiction, and exclusion of that person’s vessels from U.S. ports for up to two years.

Although we believe that we are in compliance with all applicable sanctions and embargo laws and regulations, and intend to maintain such compliance, there can be no assurance that we will be in compliance in the future, particularly as the scope of certain laws may be unclear and may be subject to changing interpretations. Any such violation could result in fines, penalties or other sanctions that could severely impact our ability to access U.S. capital markets and conduct our business, and could result in some investors deciding, or being required, to divest their interest, or not to invest, in us. In addition, certain institutional investors may have investment policies or restrictions that prevent them from holding securities of companies that have

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contracts with countries identified by the U.S. government as state sponsors of terrorism. The determination by these investors not to invest in, or to divest from, our common stock may adversely affect the price at which our common stock trades. Moreover, our customers may violate applicable sanctions and embargo laws and regulations as a result of actions that do not involve us or our drillships, and those violations could in turn negatively affect our reputation. In addition, our reputation and the market for our securities may be adversely affected if we engage in certain other activities, such as entering into drilling contracts with individuals or entities in countries subject to U.S. sanctions and embargo laws that are not controlled by the governments of those countries, or engaging in operations associated with those countries pursuant to contracts with third parties that are unrelated to those countries or entities controlled by their governments. Investor perception of the value of our common stock may be adversely affected by the consequences of war, the effects of terrorism, civil unrest and governmental actions in these and surrounding countries.

On November 24, 2013, the P5+1 (the United States, United Kingdom, Germany, France, Russia and China) entered into an interim agreement with Iran entitled the “Joint Plan of Action” (“JPOA”). Under the JPOA it was agreed that, in exchange for Iran taking certain voluntary measures to ensure that its nuclear program is used only for peaceful purposes, the U.S. and EU would voluntarily suspend certain sanctions for a period of six months.

On January 20, 2014, the U.S. and E.U. indicated that they would begin implementing the temporary relief measures provided for under the JPOA. These measures include, among other things, the suspension of certain sanctions on the Iranian petrochemicals, precious metals, and automotive industries from January 20, 2014 until July 20, 2014. On July 19, 2014, the P5+1 and Iran affirmed that they will continue to implement the commitments described in the JPOA, and the U.S. and E.U. agreed to extend its suspension of the aforementioned sanctions through November 24, 2014.

Although it is our intention to comply with the provisions of the JPOA, there can be no assurance that we will be in compliance in the future as such regulations and U.S. Sanctions may be amended over time, and the U.S. retains the authority to revoke the aforementioned relief if Iran fails to meet its commitments under the JPOA.

Local content policies may impair OPCO’s ability to compete in local jurisdictions, and changes in these policies may adversely affect our financial conditions and results of operations.

Certain foreign governments, such as those of Brazil and Angola, favor or effectively require (i) the awarding of drilling contracts to local contractors or to drillships owned by their own citizens, (ii) the use of a local agent or (iii) foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. For example, the local content policy in Angola requires our customers to develop and implement a plan to increase local Angolan content, including specific goals. These regulations may adversely affect OPCO’s ability to compete in these contract drilling markets. Further, local content policies may be subject to significant and unpredictable changes, which may lead to greater uncertainty in operational planning in those jurisdictions.

If any of OPCO’s drillships fail to maintain their class certification or fail any annual survey or special survey, that drillship would be unable to operate, thereby reducing our revenues and profitability and violating certain covenants under certain of our debt agreements.

Every drilling unit must be “classed” by a classification society. The classification society certifies that the drilling unit is “in-class,” signifying that such drilling unit has been built and maintained in accordance with the rules of the classification society and complies with applicable rules and regulations of the drilling unit’s country of registry and the international conventions of which that country is a member. In addition, where surveys are required by international conventions and corresponding laws and ordinances of a flag state, the classification society will undertake them on application or by official order, acting on behalf of the authorities concerned. Our operating drillships, theOcean Rig Mylos and theOcean Rig Skyros are due for their first Special Periodical Surveys in 2018, whilethe Ocean Rig Athena, is due for its first Special Periodical Surveys in 2019. If any

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drilling unit does not maintain its class and/or fails any annual survey or special survey, the drilling unit will be unable to carry on operations and will be unemployable and uninsurable, which could cause us to be in violation of certain covenants in certain of our debt agreements. Any such inability to carry on operations or be employed, or any such violation of covenants, could have a material adverse impact on our financial condition and results of operations.

A change in tax laws in any country in which we operate could result in higher tax expense.

We conduct our operations through various subsidiaries. Tax laws and regulations are highly complex and subject to interpretation. Consequently, we are subject to changing tax laws, treaties and regulations in and between countries in which we operate. Our income tax expense is based on our interpretation of the tax laws in effect at the time the expense was incurred. A change in tax laws, treaties or regulations, or in the interpretation thereof, could result in a materially higher tax expense or a higher effective tax rate on our earnings.

We file periodic tax returns that are subject to review and audit by various revenue agencies in the jurisdictions in which we operate. Taxing authorities may challenge any of our tax positions, at which time we will contest such assessments where we believe the assessments are in error. Determinations by such authorities that differ materially from our recorded estimates, favorably or unfavorably, may have a material impact on our results of operations, financial position or cash available for distribution.

We are subject to complex laws and regulations, including environmental laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

OPCO’s operations are subject to numerous laws and regulations in the form of international conventions and treaties, national, state and local laws and national and international regulations in force in the jurisdictions in which OPCO’s drillships operate or are registered, which can significantly affect the ownership and operation of our drillships. These requirements include, but are not limited to, the International Convention for the Prevention of Pollution from Ships, or MARPOL, the International Convention on Civil Liability for Oil Pollution Damage of 1969, generally referred to as CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or Bunker Convention, the International Convention for the Safety of Life at Sea of 1974, or SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, the International Convention for the Control and Management of Ships’ Ballast Water and Sediments in February 2004, or the BWM Convention, the U.S. Oil Pollution Act of 1990, or OPA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Clean Water Act, the U.S. Clean Air Act, the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002, or the MTSA, European Union regulations, Angola’s Petroleum Activities Law and Brazil’s National Environmental Policy Law (6938/81), Environmental Crimes Law (9605/98) and Law (9966/2000) relating to pollution in Brazilian waters.

Compliance with such laws, regulations and standards, where applicable, may require installation of costly equipment or operational changes and may affect the resale value or useful lives of our vessels. Moreover, the manner in which these laws are enforced and interpreted is constantly evolving. OPCO may also incur additional costs in order to comply with other existing and future regulatory obligations, including, but not limited to, costs relating to air emissions, including greenhouse gases, the management of ballast waters, maintenance and inspection, development and implementation of emergency procedures and insurance coverage or other financial assurance of our ability to address pollution incidents. These costs could have a material adverse effect on our business, results of operations, cash flows and financial condition. A failure to comply with applicable laws and regulations may result in administrative and civil penalties, criminal sanctions or the suspension or termination of our operations. Environmental laws often impose strict liability for remediation of spills and releases of oil and hazardous substances, which could subject us to liability without regard to whether we were negligent or at fault. Under OPA, for example, owners, operators and bareboat charterers are jointly and severally strictly liable for the discharge of oil in U.S. waters, including the 200-nautical mile exclusive economic zone around the

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United States. An oil spill could result in significant liability, including fines, penalties and criminal liability and remediation costs for natural resource damages under other international and U.S. federal, state and local laws, as well as third-party damages. We are required to satisfy insurance and financial responsibility requirements for potential oil (including marine fuel) spills and other pollution incidents and our insurance may not be sufficient to cover all such risks. As a result, claims against us could result in a material adverse effect on our business, results of operations, cash flows and financial condition.

Although OPCO’s drillships are separately owned by its subsidiaries, under certain circumstances a parent company and all of the ship-owning affiliates in a group under common control engaged in a joint venture could be held liable for damages or debts owed by one of the affiliates, including liabilities for oil spills under OPA or other environmental laws. Therefore, it is possible that OPCO could be subject to liability upon a judgment against us or any one of its subsidiaries.

OPCO’s drillships could cause the release of oil or hazardous substances, especially as its drillships age. Any releases may be large in quantity, above our permitted limits or occur in protected or sensitive areas where public interest groups or governmental authorities have special interests. Any releases of oil or hazardous substances could result in fines and other costs to OPCO, such as costs to upgrade our drillships, clean up the releases, and comply with more stringent requirements in its discharge permits. Moreover, these releases may result in OPCO’s customers or governmental authorities suspending or terminating its operations in the affected area, which could have a material adverse effect on our business, results of operation and financial condition.

If OPCO is able to obtain from its customers some degree of contractual indemnification against pollution and environmental damages in its contracts, such indemnification may not be enforceable in all instances or the customer may not be financially able to comply with its indemnity obligations in all cases. In addition, we may not be able to obtain such indemnification agreements in the future.

OPCO’s insurance coverage may not be available in the future or we may not obtain certain insurance coverage. If it is available and we have the coverage, it may not be adequate to cover our liabilities. Any of these scenarios could have a material adverse effect on our business, operating results and financial condition.

Regulation of greenhouse gases and climate change could have a negative impact on our business.

Currently, emissions of greenhouse gases from ships involved in international transport are not subject to the Kyoto Protocol to the United Nations Framework Convention on Climate Change, which entered into force in 2005 and pursuant to which adopting countries have been required to implement national programs to reduce greenhouse gas emissions. As of January 1, 2013, all ships (including rigs and drillships) must comply with mandatory requirements adopted by the MEPC in July 2011 relating to greenhouse gas emissions. All ships are required to follow the Ship Energy Efficiency Management Plans. Now the minimum energy efficiency levels per capacity mile, outlined in the Energy Efficiency Design Index, applies to all new ships. These requirements could cause us to incur additional compliance costs. The IMO is also considering the implementation of market-based mechanisms to reduce greenhouse gas emissions from ships. The European Union has indicated that it intends to propose an expansion of the existing European Union emissions trading scheme to include emissions of greenhouse gases from marine vessels, and in January 2012 the European Commission launched a public consultation on possible measures to reduce greenhouse gas emissions from ships. In the United States, the EPA has issued a finding that greenhouse gases endanger public health and safety and has adopted regulations to limit greenhouse gas emissions from certain mobile sources and large stationary sources. Although the mobile source emissions regulations do not apply to greenhouse gas emissions from vessels, such regulation of vessels is foreseeable, and the EPA has in recent years received petitions from the California Attorney General and various environmental groups seeking such regulation. Any passage of climate control legislation or other regulatory initiatives by the IMO, European Union, the U.S. or other countries where we operate, or any treaty adopted at the international level to succeed the Kyoto Protocol, that restrict emissions of greenhouse gases could require us to make significant financial expenditures which we cannot predict with certainty at this time.

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Because our business depends on the level of activity in the offshore oil and gas industry, existing or future laws, regulations, treaties or international agreements related to greenhouse gases and climate change, including incentives to conserve energy or use alternative energy sources, could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and gas. In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business.

Failure to comply with the U.S. Foreign Corrupt Practices Act could result in fines, criminal penalties, drilling contract terminations and an adverse effect on our business.

OPCO has operated its drillships outside of the United States in Angola and Brazil. The existence of state or government-owned shipbuilding enterprises puts us in contact with persons who may be considered “foreign officials” under the U.S. Foreign Corrupt Practices Act of 1977, or the FCPA. We are committed to doing business in accordance with applicable anti-corruption laws and have adopted a code of business conduct and ethics which is consistent and in full compliance with the FCPA. OPCO is subject, however, to the risk that we, our affiliated entities or their respective officers, directors, employees and agents may take actions determined to be in violation of such anti-corruption laws, including the FCPA. Any such violation could result in substantial fines, sanctions, civil and/or criminal penalties, curtailment of operations in certain jurisdictions, and might adversely affect our business, results of operations or financial condition. In addition, actual or alleged violations could damage our reputation and ability to do business. Furthermore, detecting, investigating, and resolving actual or alleged violations is expensive and can consume significant time and attention of our senior management.

The Deepwater Horizon oil spill in the Gulf of Mexico may result in more stringent laws and regulations governing deepwater drilling, which could have a material adverse effect on our business, operating results or financial condition.

On April 20, 2010, there was an explosion and a related fire on the Deepwater Horizon, an ultra-deepwater semi-submersible drilling unit that is not connected to us, while it was servicing the Macondo well in the Gulf of Mexico. This catastrophic event resulted in the death of 11 workers and the total loss of that drilling unit, as well as the release of large amounts of oil into the Gulf of Mexico, severely impacting the environment and the region’s key industries. This event is being investigated by several federal agencies, including the U.S. Department of Justice, and by the U.S. Congress, and is also the subject of numerous lawsuits. On January 11, 2011, the National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling released its final report, with recommendations for new regulations.

We do not currently operate our drillships in the Gulf of Mexico, but we may do so in the future. In any event, changes to leasing and drilling activity requirements as a result of the Deepwater Horizon incident could have a substantial impact on the offshore oil and gas industry worldwide. All drilling activity in the U.S. Gulf of Mexico must be in compliance with enhanced safety requirements contained in Notices to Lessees 2010-N05 and 2010 N-06. Effective October 22, 2012 all drilling in the U.S. Gulf of Mexico must also comply with the Final Drilling Safety Rule as adopted on August 15, 2012, which enhances safety measures for energy development on the outer continental shelf. All drilling must also comply with the Revised Workplace Safety Rule on Safety and Environmental Management Systems (SEMSII), issued by BSEE on April 5, 2013. We continue to evaluate these requirements to ensure that our rigs and equipment are in full compliance, where applicable. Additional requirements could be forthcoming based on further recommendations by regulatory agencies investigating the Macondo well incident.

We are not able to predict the extent of future leasing plans or the likelihood, nature or extent of additional rulemaking. Nor are we able to predict when the Bureau of Ocean Energy Management (BOEM) will enter into leases with our customers or when the Bureau of Safety and Environmental Enforcement (BSEE) will issue drilling permits to our customers. We are not able to predict the future impact of these events on our operations.

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Acts of terrorism, piracy and political and social unrest could affect us specifically or, more generally, the markets for drilling services, which may have a material adverse effect on our results of operations.

Acts of terrorism, piracy, and political and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. OPCO’s drilling operations may be targeted by acts of terrorism, piracy, or acts of vandalism or sabotage carried out by environmental activist groups. In addition, acts of terrorism and political and social unrest could lead to increased volatility in prices for crude oil and natural gas and could affect the markets for drilling services and result in lower dayrates. OPCO’s insurance premiums could increase as a result of these events, and coverage may be unavailable in the future.

Any failure to comply with the complex laws and regulations governing international trade could adversely affect our operations.

The shipment of goods, services and technology across international borders subjects our business to extensive trade laws and regulations. Import activities are governed by unique customs laws and regulations in each of the countries of operation. Moreover, many countries, including the United States, control the export and re-export of certain goods, services and technology and impose related export recordkeeping and reporting obligations. Governments also may impose economic sanctions against certain countries, persons and other entities that may restrict or prohibit transactions involving such countries, persons and entities. U.S. sanctions, in particular, are targeted against countries (such as Cuba, Iran, Russia, Sudan and Syria, among others) that are heavily involved in the petroleum and petrochemical industries, which includes drilling activities.

The laws and regulations concerning import activity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws and regulations may be enacted, amended, enforced or interpreted in a manner materially impacting our operations. Shipments can be delayed and denied export or entry for a variety of reasons, some of which are outside our control and some of which may result from failure to comply with existing legal and regulatory regimes. Shipping delays or denials could cause unscheduled operational downtime. Any failure to comply with applicable legal and regulatory trading obligations could also result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment from government contracts, seizure of shipments and loss of import and export privileges.

Risk Related to an Investment in Our Partnership

Substantial future sales of our common units in the public market could cause the price of our common units to fall.

We will grant registration rights to our Sponsor and certain of its affiliates. These unitholders will have the right, subject to some conditions, to require us to file registration statements covering any of our common, subordinated or other equity securities owned by them or to include those securities in registration statements that we may file for ourselves or other unitholders. Upon the closing of this offering and assuming no exercise of the underwriters’ option to purchase additional common units, our Sponsor will             own common units and             subordinated units and all of the incentive distribution rights (through its ownership of our General Partner). Following their registration and sale under the applicable registration statement, those securities will become freely tradable. By exercising their registration rights and selling a large number of common units or other securities, these unitholders could cause the price of our common units to decline.

You will experience immediate and substantial dilution of $         per common unit.

The assumed initial public offering price of $         per common unit (which is the midpoint of the range set forth in the cover of this prospectus) exceeds pro forma net tangible book value of $         per common unit. Based on the assumed initial public offering price, you will incur immediate and substantial dilution of $         per common unit. This dilution results primarily because the assets contributed by our General Partner and its affiliates are recorded at their historical cost, and not their fair value, in accordance with U.S. GAAP. Please read “Dilution.”

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Our General Partner, as the initial holder of all of the incentive distribution rights, may elect to cause us to issue additional common units to it in connection with a resetting of the target distribution levels related to our General Partner’s incentive distribution rights without the approval of the conflicts committee the board of directors of our General Partner or holders of our common units and subordinated units. This may result in lower distributions to holders of our common units in certain situations.

Our General Partner, as the initial holder of all of the incentive distribution rights, will have the right, at a time when there are no subordinated units outstanding and our General Partner has received incentive distributions at the highest level to which it is entitled (50.0%) for each of the prior four consecutive fiscal quarters, to reset the initial cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our General Partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution amount.

In connection with resetting these target distribution levels, our General Partner will be entitled to receive a number of common units equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our General Partner on the incentive distribution rights in the prior two quarters. We anticipate that our General Partner 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; however, it is possible that our General Partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued additional common units to our General Partner in connection with resetting the target distribution levels related to our General Partner’s incentive distribution rights. Please read “How We Make Cash Distributions—Incentive Distribution Rights” and “How We Make Cash Distributions—Our General Partner’s Right to Reset Incentive Distribution Levels.”

We may issue additional equity securities, including securities senior to the common units, without your approval, which would dilute your ownership interests.

We may, without the approval of our unitholders, issue an unlimited number of additional units or other equity securities. In addition, we may issue an unlimited number of units that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

• our unitholders’ 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 relative voting strength of each previously outstanding unit may be diminished; and

• the market price of the common units may decline.

Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash.

During the subordination period, which we define elsewhere in this prospectus, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum

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quarterly distribution of $ per unit, 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. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units. Upon the expiration of the subordination period, the subordinated units will convert into common units and will then participate pro rata with other common units in distributions of available cash. See “How We Make Cash Distributions—Subordination Period,” “—Distributions of Available Cash From Operating Surplus During the Subordination Period” and “—Distributions of Available Cash From Operating Surplus After the Subordination Period.”

Our General Partner’s discretion in establishing cash reserves may reduce the amount of cash we have available to distribute to unitholders.

Our Partnership Agreement requires our general partner to deduct from operating surplus the cash reserves that it determines are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the General Partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash we have available to distribute to unitholders.

Our General Partner has a limited call right that may require you to sell your common units at an undesirable time or price.

If at any time our General Partner and its affiliates will own more than 80% of the common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price of our common 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 the exercise of this limited call right. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. For additional information about the limited call right, please read “The Partnership Agreement—Limited Call Right.”

At the completion of this offering and assuming no exercise of the underwriters’ over-allotment option, our Sponsor, which owns and controls our General Partner, will own     % of our common units. At the end of the subordination period, assuming no additional issuances of common units, no exercise of the underwriters’over-allotment option and the conversion of our subordinated units into common units, our Sponsor will own     % of our common units.

We can borrow money to pay distributions, which would reduce the amount of credit available to operate our business.

Our Partnership Agreement allows us to make working capital borrowings to pay distributions. Accordingly, if we have available borrowing capacity, we can make distributions on all our units even though cash generated by our operations may not be sufficient to pay such distributions. Any working capital borrowings by us to make distributions will reduce the amount of working capital borrowings we can make for operating our business. For more information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Increases in interest rates may cause the market price of our common units to decline.

An increase in interest rates may cause a corresponding decline in demand for equity investments in general, and in particular for yield-based equity investments such as our common units. Any such increase in interest rates or reduction in demand for our common units resulting from other relatively more attractive investment opportunities may cause the trading price of our common units to decline.

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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, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for the common units. After this offering, there will be only publicly traded common units, assuming no exercise of the underwriters’ option. 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, the 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.

Unitholders may have liability to repay distributions.

Under some circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under the Marshall Islands Limited Partnership Act, or the Marshall Islands Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. The Marshall Islands Act provides that for a period of three years from the date of the impermissible distribution, members who received the distribution and who knew at the time of the distribution that it violated the Marshall Islands Act will be liable to the limited partnership for the distribution amount. Assignees who become substituted members are liable for the obligations of the assignor to make contributions to the company that are known to the assignee at the time it became members and for unknown obligations if the liabilities could be determined from the Partnership Agreement. Liabilities to members on account of their limited partnership and liabilities that are non-recourse to the company are not counted for purposes of determining whether a distribution is permitted.

We have no history operating as a separate publicly traded entity and will incur increased costs as a result of being a publicly traded limited partnership.

We have no history operating as a separate publicly traded entity. As a publicly traded limited partnership, we will be required to comply with the SEC’s reporting requirements and with corporate governance and related requirements of the Sarbanes-Oxley Act, the SEC and the securities exchange on which our common units will be listed. We will incur significant legal, accounting and other expenses in complying with these and other applicable regulations. We anticipate that our incremental general and administrative expenses as a publicly traded limited partnership be approximately $         million annually, and will include costs associated with annual reports to unitholders, tax return preparation, investor relations, registrar and transfer agent fees, audit fees, legal fees, incremental director and officer liability insurance costs and officer and director compensation.

We are an “emerging growth company” and we cannot be certain if the reduced disclosure requirements applicable to emerging growth companies will make our common units less attractive to investors.

We are an “emerging growth company,” as defined in the JOBS Act, and we may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not “emerging growth companies” as described under “Summary—Implications of Being an Emerging Growth Company.” We cannot predict if investors will find our common units less attractive because we may rely on these exemptions. If some investors find our common units less attractive as a result, there may be a less active trading market for our common units and our unit price may be more volatile.

In addition, under the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of the our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for so long as we are an emerging growth company. For as long as we take advantage of the reduced reporting obligations, the information that we provide unitholders may be different than information provided by other public companies.

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We have been organized as a limited partnership under the laws of the Republic of the Marshall Islands, which does not have a well-developed body of limited partnership law.

Our limited partnership affairs are governed by our Partnership Agreement and by the Marshall Islands Act. The provisions of the Marshall Islands Act resemble provisions of the limited partnership laws of a number of states in the United States, most notably Delaware. The Marshall Islands Act also provides that it is to be applied and construed to make it uniform with the Delaware Limited Partnership Act and, so long as it does not conflict with the Marshall Islands Act or decisions of the Marshall Islands courts, interpreted according to the non-statutory law (or case law) of the State of Delaware. There have been, however, few, if any, court cases in the Marshall Islands interpreting the Marshall Islands Act, in contrast to Delaware, which has a fairly well-developed body of case law interpreting its limited partnership statute. Accordingly, we cannot predict whether Marshall Islands courts would reach the same conclusions as the courts in Delaware. For example, the rights of our unitholders and the duties of our General Partner and our directors and officers under Marshall Islands law are not as clearly established as under judicial precedent in existence in Delaware. As a result, unitholders may have more difficulty in protecting their interests in the face of actions by our General Partner and our officers and directors than would unitholders of a similarly organized limited partnership in the United States.

Because the Public Company Accounting Oversight Board is not currently permitted to inspect our independent accounting firm, you may not get the benefit of such inspections

Auditors of U.S. public companies are required by law to undergo periodic Public Company Accounting Oversight Board, or PCAOB, inspections that assess their compliance with U.S. law and professional standards in connection with performance of audits of financial statements filed with the SEC. Certain European Union countries, including Greece, do not currently permit the PCAOB to conduct inspections of accounting firms established and operating in such European Countries, even if they are part of major international firms. Accordingly, unlike for most U.S. public companies, the PCAOB is prevented from evaluating our auditor’s performance of audits and its quality control procedures, and, unlike shareholders of most U.S. public companies, we and our unitholders are deprived of the possible benefits of such inspections.

Because we are organized under the laws of the Marshall Islands, it may be difficult to serve us with legal process or enforce judgments against us, our directors or our management.

We are organized under the laws of the Marshall Islands, and substantially all of our assets are located outside of the United States. In addition, our General Partner is a Marshall Islands limited liability company, and its directors and officers generally are or will be non-residents of the United States, and all or a substantial portion of the assets of these non-residents are located outside the United States. As a result, it may be difficult or impossible for you to bring an action against us or against these individuals in the United States if you believe that your rights have been infringed under securities laws or otherwise. Even if you are successful in bringing an action of this kind, the laws of the Marshall Islands and of other jurisdictions may prevent or restrict you from enforcing a judgment against our assets or the assets of our General Partner or our directors or officers. For more information regarding the relevant laws of the Marshall Islands, please read “Service of Process and Enforcement of Civil Liabilities.”

Tax Risks

In addition to the following risk factors, you should read “Business—Taxation of the Partnership,” “Material U.S. Federal Income Tax Considerations” and “Non-United States Tax Considerations” for a more complete discussion of the expected material U.S. federal and non-U.S. income tax considerations relating to us and the ownership and disposition of our common units.

We will be subject to taxes, which will reduce our cash available for distribution to you.

Some of our subsidiaries will be subject to tax in the jurisdictions in which they are organized or operate, reducing the amount of cash available for distribution. In computing our tax obligation in these jurisdictions, we

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are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing authorities. We cannot assure you that upon review of these positions the applicable authorities will agree with our positions. A successful challenge by a tax authority could result in additional tax imposed on our subsidiaries, further reducing the cash available for distribution. In addition, changes in our operations could result in additional tax being imposed on us, OPCO or our or its subsidiaries in jurisdictions in which operations are conducted. Please read “Business—Taxation of the Partnership.”

U.S. tax authorities could treat us as a “passive foreign investment company,” which would have adverse U.S. federal income tax consequences to U.S. unitholders.

A non-U.S. entity treated as a corporation for U.S. federal income tax purposes will be treated as a “passive foreign investment company,” or PFIC, for U.S. federal income tax purposes if at least 75% of its gross income for any taxable year consists of “passive income” or at least 50% of the average value of its assets produce, or are held for the production of, “passive income.” For purposes of these tests, “passive income” includes dividends, interest, gains from the sale or exchange of investment property, and rents and royalties other than rents and royalties that are received from unrelated parties in connection with the active conduct of a trade or business. For purposes of these tests, income derived from the performance of services does not constitute “passive income.” U.S. shareholders of a PFIC are subject to a disadvantageous U.S. federal income tax regime with respect to the income derived by the PFIC, the distributions they receive from the PFIC, and the gain, if any, they derive from the sale or other disposition of their interests in the PFIC.

Based on our current and projected method of operation we believe that we will not be a PFIC for our 2014 taxable year, and we expect that we will not be treated as a PFIC for any future taxable year. While we believe there is significant authority in support of our position, it should be noted that the conclusions in this area are not free from doubt and the U.S. Internal Revenue Service, or IRS, or a court could disagree with this opinion and our position. In addition, although we intend to conduct our affairs in a manner to avoid being classified as a PFIC with respect to each taxable year, we cannot assure you that the nature of our operations will not change in the future and that we will not become a PFIC in any taxable year. If the IRS were to find that we are or have been a PFIC for any taxable year (and regardless of whether we remain a PFIC for subsequent taxable years), our U.S. unitholders would face adverse U.S. federal income tax consequences. Please read “Material U.S. Federal Income Tax Considerations—U.S. Federal Income Taxation of U.S. Holders—PFIC Status and Significant Tax Consequences” for a more detailed discussion of the U.S. federal income tax consequences to U.S. unitholders if we are treated as a PFIC.

The ratio of dividend income to distributions on our common units is subject to business, economic and other uncertainties as well as tax reporting positions with which the IRS may disagree, which could result in a higher ratio of dividend income to distributions and adversely affect the value of our common units.

We estimate that approximately     % of the total cash distributions made to a purchaser of common units in this offering who owns those units from the date of this offering through             will constitute dividend income for U.S. tax purposes. The remaining portion of the distributions will be treated first as a nontaxable return of capital to the extent of the purchaser’s tax basis in its common units and thereafter as capital gain. These estimates are based on certain assumptions that are subject to business, economic, regulatory, competitive and political uncertainties beyond our control. In addition, these estimates are based on current U.S. federal income tax law and tax reporting positions that we will adopt and with which the IRS could disagree. As a result of these uncertainties, these estimates may be incorrect and the actual percentage of total cash distributions that will constitute dividend income could be higher, and any difference could adversely affect the value of the common units. Please read “Material U.S. Federal Income Tax Considerations—U.S. Federal Income Taxation of U.S. Holders—Ratio of Dividend Income to Distributions.”

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $         million from the sale of         common units offered by this prospectus, assuming an initial public offering price of $         per unit (which is the midpoint of the range set forth on the cover of this prospectus) and after deducting estimated underwriting discounts and commissions and paying estimated offering expenses. Of this amount, $         million will be paid to our Sponsor through DOV I as partial consideration for our interests in OPCO’s Initial Fleet.

We have granted the underwriters a 30-day option to purchase up to         additional common units. If the underwriters exercise their option to purchase additional common units, we will use the net proceeds of $         for general corporate purposes.

A $1.00 increase or decrease in the assumed initial public offering price of $         per common unit would cause the net proceeds from this offering, after deducting the estimated underwriting discount and commissions and offering expenses payable by us, to increase or decrease, respectively, by approximately $         million. In addition, we may also increase or decrease the number of common units we are offering. Each increase of 1.0 million common units offered by us, together with a concomitant $1.00 increase in the assumed public offering price to $         per common unit, would increase net proceeds to us from this offering by approximately $         million. Similarly, each decrease of 1.0 million common units offered by us, together with a concomitant $1.00 decrease in the assumed initial offering price to $         per common unit, would decrease the net proceeds to us from this offering by approximately $         million.

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CAPITALIZATION

The following table sets forth:

• our historical cash and capitalization as of December 31, 2013;

• our cash and capitalization on an as adjusted basis as of July 23, 2014 to give effect to: (i) the drawdown of the remaining $450.0 million under the Existing Senior Secured Loan Facility due to the delivery ofOcean Rig Athena; (ii) the increase in restricted cash amounting to $25.0 million due to the drawdown of the $450.0 million; (iii) scheduled loan repayments of $51.6 million under our senior secured credit facility after December 31, 2013; and (iv) the repayment of the Existing Senior Secured Loan Facility and our entry into the New Senior Secured Term Loan Facility; and*

• our cash and capitalization on an as further adjusted basis to give effect to the transactions described under Formation Transactions, including the completion of this offering, assuming no exercise of the underwriters’ over-allotment option.

There have been no significant adjustments to our capitalization since December 31, 2013, as so adjusted. The following table is derived from and should be read together with the historical Combined Carve-out Financial and the accompanying notes contained elsewhere in this prospectus. You should also read this table together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Use of Proceeds.”

	As of December 31, 2013
	Historical			As adjusted (1)(2)			As further adjusted
	(in thousands)
Cash and cash equivalents	$	6,083			451,458
Restricted Cash		50,000			0
Total Cash		56,083			451,458
Debt:
New Senior Secured Term Loan Facility					1,300,000
Existing Senior Secured Loan Facility		890,000
Deferred financing costs		(14,334	)		(14,625	)
		875,666			1,285,375
Total debt
Equity:
Stockholders equity		815,177			800,843
Partner’s Equity
Held by public:
Common units
Held by our Sponsor
Common units
Subordinated units
Equity attributable to Ocean Rig Partners LP
Non-controlling interest
Total capitalization	$	1,690,843		$	2,086,218

* On July 17, 2014, we priced the New Senior Secured Term Loan Facility and expect to close this transaction on July 25, 2014. The Existing Senior Secured Loan Facility will be repaid in full in connection with the closing of the New Senior Secured Term Loan Facility

(1) Excludes shipyard installment payments of $384.6 million relating to the delivery ofOcean Rig Athena.

(2) The cash position gives effect to $75.0 million of previously restricted cash becoming unrestricted cash as a result of the refinancing of existing senior secured credit facility with a New Senior Secured Term Loan Facility.

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DILUTION

Dilution is the amount by which the offering price will exceed the net tangible book value per common unit after this offering. Based on the initial public offering price of $         per common unit (the midpoint of the range set forth on the cover of this prospectus), on a pro forma basis as of             , after giving effect to this offering of common units, the application of the net proceeds in the manner described under “Use of Proceeds” and the formation and contribution transactions related to this offering, our pro forma net tangible book value would have been $         million, or $         per common unit. 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 common unit before this offering(1)	$
Increase in net tangible book value per common unit attributable to purchasers in this offering
Less: Pro forma net tangible book value per common unit after this offering(2)
Immediate dilution in net tangible book value per common unit to purchasers in this offering		$

(1) Determined by dividing the total number of units (             common units and             subordinated units, assuming no exercise of the underwriters’ option to purchase additional common units) to be issued to our General Partner and its affiliates for their contribution of assets and liabilities to us into the net tangible book value of the contributed assets and liabilities.

(2) Determined by dividing the total number of units (             common units and             subordinated units, assuming no exercise of the underwriters’ option to purchase additional common units) to be outstanding after this offering into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering.

(3) Each $1.00 increase or decrease in the assumed public offering price of $         per common unit would increase or decrease, respectively, our pro forma net tangible book value by approximately $         million, or approximately $         per common unit, and dilution per common unit to investors in this offering by approximately $         per common unit, after deducting the estimated underwriting discount and offering expenses payable by us. We may also increase or decrease the number of common units we are offering. An increase of 1.0 million common units offered by us, together with a concomitant $1.00 increase in the assumed offering price to $         per common unit, would result in a pro forma net tangible book value of approximately $         million, or $         per common unit, and dilution per common unit to investors in this offering would be $         per common unit. Similarly, a decrease of 1.0 million common units offered by us, together with a concomitant $1.00 decrease in the assumed public offering price to $         per common unit, would result in an pro forma net tangible book value of approximately $         million, or $         per common unit, and dilution per common unit to investors in this offering would be $         per common unit. The information discussed above is illustrative only and will be adjusted based on the actual public offering price and other terms of this offering determined at pricing.

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy and restrictions on distributions in conjunction with specific assumptions included in this section. 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.

Our wholly owned subsidiary, OPCO GP LLC, the general partner of OPCO, will manage OPCO’s operations and activities. We will have the authority to appoint and elect the directors of OPCO GP LLC, who in turn will appoint the officers of OPCO GP LLC. Certain of the directors and officers of our General Partner and those of our Sponsor will also serve as directors or executive officers of OPCO GP LLC. The partnership agreement of OPCO will provide that certain actions relating to OPCO must be approved by the board of directors of our General Partner. These actions will include, among other things, establishing maintenance and replacement capital and other cash reserves and the determination of the amount of quarterly distributions by Ocean Rig Operating LP to its partners, including us. Please read “Certain Relationships and Related Party Transactions—OPCO Operating Agreements.”

General

Rationale for Our Cash Distribution Policy

Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing our available cash (after deducting expenses, including estimated maintenance and replacement capital expenditures and reserves) rather than retaining it. We will generally finance any expansion capital expenditures from external financing sources, including borrowings from commercial banks and the issuance of equity and debt securities. Our cash distribution policy is consistent with the terms of our partnership agreement, which requires that we distribute all of our available cash quarterly (after deducting expenses, including estimated maintenance and replacement capital expenditures and reserves).

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 is subject to certain restrictions and may be changed at any time. Set forth below are certain factors that influence our cash distribution policy:

• Our unitholders have no contractual or other legal right to receive distributions other than the obligation under our partnership agreement to distribute available cash on a quarterly basis, which is subject to the broad discretion of the board of directors of our General Partner to establish reserves and other limitations.

• The board of directors of our General Partner has authority to establish reserves for the prudent conduct of OPCO’s business (subject to approval of its board of directors). The establishment of these reserves could result in a reduction in cash distributions to you from levels we currently anticipate pursuant to our stated cash distribution policy.

As OPCO’s Initial Fleet and our other assets expand, our General Partner will evaluate future increases to the minimum quarterly distribution based on our cash flow and liquidity position. Our policy is to make cash distributions to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our General Partner and its affiliates. The board of directors of our General Partner will determine the timing and amount of all cash distributions, based on various factors, including our financial performance, cash requirements and contractual and legal restrictions. Accordingly, we cannot guarantee that we will be able to make cash distributions. See “Risk Factors.”

• Our ability to make cash distributions will be limited by restrictions on distributions under OPCO’s, including its subsidiaries’, financing agreements (and our other financing agreements, if any). OPCO’s

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financing agreement contains material financial tests and covenants that must be satisfied in order to pay distributions. If OPCO or us (as applicable) is unable to satisfy the restrictions included in any of its financing agreements or is otherwise in default under any such agreement, it could have a material adverse effect on OPCO’s ability to make cash distributions to us and our ability to make cash distributions to you, notwithstanding our stated cash distribution policy. These financial tests and covenants are described in this prospectus in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Borrowing Activities.”

• OPCO will be required to make substantial capital expenditures to maintain and replace its fleet. These expenditures may fluctuate significantly over time, particularly as drillships near the end of their useful lives. In order to minimize these fluctuations, we are required to deduct estimated, as opposed to actual, maintenance and replacement capital expenditures from the amount of cash that we would otherwise have available for distribution to our unitholders. In years when estimated maintenance and replacement capital expenditures are higher than actual maintenance and replacement capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance and replacement capital expenditures were deducted.

• Although our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including provisions requiring us to make cash distributions, may be amended. During the subordination period, with certain exceptions, our Partnership Agreement may not be amended without the approval of a majority of the units held by non-affiliated common unitholders. After the subordination period has ended, our Partnership Agreement can be amended with the approval of a majority of the outstanding common units, including those held by our Sponsor. At the closing of this offering, our Sponsor will own approximately     % of our common units and all of our subordinated units. Please read “The Partnership Agreement—Amendment of the Partnership Agreement.”

• 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 the board of directors of our General Partner, taking into consideration the terms of our Partnership Agreement.

• Under Section 51 of the Marshall Islands Act, we may not make a distribution to you 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, among other things, changes in our business, including decreases in total operating revenues, decreases in dayrates, the loss of a drillship, increases in operating or general and administrative expenses, principal and interest payments on outstanding debt, taxes, working capital requirements, maintenance and replacement capital expenditures or anticipated cash needs. Please read “Risk Factors” for a discussion of these factors.

Our ability to make distributions to our unitholders depends on the performance of our controlled affiliates, including OPCO, and their ability to distribute cash to us. Upon the closing of this offering, our interest in OPCO will be our only cash-generating asset. The ability of our controlled affiliates, including OPCO, to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable limited partnership and limited liability company laws and other laws and regulations.

Our Ability to Grow Depends on Our and OPCO’s Ability to Access External Capital

Because we, DOV II and OPCO expect to distribute the majority of our respective available cash, our growth may not be as fast as businesses that reinvest their available cash to expand ongoing operations. We expect that we, DOV II and OPCO will rely upon external financing sources, including commercial borrowings and the issuance of debt and equity securities, to fund acquisitions and capital expenditures. As a result, to the extent we, DOV II or OPCO are unable to finance growth externally, the cash distribution policy will significantly impair our, DOV II’s and OPCO’s ability to grow. To the extent we issue additional units in connection with any acquisitions or 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

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may affect the available cash that we have to distribute on each unit. 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 additional borrowings or other debt by DOV II, OPCO or us to finance growth would result in increased interest expense, which in turn may affect the available cash that OPCO has to distribute to us and that we have to distribute to our unitholders.

Initial Distribution Rate

Upon completion of this offering, the board of directors of our General Partner will adopt a policy pursuant to which we will declare an initial quarterly distribution of $         per unit for each complete quarter, or $         per unit on an annualized basis, to be paid no later than             days after the end of each fiscal quarter (beginning with the quarter ending             ). This equates to an aggregate cash distribution of $         million per quarter, or $         million per year, in each case based on the number of common units and subordinated units outstanding immediately after completion of this offering. Our ability to make cash distributions at the initial distribution rate pursuant to this policy will be subject to the factors described above under “—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.”

The table below sets forth the number of common units and subordinated units that will be outstanding 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 initial distribution rate of $         per unit per quarter ($         per unit on an annualized basis).

		Distributions
	Number of Units	One Quarter(1)	Four Quarters
Common units		$	$
Subordinated units
Total		$	$

(1) Actual payments of distributions on the common units and subordinated units are expected to be approximately $         million for the period between the estimated closing date of this offering and the end of the fiscal quarter in which the closing date of this offering occurs.

During the subordination period, before we make any quarterly distributions to subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution plus any arrearages in distributions from prior quarters. Please read “How We Make Cash Distributions—Subordination Period.” We cannot guarantee, however, that we will pay the minimum quarterly distribution or any amount on the common units in any quarter.

Forecasted Results of Operations for the Twelve Months Ending June 30, 2015

In this section, we present in detail the basis for our belief that we will be able to pay our minimum quarterly distribution on all of our outstanding units for the twelve months ending June 30, 2015. We present two tables, consisting of:

• Forecasted Results of Operations for the twelve months ending June 30, 2015, and

• Forecasted Cash Available for Distribution for the twelve months ending September 30, 2015 as well as the significant assumptions upon which the forecast is based.

We present below a forecast of the expected results of operations for Ocean Rig Partners LP for the twelve months ending June 30, 2015. Our forecast presents, to the best of our knowledge and belief, the expected results of operations for Ocean Rig Partners LP for the forecast period.

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Our 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 June 30, 2015. Our forecast is based on assumptions that we believe to be reasonable with respect to the forecast period as a whole. The assumptions and estimates used in the forecast are inherently uncertain and represent those that we believe are significant to our financial forecast. We believe that we have a reasonable objective basis for those assumptions. To the extent that there is a shortfall during any quarter in the forecast period, we believe we would be able to make working capital borrowings to pay distributions in such quarter and would be able to repay such borrowings in a subsequent quarter, because we believe the total cash available for distribution for the forecast period will be more than sufficient to pay the aggregate minimum quarterly distribution to all unitholders. 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 the actual results and those differences could be material. Our operations and those of DOV II and OPCO are subject to numerous risks that are beyond our control. If the forecast is not achieved, we may not be able to pay cash distributions on our units at the initial distribution rate stated in our cash distribution policy or at all.

Our forecasted results of operations is a forward-looking statement and should be read together with the historical Combined Carve-out Financial Statements and Balance Sheets of our predecessor and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

The amount of cash needed to pay the minimum quarterly distribution on all of our units to be outstanding immediately after completion of this offering is $         million per quarter or $         million per year. During the year ended December 31, 2013, we would have cash available for distribution of $         million, which would not have been sufficient to pay the minimum quarterly distribution on all of our common units and subordinated units. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Items You Should Consider When Evaluating Our Historical Financial Performance and Assessing Our Future Prospects.”

We do not, as a matter of course, make public projections as to future revenues, earnings or other results. The forecast has been prepared by and is the responsibility of our management. However, our management has prepared the financial forecast set forth below in support of our belief that we will have sufficient cash available to allow us to pay the minimum quarterly distribution on all of our outstanding units during the forecast period. The financial forecast has been prepared in accordance with the guidelines established by the American Institute of Certified Public Accountants. In addition, in the view of our management, the accompanying financial forecast 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 of Ocean Rig Partners LP. However this information is not fact and should not be relied on as being necessarily indicative of future results and readers of this prospectus are cautioned not to place undue reliance on this forecast.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements included under the heading “Risk Factors” elsewhere in this prospectus. Any of the risks discussed in this prospectus or unanticipated events could cause our actual results of operations, cash flows and financial condition to vary from the financial forecast and these variations may be material. The information in this forecast is not fact and should not be relied upon as being necessarily indicative of future results, and prospective investors are cautioned to not place undue reliance on the financial forecast and should make their own independent assessment of our future results of operations, cash flows and financial condition.

We are providing the financial forecast to supplement the historical Combined Carve-out Financial Statements of our predecessor in support of our belief that we will have sufficient cash available to allow us to pay cash distributions on all of our units for each quarter in the twelve-month period ending June 30, 2015 at our stated initial distribution rate. Please read “—Forecast Assumptions and Considerations—Summary of

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Significant Forecast Assumptions” for further information as to the assumptions we have made for the financial forecast. Unanticipated events may occur which could adversely affect actual results we achieve during the forecast period. Consequently,OPCO’s and our actual results of operations, cash flows, and financial condition during the forecast period may vary from the forecast and such variations may be material. Prospective investors are cautioned to not place undue reliance on the forecast and should make their own independent assessment of our future results of operations, cash flows and financial conditions.

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 the financial forecast to reflect events or circumstances after the date of this prospectus, even in the event that any or all of the underlying assumptions are shown to be in error. Therefore, we caution you not to place undue reliance on this information.

Neither our independent registered public accounting firm, nor any other independent registered public accounting firm, have compiled, examined or performed any procedures with respect to the forecasted results of operations contained herein, nor have they expressed any opinion or given any other form of assurance on such information or its achievability, and they assume no responsibility for such forecasted financial information. Our independent registered accounting firm’s report included in this prospectus relates to the Combined Carve-out Financial Information of our predecessor. That report does not extend to the tables and the related forecasted financial information contained in this section and should not be read to do so.

OCEAN RIG PARTNERS LP

FORECASTED RESULTS OF OPERATIONS

The following table presents (1) forecasted results of operations for Ocean Rig Partners LP for the twelve months ending June 30, 2015 and (2) historical results of operations for the year ended December 31, 2013. Net income attributable to non-controlling interest, net income attributable to Ocean Rig Partners LP partners and net income per unit are not extracted from the audited historical Combined Carve-out Financial Statements of our predecessor and the notes thereto for the year ended December 31, 2013.

	Forecast	Historical
	Ocean Rig Partners LP	Ocean Rig Partners LP Predecessor
	Twelve Months Ending June 30, 2015	Year Ended December 31, 2013
(in millions, except per unit data)	(unaudited)	(unaudited)
Revenues:
Service revenue, net			37,325
Total Revenue			37,325
Expenses:
Drillships operating expenses			13,576
Depreciation			11,740
General and administrative expenses			25,827
Operating loss			(13,818	)
Other income / (expenses):
Interest and finance costs			(21,022	)
Interest income			90
Gain on interest rate swaps			8,510
Other, net			613
Total other expenses, net			(11,809	)

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	Forecast	Historical
	Ocean Rig Partners LP	Ocean Rig Partners LP Predecessor
	Twelve Months Ending June 30, 2015	Year Ended December 31, 2013
(in millions, except per unit data)	(unaudited)	(unaudited)
Income (Loss) before income taxes and non-controlling interest
Income taxes			—
Net income (loss)			(25,627	)
	(forecasted)	(estimated)
Net income attributable to non-controlling interest(2)(3)
Net income attributable to Ocean Rig Partners LP partners(3)
Net income per:
Common unit (basic and diluted)(3)
Subordinated unit (basic and diluted)(3)

(1) Forecasted amount includes estimated incremental public company expenses of $         million.

(2) Non-controlling interest for the historical periods presented in the table above have been calculated as if the intended capital structure was in place at December 31, 2013. Please also see the audited historical Combined Carve-out Financial Statements of our predecessor and the notes thereto for the year ended December 31, 2013. Net income attributable to non-controlling interest has been estimated based on a number of assumptions. The main assumption is related to the allocation of loss on derivatives, where the allocation has been based on average outstanding debt in the periods presented. Net income attributable to non-controlling interest includes:

	Forecast	Estimated
	Ocean Rig Partners LP	Our Predecessor
	Twelve Months Ending June 30, 2015	Year Ended December 31, 2013
(in millions)	(forecasted)	(estimated)
Net income attributable to non-controlling interest in Ocean Rig Operating LP
Total net income attributable to non-controlling interest	$	$

(3) Net income attributable to non-controlling interest, net income attributable to Ocean Rig Partners LP partners and net income per unit are not extracted from the audited historical Combined Carve-out Financial Statements of our predecessor and the notes thereto for the year ended December 31, 2013.

Please read the accompanying summary of significant accounting policies and forecast assumptions.

The financial information presented in the table above contains forecasted and estimated financial information. Our estimated financial position, results of operations and cash flows could differ from those that would have resulted if we had operated autonomously or as an entity independent of our Sponsor in the periods for which historical financial data is presented above, and such data may not be indicative of our future operating results, cash flows or financial performance.

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Forecast Assumptions and Considerations

Basis of Presentation

The accompanying financial forecast and related notes of Ocean Rig Partners LP present the forecasted results of operations of Ocean Rig Partners LP for the twelve months ending June 30, 2015, based on the assumptions set forth in the section titled—Formation Transactions.”

Summary of Significant Accounting Policies

Organization. We are a Marshall Islands limited partnership formed on April 16, 2014 to acquire, own and operate offshore drilling units, including without limitation, through our ownership of OPCO’s Initial Fleet Additional Fleet Interests, Four Year Drillships and Optional Drillship Interests.

Principles of Combination. This financial forecast includes our accounts and those of the wholly and partially owned subsidiaries we control, including OPCO. All intercompany transactions have been eliminated in consolidation.

Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reporting Currency. The U.S. Dollar is our functional and reporting currency because the majority of our revenues and expenses are denominated in U.S. Dollars. A portion of our revenues and expenses are denominated in Brazilian Reals and in Angolan kwanza. Transactions involving other currencies during a period are converted into U.S. Dollars using the exchange rates in effect on the date of the transactions. Foreign currency assets and liabilities are translated using rates of exchange at the balance sheet date. Resulting gains or losses are reflected in our combined statements of income.

Service Revenue, net. A substantial majority of our revenues are derived from OPCO’s dayrate-based drilling contracts (which may include lump sum fees for mobilization and demobilization). Both dayrate based revenues and lump sum fee revenues are recognized ratably over the original contract term when services are rendered, excluding any extension option periods. Under some contracts, OPCO is entitled to additional payments for meeting or exceeding certain performance targets. Such additional payments are recognized when any uncertainties regarding such performance targets are resolved or upon completion of the drilling program, as applicable. Revenues are recorded net of related party and third party agent commissions.

In connection with its drilling contracts, OPCO may receive lump sum fees for the mobilization of equipment and personnel or for capital additions and upgrades prior to commencement of drilling services. These up-front fees are recognized as revenue over the original contract term, excluding any extension option periods.

In some cases, OPCO may receive lump sum non-contingent fees or dayrate-based fees from customers for demobilization upon completion of a drilling contract. Non-contingent demobilization fees are recognized as revenue over the original contract term, excluding any extension option periods. Contingent demobilization fees are recognized as earned upon completion of the drilling contract.

Fees received from customers under drilling contracts for capital upgrades are deferred and recognized over the original contract term, excluding any extension option periods.

Mobilization and Demobilization Expenses. Mobilization costs incurred as part of a contract are capitalized and recognized as expense over the original contract term, excluding any extension option periods. The costs of relocating drillships that are not under contract are expensed as incurred. Demobilization costs are costs related to the transfer of a drillship to a safe harbor or different geographic area and are expensed as incurred.

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Drillships Operating Expenses. Drillships operating expenses are costs associated with operating a drillship that is either in operation or stacked, and include the remuneration of offshore crews and related costs, drillship supplies, insurance costs, expenses for repairs and maintenance as well as costs related to onshore personnel in various locations where we operate the drillship and are expensed as incurred. In addition, mobilization costs incurred as part of a contract are capitalized and recognized as an expense over the original contract term, excluding any extension option periods. The costs of relocating drillships that are not under contract are expensed as incurred. Demobilization costs are costs related to the transfer of a drillship to a safe harbor or different geographic area and are expensed as incurred.

Accounting for Dry-docking and Special Survey Costs. Dry-docking and special survey costs are expensed in the period incurred. The drillships undergo dry-dock or special survey approximately every five years during the first fifteen years of their life and every two and a half years during their remaining useful life. Costs relating to routine repairs and maintenance are also expensed as incurred. All three drillships in OPCO’s Initial Fleet are scheduled to complete their initial special survey in 2018 or 2019.

Depreciation and Amortization. Depreciation and amortization costs are based on the historical cost of the drillships and other equipment. We depreciate our drilling units on a straight-line basis over their estimated useful lives. Specifically, we depreciate bare-decks over 30 years and other asset parts and equipment over 5 to 15 years. We expense the costs associated with a five-year periodic class work.

Significant investments are capitalized and depreciated in accordance with the nature of the investment. Significant investments that are deemed to increase a drilling unit’s value for its remaining economic useful life are capitalized and depreciated over the remaining economic useful life of the drillship.

Cash and Cash Equivalents. Cash and cash equivalents consist of cash, bank deposits and highly liquid financial instruments with original maturities of three months or less.

Deferred Charges. Deferred charges, including debt arrangement fees and legal expenses, are capitalized and amortized over the term of the related loan and are included in interest expense.

Income Taxes. OPCO’s subsidiaries operate in jurisdictions where taxes are imposed on income and on revenues and thus, income taxes have been recorded in these jurisdictions when appropriate. As tax law is based on interpretations and applications of the law, which are only ultimately decided by the courts of the particular jurisdictions, significant judgment is involved in determining our provision for income taxes in the ordinary course of our business. We recognize tax liabilities based on our assessment of whether our tax positions are more likely than not sustainable, based on the technical merits of each position and having regard to the relevant taxing authority’s widely understood administrative practices and precedent.

Net Income Per Unit. The calculation of the forecasted basic and diluted earnings for the twelve months ending June 30, 2015 is set forth below:

($ in thousands)	Common Unitholders	Subordinated Unitholders
Partners interests in forecasted net income	$	$
Forecasted weighted average number of units outstanding	$	$
Forecasted net income per unit	$	$

Summary of Significant Forecast Assumptions

Service Revenue, net. Our forecast of service revenues is based on estimated dayrates under each drillship’s charter agreement multiplied by the estimated economic utilization rate and the total number of days on the contract during the twelve months ending June 30, 2015. Forecasted contract revenues assume that all of OPCO’s drillships are operational throughout the twelve months ending June 30, 2015.

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In arriving at economic utilization, we have taken into account certain contractual elements that generally exist in our drilling contracts. For example, drilling contracts generally provide for a general repair allowance for preventive maintenance or repair of equipment, which could range from 18 to         hours per month. Such allowance varies from contract to contract, and OPCO may be compensated at the full operating dayrate or at a reduced operating dayrate for such general repair allowance. In addition, drilling contracts typically provide for situations where the drillships would operate at reduced operating dayrates, such as, among other things: a standby rate, where the drillship is prevented from commencing operations for reasons such as bad weather, waiting for customer orders, waiting on other contractors; a moving rate, where the drillship is in transit between locations; a reduced performance rate in the event of major equipment failure; or a force majeure rate in the event of a force majeure that causes the suspension of operations. In addition, in limited circumstances, the drillship could operate at a zero rate due to a shutdown of operations for repairs where the general repair allowance has been exhausted or for any period of force majeure in excess of a specific number of days allowed under a drilling contract.

The assumed economic utilization rate of     % for each drillship is based on our Sponsor’s past experience with similar drillships and is consistent with the historical drillship utilization rate for certain of our Sponsor’s other drillships (the Ocean Rig Corcovado, theOcean Rig Poseidon, theOcean Rig Olympia and theOcean Rig Mykonos) for the year ended December 31, 2013 which was     %.

In all of our drilling contracts we are entitled to escalation in dayrates to compensate us for future cost increases as reflected in publicly available cost indices. We have estimated the escalation of the dayrate for OPCO’s drillships based on either the contractually predetermined escalation percentage or the current cost indices and incorporated all of the known or estimated contractual rate escalations that are expected to occur during the twelve months ending June 30, 2015.

In addition to recurring contracted dayrates, OPCO may also receive mobilization and demobilization fees for drillships before and after their drilling assignments, and may also receive reimbursement of costs incurred by us at the customer’s request for additional supplies, personnel and other services not covered by the contracted dayrate.

For the purpose of this forecast, we have included the current amortization schedule of mobilization fees for our three drillships under their initial contracts. We have not included any demobilization fees in the forecast as no drillships are expected earn demobilization fees during this period.

Our forecast assumes estimated reimbursable revenues of $         million during the twelve months ending September 30, 2015. The assumed reimbursable revenues consist primarily of estimated fuel costs relating to one of the drillships in transit between locations, plus the estimated handling fees.

Finally, we have included a total of $         million in agent commissions during the twelve-month period ending June 30, 2015 which is based on commissions of 1.0% paid to Cardiff Drilling as well as weighted average commissions of     % paid to third parties under the time charters for the drillships in OPCO’s Initial Fleet.

The following table summarizes OPCO’s assumed average dayrates and economic utilization for the twelve months ending June 30, 2015:

Drillships	Year Built(1)		Ownership(2)			Customer	Country of Operations	Expiration Date		Economic Utilization
Ocean Rig Mylos(3)		2013		100	%	Repsol	Brazil		Q4 2016		%
Ocean Rig Athena(4)		2014		100	%	ConocoPhillips	Angola		Q2 2017		%
Ocean Rig Skyros(5)		2013		100	%	Total	Angola		Q4 2014		%

(1) TheOcean Rig Mylos and theOcean Rig Skyros commenced operations in third quarter 2013 and first quarter 2014, respectively. TheOcean Rig Athena commenced operations in the second quarter of 2014.

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(2) The ownership percentage represents the ownership of each drillships by OPCO. Following the completion of this offering we will own     % of the outstanding limited partner interest of OPCO.

(3) The dayrate includes estimated non-cash amortized revenue of $         per day relating to lump sum mobilization fee received prior to commencement of contract. The dayrate also includes an annual contract revenue adjustment that is projected to incur during the twelve months ending June 30, 2015.

(4) The dayrate includes estimated non-cash amortized revenue of $         per day relating to lump sum mobilization fee received prior to commencement of contract. The dayrate also includes an annual contract revenue adjustment that is projected to incur during the twelve months ending June 30, 2015.

(5) The dayrate includes estimated non-cash amortized revenue of $         per day relating to lump sum mobilization fee received prior to commencement of contract. The dayrate also includes an annual contract revenue adjustment that is projected to incur during the twelve months ending June 30, 2015.

Drillship Operating Expenses. Forecasted drillship operating expenses and that average daily operating expenses will be $ per vessel. The forecast takes into account increases in crewing and other labor related costs driven predominantly by an increase in demand for qualified and experienced officers and crew.

Our forecast also takes into account the cost level of operating in each of Brazil and Angola, where OPCO’s drillships are expected to be located during the twelve months ending June 30, 2015.

Our forecast assumes estimated reimbursable expenses of $         million during the twelve months ending September 30, 2015. The assumed reimbursable revenues consist primarily of estimated fuel costs relating to one of the drillships in transit between locations, plus the estimated handling fees.

Dry-docking and Special Survey Costs. We do not expect to incur any dry-docking and special survey costs for the twelve months ending June 30, 2015.

General and Administrative Expenses. Forecasted general and administrative expenses for the twelve months ending June 30, 2015 are based on the following assumptions:

• OPCO will incur approximately $         million of costs and fees, based on a daily fee of $         per drillship, pursuant to the management and administrative services agreements that we will enter into with our Sponsor and its affiliates. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Management and Administrative Services Agreements;”

• OPCO will incur approximately $         million of costs and fees, based on a daily fee of $         per drillship, pursuant to the advisory, technical and administrative services agreement that OPCO’s subsidiaries will enter into with certain affiliates of our Sponsor. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Advisory, Technical and Administrative Services Agreement;” and

• OPCO will incur approximately $         million in incremental expenses as a result of being a publicly traded limited partnership. These expenses will include costs associated with annual reports to unitholders, tax return preparation, investor relations, registrar and transfer agent fees, audit fees, legal fees, incremental director and officer liability insurance costs and director compensation.

Depreciation and Amortization. Forecasted depreciation and amortization expense assumes that no drilling units are purchased or sold during the twelve months ending June 30, 2015. We have accounted for depreciation and amortization expense in a manner consistent with the historical presentation in the Combined Consolidated

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Carve-out Financial Statement of our predecessor. Drilling units and equipment are recorded at historical cost less accumulated depreciation. The cost of drillships and equipment less the estimated residual value is depreciated on a straight-line basis over the assets’ remaining economic useful lives, which we estimate at the start of 2014 to be approximately 30 years for each of theOcean Rig Mylos, theOcean Rig Skyros, and theOcean Rig Athena.

Interest Income. We have assumed that any cash surplus balances will not earn any interest during the twelve months ending June 30, 2015.

Interest Expense. Our forecast for the twelve months ending June 30, 2015 assumes we will have an average outstanding loan balance of approximately $1.3 billion under the New Senior Secured Term Loan Facility, with an estimated weighted average interest rate of approximately     % per annum. We have assumed that interest rates are constant during the forecast period. The rates we have assumed are based on a LIBOR floor of 1% plus the applicable 4.5% margin under the New Senior Secured Term Loan Facility. The loan must be repaid in quarterly installments over a term of seven years, with a balloon payment upon maturity. Upon the closing of this offering the New Senior Secured Term Loan Facility will be assumed by DOV II and our Sponsor’s guarantee of such facility will be unconditionally released.

Derivative Financial Instruments and Hedging Activities. We have assumed that OPCO will enter into 4-year interest rate swap agreements to hedge its exposure to floating interest rates. We assume OPCO will not use hedge accounting for these interest-rate swap agreements and will record them at fair value. Changes in the fair value of interest-rate swap agreements will be recorded as a gain or loss as a separate line item within Financial Items. For the purpose of the forecast, we assumed there will be no change in the long-term interest rates that would result in a variation in the mark-to-market valuation of interest rate swaps. The market valuation adjustments for the interest swap instrument may have a significant impact on OPCO s results of operations and financial position.

Foreign Exchange Gain and Loss. Foreign exchange gains or losses arise primarily due to the translation of cash balances that are denominated in Euros and         accounts receivables denominated in Euros. For the purpose of our forecast, we have assumed that the exchange rate between the U.S. Dollar and the Euros and         will not fluctuate and, as a result, we have assumed that there is no foreign exchange rate gain or loss at translation.

Our and OPCO’s functional currency is the U.S. Dollar as the vast majority of our and OPCO’s revenues are received in U.S. Dollars and a majority of our expenditures are made in U.S. Dollars. Our reporting currency is also in U.S. Dollars.

As a result of our international operations, we are exposed to fluctuations in foreign exchange rates due to revenues being received and operating expenses paid in currencies other than U.S. Dollars. Accordingly we may experience currency exchange losses if we have not fully hedged our exposure to a foreign currency, or if revenues are received in currencies that are not readily convertible. We may also be unable to collect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange or controls over the repatriation of income or capital. See “Risk Factors—Risks Inherent in Our Business—Fluctuations in exchange rates or exchange controls could result in losses to us.”

Taxes.Forecasted income tax expense is based on the tax laws and applicable rates in the countries where operations are conducted and income is earned. The forecasted tax expense for the twelve months ending June 30, 2015 is primarily comprised of expected Brazilian tax on the Brazilian operations of theOcean Rig Mylos and expected Angolan tax on the Angola operations of theOcean Rig Skyros and theOcean Rig Athena. We have assumed that during the forecast period the drillships will remain in the same country of operations throughout the twelve months ending June 30, 2015.

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Maintenance and Replacement Capital Expenditures. OPCO’s Operating Agreement will require our General Partner to deduct from operating surplus each quarter estimated maintenance and replacement capital expenditures, as opposed to actual maintenance and replacement capital expenditures, in order to reduce disparities in operating surplus caused by fluctuating maintenance and replacement capital expenditures, such as long term maintenance (including special classification surveys) and drillship replacement. The actual cost of replacing the drillships in OPCO’s fleet will depend on a number of factors, including prevailing market conditions and the availability and cost of financing at the time of replacement. The board of directors of our General Partner, with the approval of the conflicts committee, may determine that one or more of our assumptions should be revised, which could cause our General Partner to increase the amount of estimated maintenance and replacement capital expenditures. We may elect to finance some or all of maintenance and replacement capital expenditures through the issuance of additional common units which could be dilutive to our existing unitholders. Please read “Risk Factors—Risks Inherent in Our Business—OPCO must make substantial capital and operating expenditures to maintain the operating capacity of its fleet, which will reduce cash available for distribution. In addition, each quarter we are required to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted.”

Maintenance Capital Expenditures. Because of the substantial capital expenditures OPCO is required to make to maintain its fleet, OPCO’s initial annual estimated maintenance costs for the three drillships in OPCO’s Initial Fleet for purposes of calculating operating surplus will be $         million per year on total expected dry-docking and special survey costs of approximately $         million incurred every five years for the three drillships in OPCO’s Initial fleet. In calculating these maintenance costs we include the projected dry-docking and special survey costs for each drillship and we also take into account the anticipated loss of revenues while our drillships are out of service during these surveys.

Replacement Capital Expenditures. OPCO’s initial annual estimated replacement capital expenditures will be $         million per year, including financing costs, for replacing drillships at the end of their useful lives. The annual estimated $         million for future drillship replacement is based on assumptions regarding the remaining useful lives of the drillships, a net investment rate, drillship replacement values based on current market conditions and residual value of the drillships.

Regulatory, Industry and Economic Factors. Our forecast for the twelve months ending June 30, 2015 is based on the following assumptions related to regulatory, industry and economic factors:

• no material nonperformance or credit-related defaults by suppliers, customers or vendors;

• no new regulation or any interpretation of existing regulations or governmental action that, in either case, would be materially adverse to our business;

• no material accidents, environmental incidents, releases, weather-related incidents, unscheduled downtime or similar unanticipated events;

• no major adverse change in the markets in which we operate resulting from oil production disruptions, reduced demand for oil or significant changes in the market prices of oil; and

• no material changes to market, regulatory and overall economic conditions or in prevailing interest rates.

Cash Available for Distribution

The table below sets forth our calculation of (1) forecasted cash available for distribution to our unitholders for the twelve months ending June 30, 2015 based on the Forecasted Results of Operations set forth above and (2) our predecessor cash available for distribution for the year ended December 31, 2013. Based on the financial forecast and related assumptions, we forecast that our cash available for distribution generated during the twelve months ending June 30, 2015 will be approximately $         million. This amount would be sufficient to pay the

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minimum quarterly distribution of $         per unit on all of our common units and subordinated units for the four quarters ending June 30, 2015 in accordance with our cash distribution policy. Please see “—General” above and “How We Make Cash Distributions.”

Actual payments of distributions on the common units and subordinated units are expected to be $         million for the period between the estimated closing date of this offering (                 , 2014) and the last day of the quarter in which the closing date of this offering occurs.

You should read “—Forecast Assumptions and Considerations—Summary of Significant Forecast Assumptions” included as part of the financial forecast for a discussion of the material assumptions underlying our forecast of adjusted EBITDA that is included in the table below. Our forecast is based on those material assumptions and reflects our judgment of conditions we expect to exist and the course of action we expect to take. The assumptions disclosed in our financial forecast are those that we believe are significant to generate the forecasted adjusted EBITDA. If our estimate is not achieved, we may not be able to pay distributions on the common units at the initial distribution rate of $         per unit per quarter ($         per unit on an annualized basis). Our financial forecast and the forecast of cash available for distribution set forth below have been prepared by our management. This calculation represents available cash from operating surplus generated during the period and excludes any cash from working capital borrowings, capital expenditures and cash on hand on the closing date.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance calculated in accordance with U.S. GAAP.

When considering our forecast of cash available for distribution for the twelve months ending June 30, 2015, you should keep in mind the risk factors and other cautionary statements under the heading “Forward-Looking Statements” and “Risk Factors” included elsewhere in this prospectus. Any of these factors or the other risks discussed in this prospectus could cause our financial results of operations to vary significantly from those set forth in the financial forecast and the forecast of cash available for distribution set forth below.

Neither our independent registered public accounting firm, nor any other independent registered public accounting firm have compiled, examined or performed any procedures with respect to the forecasted financial information contained herein, nor have they expressed any opinion or given any other form of assurance on such information or its achievability, and they assume no responsibility for such forecasted financial information. Our independent registered accounting firm’s report included in this prospectus relates to the Combined Consolidated Carve-out Financial Statements of our predecessor. That report does not extend to the tables and the related financial forecast information contained in this section and should not be read to do so.

The non-controlling interest in the table below is comprised of Ocean Rig’s     % limited partner interest of OPCO, through OPCO Holdings, which owns 100% of the interests in the entities that will own and operate theOcean Rig Mylos, theOcean Rig Athena and theOcean Rig Skyros upon the closing of this offering. Non-controlling interest for the historical periods presented in the table below have been calculated as if the non-controlling interests described herein were in place at December 31, 2013.

The financial information presented in the table below contains forecasted and estimated financial information. Our estimated financial position, results of operations and cash flows could differ from those that would have resulted if we had operated autonomously or as an entity independent of our Sponsor in the periods for which historical financial data is presented below, and such data may not be indicative of our future operating results, cash flows or financial performance.

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OCEAN RIG PARTNERS LP FORECASTED CASH AVAILABLE FOR DISTRIBUTION

	Forecast(1)		Historical
	Ocean Rig Partners LP		Our Predecessor
	Twelve Months Ending June 30, 2015		Year Ended December 31, 2013
(in millions, except per unit amounts)	(forecasted)		(unaudited)
Adjusted EBITDA(2)				2,490
Adjustments for cash items and estimated maintenance and replacement capital expenditures:
Cash interest expense				(4,282	)
Non-cash Amortization of deferred mobilization revenue				(6,376	)
Non-cash Amortization of deferred mobilization expenses				2,127
Cash income tax expense
Maintenance capital expenditure reserves(3)
Replacement capital expenditure reserves(3)
Cash available for distribution before non-controlling interest				(6,041	)
	(forecasted)		(estimated)
Less: Cash flow attributable to non-controlling interest(4)
Cash available for distribution	$		$
Expected distributions:
Distributions per unit	$		$
Distributions to our public common unitholders(5)
Distributions to our Sponsor—common units(5)
Distributions to our Sponsor—subordinated units(5)
Total distributions(6)	$		$
Excess (shortfall)	$		$
Annualized minimum quarterly distribution per unit	$		$
Aggregate distributions based on annualized minimum quarterly distribution
Percent of minimum quarterly distributions payable to common unitholders		%			%
Percent of minimum quarterly distributions payable to subordinated unitholder		%			%

(1) The forecast is based on the assumptions set forth in “—Forecast Assumptions and Considerations—Summary of Significant Forecast Assumptions.”

(2) Adjusted EBITDA is a non-GAAP financial measure. We define adjusted EBITDA as earnings before interest, other financial items, depreciation and amortization, amortization of mobilization revenue and expense, taxes and non-controlling interest and is used as a supplemental financial measure by management and external users of financial statements, such as investors, to assess our financial and operating performance. Adjusted EBITDA assists our management and investors by increasing the comparability of our performance from period to period and against the performance of other companies in our industry that provide adjusted EBITDA information. This increased comparability is achieved by excluding the potentially disparate effects between periods or companies of interest, other financial items, depreciation and amortization, amortization of mobilization revenue and expense, taxes and non-controlling interest, which items are affected by various and possibly changing financing methods, capital structure and

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historical cost basis and which items may significantly affect net income between periods. We believe that including adjusted EBITDA as a financial and operating measure benefits investors in (a) selecting between investing in us and other investment alternatives and (b) monitoring our ongoing financial and operational strength in assessing whether to continue to hold common units.

Adjusted EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with U.S. GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income, and these measures may vary among other companies. Therefore, adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies. The following table reconciles our forecasted net income to forecasted adjusted EBITDA.

	Forecast
	Ocean Rig Partners LP
	Twelve Months Ending September 30, 2015	Historical
		Year Ended December 31, 2013
(in thousands)
Net income/(loss) attributable to Ocean Rig Partners LP partners	$	$	(25,627	)
Interest income			(90	)
Interest expense and other financial items			21,022
Depreciation and amortization			11,740
Amortization of mobilization revenue and expense(7)			(4,249	)
Income taxes
Non-controlling interest
Adjusted EBITDA	$	$	2,796

(3) Our Partnership Agreement requires that an estimate of the maintenance and replacement capital expenditures necessary to maintain our asset base be subtracted from operating surplus each quarter, as opposed to amounts actually spent. Please read “Risk Factors—Risks Inherent in Our Business—OPCO must make substantial capital and operating expenditures to maintain the operating capacity of its fleet, which will reduce cash available for distribution. In addition, each quarter we are required to deduct estimated maintenance and replacement capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance and replacement capital expenditures were deducted.”

(4) The non-controlling interest comprises (i) Ocean Rig’s     % limited partner interest in OPCO, through OPCO Holdings, which owns 100% of the entities that will own and operate theOcean Rig Athena, theOcean Rig Mylos and theOcean Rig Skyros upon the closing of this offering. Non-controlling interest for the historical periods presented in the table above have been calculated as if the non-controlling interests described above were in place at January 1, 2013. Net income attributable to non-controlling interest has been estimated based on a number of assumptions. The main assumption is related to the allocation of loss on derivatives, where the allocation has been based on average outstanding debt in the periods presented.

(5) Assumes the underwriters’ option to purchase additional common units is not exercised.

(6) Represents the amount required to fund distributions to our unitholders for four quarters based upon our minimum quarterly distribution rate of $         per unit.

(7) Amortization of mobilization revenue and expense is amortization of lump sum mobilization revenue received prior to the commencement of the drilling contracts net of amortized expense incurred during the mobilization period.

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Forecast of Compliance with Debt Covenants. Our ability to make distributions could be affected if OPCO does not remain in compliance with the covenants of the New Senior Secured Term Loan Facility. We have assumed that OPCO will be in compliance with all of the covenants during the forecast period. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Borrowing Activities” for a further description of our financing agreements, including these financial covenants.

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HOW WE MAKE CASH DISTRIBUTIONS

Distributions of Available Cash

General

Within 45 days after the end of each quarter, beginning with the quarter ending             ,         we will distribute all of our available cash (defined below) to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of this offering through             ,         based on the actual length of the period.

Definition of Available Cash

Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own, including OPCO):

• less, the amount of cash reserves (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own, including OPCO) established by the board of directors of our General Partner to:

• provide for the proper conduct of our business (including reserves for future capital expenditures and for anticipated credit needs);

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

• provide funds for distributions to our unitholders for any one or more of the next four quarters; provided, however, our board could not reserve funds for such future quarters if we would be unable to pay the minimum quarterly distribution plus any arrearage in the quarter for which available cash is being determined;

• plus, all cash on hand (including our proportionate share of cash on hand of certain subsidiaries we do not wholly own, including OPCO) on the date of determination of available cash for the quarter resulting from (1) working capital borrowings made after the end of the quarter and (2) cash distributions received after the end of the quarter from any of our equity interests in any person (other than a subsidiary of us), which distributions are paid by such person in respect of operations conducted by such person during such quarter. Working capital borrowings are generally borrowings that are made under a revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to members.

Intent to Distribute the Minimum Quarterly Distribution

We intend to distribute to the holders of common units and subordinated units on a quarterly basis at least the minimum quarterly distribution of $         per unit, or $         per unit per year, to the extent we have sufficient cash on hand to pay the distribution after we establish cash reserves and pay fees and expenses. The amount of available cash from operating surplus needed to pay the minimum quarterly distribution for one quarter on all units outstanding immediately after this offering is approximately $         million.

There is no guarantee that we will pay the minimum quarterly distribution on the common units and subordinated units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution will be determined by the board of directors of our General Partner, taking into consideration the terms of our Partnership Agreement. Because our ownership interest in OPCO will be our only cash-generating asset upon the closing of this offering, the amount of our distributions to unitholders initially will depend upon distributions by OPCO to us including, OPCO’s ability to make distributions to us based on their financing arrangements. OPCO will be prohibited from making any distributions to us if it would cause an event of default, or an event of default is then existing, under its

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financing agreements. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for a discussion of the restrictions contained in OPCO’s financing agreements that may restrict its ability to make distributions.

Operating Surplus and Capital Surplus

General

All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

Definition of Operating Surplus

Operating surplus for any period generally means:

• $         million;plus

• all of our cash receipts (including our proportionate share of cash receipts of certain subsidiaries we do not wholly own, including OPCO) after the closing of this offering (provided, that cash receipts from the termination of an interest rate, currency or commodity hedge contract prior to its specified termination date will be included in operating surplus in equal quarterly installments over the remaining scheduled life of such hedge contract), excluding cash from (1) borrowings, other than working capital borrowings, (2) sales of equity and debt securities, (3) sales or other dispositions of assets outside the ordinary course of business, (4) capital contributions or (5) corporate reorganizations or restructurings;plus

• working capital borrowings (including our proportionate share of working capital borrowings for certain subsidiaries we do not wholly own, including OPCO) made after the end of a quarter but before the date of determination of operating surplus for the quarter;plus

• interest paid on debt incurred (including periodic net payments under related hedge contracts) and cash distributions paid on equity securities issued (including the amount of any incremental distributions made to the holders of our incentive distribution rights and our proportionate share of such interest and cash distributions paid by certain subsidiaries we do not wholly own, including OPCO), in each case, to finance all or any portion of the construction, replacement or improvement of a capital asset (such as a drillship) in respect of the period from such financing until the earlier to occur of the date the capital asset is put into service or the date that it is abandoned or disposed of;plus

• interest paid on debt incurred (including periodic net payments under related hedge contracts) and cash distributions paid on equity securities issued (including the amount of any incremental distributions made to the holders of our incentive distribution rights and our proportionate share of such interest and cash distributions paid by certain subsidiaries we do not wholly own, including OPCO), in each case, to pay the construction period interest on debt incurred (including periodic net payments under related interest rate swap agreements), or to pay construction period distributions on equity issued, to finance the construction projects described in the immediately preceding bullet;less

• all of our “operating expenditures” (which includes estimated maintenance and replacement capital expenditures and is further described below) of us and our subsidiaries (including our proportionate share of operating expenditures by certain subsidiaries we do not wholly own, including OPCO) immediately after the closing of this offering;less

• the amount of cash reserves (including our proportionate share of cash reserves for certain subsidiaries we do not wholly own, including DOV II) established by our General Partner to provide funds for future operating expenditures;less

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• any cash loss realized on dispositions of assets acquired using investment capital expenditures;less

• all working capital borrowings (including our proportionate share of working capital borrowings by certain subsidiaries we do not wholly own, including OPCO) not repaid within twelve months after having been incurred.

If a working capital borrowing, which increases operating surplus, is not repaid during the 12-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 not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

As described above, operating surplus includes a provision that will enable us, if we choose, to distribute as operating surplus up to $         million of 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 securities or interest payments on debt in operating surplus would be to increase operating surplus by the amount of any such cash distributions or interest payments. As a result, we may also distribute as operating surplus up to the amount of any such cash distributions or interest payments of cash we receive from non-operating sources.

Operating expenditures generally means all of our cash expenditures, including, but not limited to taxes, employee and director compensation, reimbursement of expenses to our General Partner, repayment of working capital borrowings, debt service payments and payments made under any interest rate, currency or commodity hedge contracts (provided that payments made in connection with the termination of any hedge contract prior to the expiration of its stipulated settlement or termination date shall be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such hedge contract), provided that operating expenditures will not include:

• deemed repayments of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus above when such repayment actually occurs;

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

• expansion capital expenditures, investment capital expenditures or actual maintenance and replacement capital expenditures (which are discussed in further detail under “—Capital Expenditures” below);

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

• distributions to members.

Capital Expenditures

For purposes of determining operating surplus, maintenance and replacement capital expenditures are those capital expenditures required to maintain over the long-term the operating capacity of or the revenue generated by capital assets, and expansion capital expenditures are those capital expenditures that increase the operating capacity of or the revenue generated by capital assets. In our Partnership Agreement, we refer to these maintenance and replacement capital expenditures as “maintenance capital expenditures.” To the extent, however, that capital expenditures associated with acquiring a new drillship or improving an existing drillship increase the revenues or the operating capacity of the fleet, those capital expenditures would be classified as 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

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traditional capital expenditures for investment purposes, such as purchases of equity 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.

Examples of maintenance and replacement capital expenditures include capital expenditures associated with maintenance, modifying an existing drillship or acquiring a new drillship to the extent such expenditures are incurred to maintain the operating capacity of or the revenue generated by the fleet. Maintenance and replacement capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including the amount of any incremental distributions made to the holders of our incentive distribution rights) to finance the construction of a replacement drillship and paid in respect of the construction period, which we define as the period beginning on the date that we or DOV II enter into a binding construction contract and ending on the earlier of the date that the replacement drillship commences commercial service or the date that the replacement drillship is abandoned or disposed of. Debt incurred to pay or equity issued to fund construction period interest payments, and distributions on such equity (including the amount of any incremental distributions made to the holders of our incentive distribution rights), will also be considered maintenance and replacement capital expenditures.

Because maintenance and replacement capital expenditures can be very large and vary significantly in timing, the amount of actual maintenance and replacement capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and available cash for distribution to our unitholders if we subtracted actual maintenance and replacement capital expenditures from operating surplus each quarter. Accordingly, to eliminate the effect on operating surplus of these fluctuations, our Partnership Agreement will require that an amount equal to an estimate of the average quarterly maintenance and replacement capital expenditures necessary to maintain the operating capacity of or the revenue generated by our capital assets over the long-term be subtracted from operating surplus each quarter, as opposed to the actual amounts spent. In our Partnership Agreement, we refer to these estimated maintenance and replacement capital expenditures to be subtracted from operating surplus as “estimated maintenance capital expenditures.” The amount of estimated maintenance and replacement capital expenditures deducted from operating surplus is subject to review and change by our General Partner at least once a year, provided that any change must be approved by our General Partner’s conflicts committee. 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 affect the fleet. 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:

• it will reduce the risk that actual maintenance and replacement capital expenditures in any one quarter will be large enough to make operating surplus less than the minimum quarterly distribution to be paid on all the units for that quarter and subsequent quarters;

• it may reduce the need for us to borrow to pay distributions;

• it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions to our General Partner; and

• it will reduce the likelihood that a large maintenance and replacement capital expenditure in a period will prevent our Sponsor from being able to convert some or all of its subordinated units into common units since the effect of an estimate is to spread the expected expense over several periods, mitigating the effect of the actual payment of the expenditure on any single period.

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Definition of Capital Surplus

Capital surplus generally will be generated only by:

• borrowings other than working capital borrowings;

• sales of debt and equity securities; and

• sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or non-current assets sold as part of normal retirements or replacements of assets.

Characterization of Cash Distributions

We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $         million of 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. We do not anticipate that we will make any distributions from capital surplus.

Subordination Period

General

During the subordination period, which we define below, the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution of $         per unit, 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. Distribution arrearages do not accrue on the subordinated units. The purpose of the subordinated units is to increase the likelihood that during the subordination period there will be available cash from operating surplus to be distributed on the common units.

Definition of Subordination Period

The subordination period will extend until the second business day following the distribution of available cash from operating surplus in respect of any quarter, ending on or after             , that each of the following tests are met:

• distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded the 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 minimum quarterly distributions on all of the outstanding common units and subordinated units during those periods on a fully diluted weighted average basis during those periods; and

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

If the unitholders remove our General Partner without cause, the subordination period may end before                 .

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For purposes of determining whether the tests in the bullets above have been met, the three consecutive four-quarter periods for which the determination is being made may include one or more quarters with respect to which arrearages in the payment of the minimum quarterly distribution on the common units have accrued, provided that all such arrearages have been repaid prior to the end of each such four-quarter period.

If the expiration of the subordination period occurs as a result of us having met the tests described above, 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.

In addition, at any time on or after             , provided that there are no outstanding arrearages in payment of the minimum quarterly distribution on the common units and subject to approval by our conflicts committee, the holder or holders of a majority of our outstanding subordinated units will have the option to convert each subordinated unit into a number of common units determined by multiplying the number of outstanding subordinated units to be converted by a fraction, (i) the numerator of which is equal to the aggregate amount of distributions of available cash from operating surplus (not to exceed adjusted operating surplus) on the outstanding subordinated units (“historical distributions”) for the four fiscal quarters preceding the date of conversion (the “measurement period”) and (ii) the denominator of which is equal to the aggregate amount of distributions that would have been required during the measurement period to pay the minimum quarterly distribution on all outstanding subordinated units during such four-quarter period; provided, that if the forecasted distributions to be paid from forecasted operating surplus (not to exceed forecasted adjusted operating surplus) on the outstanding subordinated units for the four fiscal quarter period immediately following the measurement period (“forecasted distributions”), as determined by the conflicts committee, is less than historical distributions, then the numerator shall be forecasted distributions; provided, further, however, that the subordinated units may not convert into common units at a ratio that is greater than one-to-one. If the option to convert the subordinated units into common units is exercised as described above, the outstanding subordinated units will convert into the prescribed number of common units and will then participate pro rata with other common units in distributions of available cash.

Definition of Adjusted Operating Surplus

Adjusted operating surplus for any period generally means:

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

• the amount of any net increase in working capital borrowings (including our proportionate share of any changes in working capital borrowings of certain subsidiaries we do not wholly own, including DOV II) with respect to that period;less

• the amount of any net reduction in cash reserves for operating expenditures (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own, including DOV II) over that period not relating to an operating expenditure made during that period;plus

• the amount of any net decrease in working capital borrowings (including our proportionate share of any changes in working capital borrowings of certain subsidiaries we do not wholly own, including DOV II) with respect to that period; plus

• the amount of any net increase in cash reserves for operating expenditures (including our proportionate share of cash reserves of certain subsidiaries we do not wholly own, including DOV II) over that period required by any debt instrument for the repayment of principal, interest or premium;plus

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

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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.

Effect of Removal of Our General Partner on the Subordination Period

If the unitholders remove our General Partner other than for cause and units held by our General Partner and its affiliates are not voted in favor of such removal:

• the subordination period will end and each subordinated unit will immediately convert into one common unit and will then participate pro rata with the other common units in distributions of available cash;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• the holders of the incentive distribution rights (initially, our General Partner) will have the right to convert its incentive distribution rights into common units or to receive cash in exchange for those interests.

Distributions of Available Cash From Operating Surplus During the Subordination Period

We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

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

• second, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

• third, 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.

The preceding paragraph is based on the assumption that we do not issue additional classes of equity securities.

Distributions of Available Cash From Operating Surplus After the Subordination Period

We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

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

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

The preceding paragraph is based on the assumption that we do not issue additional classes of equity securities.

General Partner Interest

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

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Incentive Distribution Rights

Incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner will hold the incentive distribution rights following completion of this offering. Except for transfers of incentive distribution rights to an affiliate or another entity as part of our General Partner’s merger or consolidation with or into, or sale of substantially all of its assets to such entity, the approval of a majority of our common units (excluding common units held by our General Partner and its affiliates), voting separately as a class, generally is required for a transfer of the incentive distribution rights to a third party prior to             . Please read “The Partnership Agreement—Transfer of Incentive Distribution Rights.” Any transfer by our General Partner of the incentive distribution rights would not change the percentage allocations of quarterly distributions with respect to such rights.

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, we will distribute any additional available cash from operating surplus for that quarter among the unitholders in the following manner:

• first, 100% to all unitholders, pro rata, until each unitholder receives a total of $         per unit for that quarter (the “first target distribution”);

• second, 85% to all unitholders, pro rata, and 15% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $         per unit for that quarter (the “second target distribution”);

• third, 75% to all unitholders, pro rata, and 25% to the holders of the incentive distribution rights, pro rata, until each unitholder receives a total of $         per unit for that quarter (the “third target distribution”); and

• thereafter, 50% to all unitholders, pro rata, and 50% to the holders of the incentive distribution rights, pro rata.

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution. The percentage interests set forth above assume that we do not issue additional classes of equity securities.

Percentage Allocations of Available Cash From Operating Surplus

The following table illustrates the percentage allocations of the additional available cash from operating surplus among the unitholders and the holders of the incentive distribution rights up to the various target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of the unitholders and the holders of the incentive distribution rights in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Target Amount,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the holders of the

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incentive distribution rights for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.

	Total Quarterly Distribution Target Amount		Marginal Percentage Interest in Distributions
			Unitholders			Holders of IDRs
Minimum Quarterly Distribution	$			100	%		0	%
First Target Distribution		up to $		100	%		0	%
Second Target Distribution		above $         up to $		85	%		15	%
Third Target Distribution		above $         up to $		75	%		23	%
Thereafter		above $		50	%		50	%

Our General Partner’s Right to Reset Incentive Distribution Levels

Our General Partner, as the initial holder of our incentive distribution rights, has the right under our Partnership Agreement to elect to relinquish the right of the holders of our incentive distribution rights to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our General Partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our General Partner are based may be exercised, without approval of our unitholders or the conflicts committee of the board of directors of our General Partner, 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 each of the prior four consecutive fiscal quarters. If at the time of any election to reset the minimum quarterly distribution amount and the target distribution levels our General Partner and its affiliates are not the holders of a majority of the incentive distribution rights, then any such election to reset shall be subject to the prior written concurrence of our General Partner that the conditions described in the immediately preceding sentence have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and 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 this event increase as described below. We anticipate that our General Partner 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 to our General Partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our General Partner of incentive distribution payments based on the target cash distributions prior to the reset, our General Partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our General Partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period.

The number of common units that our General Partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to (x) the average amount of cash distributions received by our General Partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election divided by (y) the average of the amount of cash distributed per common unit during each of these two quarters. The issuance of the additional common units will be conditioned upon approval of the listing or admission for trading of such common units by the national securities exchange on which the common units are then listed or admitted for trading.

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Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

• first, 100% to all unitholders, pro rata, until each unitholder receives an amount equal to 115% of the reset minimum quarterly distribution for that quarter;

• second, 85% to all unitholders, pro rata, and 15% to the holders of the incentive distribution rights, pro rata, until each unitholder receives an amount per unit equal to 125% of the reset minimum quarterly distribution for the quarter;

• third, 75% to all unitholders, pro rata, and 25% to the holders of the incentive distribution rights, pro rata, until each unitholder receives an amount per unit equal to 150% of the reset minimum quarterly distribution for the quarter; and

• thereafter, 50% to all unitholders, pro rata, and 50% to the holders of the incentive distribution rights, pro rata.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and the holders of the incentive distribution rights at various levels of cash distribution levels pursuant to the cash distribution provision of our Partnership Agreement in effect at the closing of this offering as well as 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 two fiscal quarters immediately preceding the reset election was $            .

			Marginal Percentage Interest in Distribution
	Quarterly Distribution per Unit Prior to Reset		Unitholders			Holders of IDRs			Quarterly Distribution per Unit following Hypothetical Reset
Minimum Quarterly Distribution	$			100	%		0	%	$
First Target Distribution	up to $			100	%		0	%	up to $         (1)
Second Target Distribution		above $         up to $		85	%		15	%	above $         up to $         (2)
Third Target Distribution		above $         up to $		75	%		25	%	above $         up to $         (3)
Thereafter		above $		50	%		50	%	above $ (3)

(1) This amount is 115% of the hypothetical reset minimum quarterly distribution.

(2) This amount is 125% of the hypothetical reset minimum quarterly distribution.

(3) This amount is 150% 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 the holders of the incentive distribution rights based on an average of the amounts distributed per quarter for the two quarters immediately prior to the reset. The table assumes that there are             common units outstanding, and that the average distribution to each common unit is $         for the two

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quarters prior to the reset. The assumed number of outstanding units assumes the conversion of all subordinated units into common units and no additional unit issuances.

	Quarterly Distribution per Unit Prior to Reset	Common Unitholders Cash Distributions Prior to Reset	Additional Common Units	IDR Holders Cash Distributions Prior to Reset		Total Distributions
				IDRs	Total
Minimum Quarterly Distribution	$	$		$	$	$
First Target Distribution	$
Second Target Distribution	$
Third Target Distribution	$
Thereafter	$
		$		$	$	$

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the holders of the incentive distribution rights with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there are         common units outstanding, and that the average distribution to each common unit is $            . The number of additional common units was calculated by dividing (x) $         as the average of the amounts received by our General Partner in respect of their incentive distribution rights, for the two quarters prior to the reset as shown in the table above by (y) the $         of available cash from operating surplus distributed to each common unit as the average distributed per common unit for the two quarters prior to the reset.

	Quarterly Distribution per Unit After Reset	Common Unitholders Cash Distributions After Reset	Additional Common Units	IDR Holders Cash Distributions After Reset		Total Distributions
				IDRs	Total
Minimum Quarterly Distribution	$	$	$	$	$	$
First Target Distribution	$
Second Target Distribution	$
Third Target Distribution	$
Thereafter	$
		$	$	$	$	$

Assuming that it continues to hold a majority of our incentive distribution rights, our General Partner will be entitled to cause the minimum quarterly distribution amount and 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 the holders of the incentive distribution rights have received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that the holders of incentive distribution rights are entitled to receive under our Partnership Agreement.

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Distributions From Capital Surplus

How Distributions From Capital Surplus Will Be Made

We will make distributions of available cash from capital surplus, if any, in the following manner:

• first, to all 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.

The preceding paragraph is based on the assumption that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus

The Partnership Agreement treats a distribution of capital surplus as the repayment of the consideration for the issuance of the units, 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 distribution had 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, after any of these distributions are made, it may be easier for our General Partner 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 the target distribution levels to zero, we will then make all future distributions 50% to the holders of units and 50% to the holders of the incentive distribution rights (initially, our General Partner).

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 units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

• the minimum quarterly distribution;

• the target distribution levels; and

• the initial unit price.

For example, if a two-for-one split of the common and subordinated units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50% 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 our subordinated units or subdivide our subordinated units, using the same ratio applied to the common units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

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Distributions of Cash Upon Liquidation

If we dissolve in accordance with the Operating Agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will apply the proceeds of liquidation in the manner set forth below.

If, as of the date three trading days prior to the announcement of the proposed liquidation, the average closing price for our common units for the preceding 20 trading days (or the current market price) is greater than the sum of:

• any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; plus

• the initial unit price (less any prior capital surplus distributions and any prior cash distributions made in connection with a partial liquidation);

then the proceeds of the liquidation will be applied as follows:

• first, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the current market price of our common units;

• second, to the subordinated unitholders, pro rata, until we distribute for each subordinated unit an amount equal to the current market price of our common units; and

• thereafter, 50% to all unitholders, pro rata, 50% to holders of incentive distribution rights.

If, as of the date three trading days prior to the announcement of the proposed liquidation, the current market price of our common units is equal to or less than the sum of:

• any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period; plus

• the initial unit price (less any prior capital surplus distributions and any prior cash distributions made in connection with a partial liquidation);

then the proceeds of the liquidation will be applied as follows:

• first, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the initial unit price (less any prior capital surplus distributions and any prior cash distributions made in connection with a partial liquidation);

• second, to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

• third, to the subordinated unitholders, until we distribute for each outstanding subordinated unit an amount equal to the initial unit price (less any prior capital surplus distributions and any prior cash distributions made in connection with a partial liquidation); and

• thereafter, 50% to all unitholders, pro rata, 50% to holders of incentive distribution rights.

The immediately preceding paragraph is based on the assumption that we do not issue additional classes of equity securities.

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SELECTED HISTORICAL COMBINED FINANCIAL AND OPERATING DATA

We were formed on April 16, 2014 by our Sponsor as a growth-oriented limited partnership to own, operate and acquire offshore drilling units, including through our ownership of OPCO. OPCO’s Initial Fleet consists of three ultra-deepwater drillships theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena, all of which are currently employed or will be employed on multi-year drilling contracts with affiliates of major oil companies. Upon the closing of this offering, we will acquire from our Sponsor, interests in OPCO’s Initial Fleet. In addition, prior the completion of this offering, we will complete a series of other formation transactions that are described in the section of the prospectus entitled “Summary—Formation Transactions.” Our business will be a direct continuation of the Ocean Rig Partners LP Predecessor. We do not intend to engage in any business or other activities prior to the closing of the offering, except in connection with our formation. The Ocean Rig Partners LP Predecessor includes subsidiaries of our Sponsor that prior to the completion of the this offering had interests in the entities that own and operate the drillships in OPCO’s initial fleet.

The selected historical financial data of Ocean Rig Partners LP Predecessor as of and for the years ended December 31, 2012 and 2013 are derived from the audited Combined Carve-out Financial Statements of Ocean Rig Partners LP Predecessor, prepared in accordance with U.S. GAAP, which are included elsewhere in this prospectus. Our independent registered accounting firm’s report included in this prospectus relate to historical Combined Carve-out Financial Statements of Ocean Rig Partners LP Predecessor. That report does not extend to the tables and the related forecasted financial information contained in this prospectus and should not be read to do so.

The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical Combined Carve-out Financial Statements of Ocean Rig Partners LP Predecessor and the notes thereto and our forecasted results of operations, in each case included elsewhere in this prospectus.

Our financial position, results of operations and cash flows could differ from those that would have resulted if we operated autonomously or as an entity independent of our Sponsor in the periods for which historical financial data are presented below, and such data may not be indicative of our future operating results or financial performance.

	For the year ended December 31,
(U.S. Dollars in thousands)	2012			2013
Income statement data:
Total revenues	$	—		$	37,325
Drillships operating expenses		—			13,576
Depreciation		—			11,740
General and administrative expenses		6,720			25,827
Operating Loss		(6,720	)		(13,818	)
Other Income/(Expenses)
Interest and finance costs		(3	)		(21,022	)
Interest income		—			90
Gain/(loss) on interest rate swaps, net		(3,674	)		8,510
Other, net		(219	)		613
Total other expenses, net		(3,896	)		(11,809	)
Loss before income taxes		(10,616	)		(25,627	)
Income taxes
Net loss	$	(10,616	)		(25,627	)

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	As of December 31,
(U.S. Dollars in thousands)	2012		2013
Balance sheet data:
Cash and cash equivalents	$	1,452	$	6,083
Other current assets		14,000		119,156
Total current assets		15,452		125,239
Drillships, machinery and equipment, net				1,412,164
Other non current assets		935		104,839
Advances for drillships under construction and related costs		770,858		292,692
Total assets		787,245		1,934,934
Current liabilities, including current portion of long term debt, net of deferred financing costs		5,961		221,514
Long term debt, net of current portion and deferred financing costs				797,114
Other non current liabilities		3,106		101,129
Total liabilities		9,067		1,119,757
Total Stockholders’ equity		778,178		815,177
Common Stock		184		184
Total liabilities and stockholders’ equity	$	787,245	$	1,934,934

	Year Ended December 31,
(U.S. Dollars in thousands, except for operating data)	2012			2013
Cash flow data:
Net cash provided by / (used in):
Operating activities	$	(3,779	)	$	83,375
Investing activities		(45,284	)		(989,738	)
Financing activities		50,515			910,994
Other financial data
EBITDA(1)		(10,613	)		7,045
Cash paid for interest		—			(4,282	)
Capital expenditures		—			(58,267	)
Payments for drillships under construction		(39,284	)		(887,471	)
Operating data, when on hire
Operating units		0			2

(1) EBITDA represents net income before interest, taxes, depreciation and amortization. EBITDA is a non-U.S. generally accepted accounting principles, or U.S. GAAP, measure and does not represent and should not be considered as an alternative to net income or cash flow from operations, as determined by GAAP or other GAAP measures, and our calculation of EBITDA may not be comparable to that reported by other companies. EBITDA is included herein because it is a basis upon which we measure our operations.

	Year Ended December 31,
(U.S. Dollars in thousands)	2012			2013
EBITDA reconciliation
Net loss	$	(10,616	)	$	(25,627	)
Add: Depreciation		—			11,740
Add: Net interest expense		3			20,932
Add: Income taxes		—
EBITDA	$	(10,613	)	$	7,045

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the “Selected Historical Combined Financial and Operating Data” and the accompanying audited combined carve-out financial statements of Ocean Rig Partners LP Predecessor and the related notes included elsewhere in this prospectus. Amounts relating to percentage variations in period—on—period comparisons shown in this section are derived from the actual numbers in our books and records. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. See “Risk Factors” and “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Our Business

We are a growth-oriented limited partnership recently formed by our Sponsor to own, operate and acquire offshore drilling units, including through our ownership of OPCO. OPCO’s Initial Fleet consists of three ultra-deepwater drillships: theOcean Rig Mylos,Ocean Rig Skyros and theOcean Rig Athena, all of which are currently in operation. The drillships that comprise OPCO’s Initial Fleet are employed under multi-year contracts with affiliates of major oil companies, including Repsol, Total and Conoco Phillips with an average remaining term of 4.0 years as of July 13, 2014. We intend to grow our exposure to the offshore drilling market initially by acquiring additional interests in OPCO and at a later stage by acquiring ownership interests in other drilling units owned by our Sponsor and third parties, subject to the limitations in our and our Sponsor’s debt agreements. We intend to leverage the relationships, expertise and reputation of our Sponsor to operate OPCO’s Initial Fleet in an efficient manner, to re-contract OPCO’s Initial Fleet under multi-year contracts and to identify opportunities to expand OPCO’s Initial Fleet through acquisitions. We believe our Sponsor will be motivated to facilitate our growth because of its significant ownership interest in us. See “—Our Relationship with our Sponsor.”

We plan to grow our per unit distributions by acquiring additional interests in OPCO and interests in other drilling units owned by our Sponsor and third parties. Pursuant to the Omnibus Agreement that we will enter into with our Sponsor and our General Partner upon the completion of this offering, we will have the following purchase rights:

• a right of first offer to purchase from our Sponsor Additional Fleet Interests;

• a right to purchase from our Sponsor any Four-Year Drillships; and

• a right to purchase from our Sponsor Optional Drillship Interests.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations is based on upon our combined financial statements, which have been prepared in accordance with U.S. GAAP. We are an “emerging growth company,” as defined in the JOBS Act. We have elected to take advantage of the reduced reporting obligations, including the extended transition period for complying with new or revised accounting standards under Section 102 of the JOBS Act, and as such, the information we provide to our unitholders may be different from the information provided by other public companies and our financial statements and may not be comparable to companies that comply with public company effective dates. The preparation of those financial statements requires us to make estimates and judgments that affect the reported amounts of asset and liabilities, revenues and expenses and related disclosure at the date of our financial statements. Actual results may differ from these estimates under different assumptions and conditions.

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Critical accounting policies are those that reflect significant judgments or uncertainties and potentially result in materially different results under different assumptions and conditions.

Drillships machinery and equipment, net: Drillships are stated at historical cost less accumulated depreciation. Such costs include the cost of adding or replacing parts of drillships machinery and equipment when that cost is incurred, if the recognition criteria are met. The recognition criteria require that the cost incurred extends the useful life of a drillship. The carrying amounts of those parts that are replaced are written off and the cost of the new parts is capitalized. Depreciation is calculated on a straight- line basis over the useful life of the assets as follows: bare-deck, 30 years and other asset parts, 5 to 15 years. The residual value of the drillships are estimated at $50 million.

Drillships machinery and equipment, information technology and office equipment are recorded at cost and are depreciated on a straight-line basis over the estimated useful lives, for drilling unit machinery and equipment over 5 to 15 years and for information technology and office equipment over 5 years.

Impairment of long-lived assets: We review for impairment long-lived assets and intangible long-lived assets held and used whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. In this respect, we review our assets for impairment on a drillship by drillship and asset by asset basis. When the estimate of undiscounted cash flows, excluding interest charges, expected to be generated by the use of the asset is less than its carrying amount, we evaluate the asset for impairment loss. The impairment loss is determined by the difference between the carrying amount of the asset and the fair value of the asset. We evaluate the carrying amounts of our drillships by obtaining independent appraisals to determine if events have occurred that would require modification to their carrying values or useful lives. In evaluating useful lives and carrying values of long-lived assets, we review certain indicators of potential impairment, such as undiscounted projected operating cash flows, drilling rig/drillship sales and purchases, business plans and overall market conditions. In developing estimates of future undiscounted cash flows, we make assumptions and estimates about the drillships’ future performance, with the significant assumptions being related to drilling rates, fleet utilization, operating expenses, capital expenditures, residual value and the estimated remaining useful life of each drillship. The assumptions used to develop estimates of future undiscounted cash flows are based on historical trends as well as future expectations. To the extent impairment indicators are present, we determine undiscounted projected net operating cash flows for each drillship and compare them to the drillship’s carrying value. The projected net operating cash flows are determined by considering the drilling revenues from existing drilling contracts for the fixed days and an estimated daily rate equivalent for the unfixed days. The salvage value used in the impairment test is estimated to be $35 million and $50 million for drillships, respectively, in accordance with our depreciation policy. If our estimate of undiscounted future cash flows for any drillship is lower than the carrying value, the carrying value is written down, by recording a charge to operations, to the vessel’s fair market value if the fair market value is lower than the vessel’s carrying value. Our analysis for the year ended December 31, 2013, which also involved sensitivity tests on the drilling rates and fleet utilization (being the most sensitive inputs to variances), allowing for variances ranging from 97.5% to 92.5%, indicated no impairment on any of drillships. Although we believe that the assumptions used to evaluate potential impairment are reasonable and appropriate, such assumptions are highly subjective. There can be no assurance as to how long drilling rates and drillship values will remain at their currently high levels.

Deferred financing costs: Deferred financing costs include fees, commissions and legal expenses associated with our long-term debt and are capitalized and recorded net with the underlying debt. These costs are amortized over the life of the related debt using the effective interest method and are included in interest expense. Unamortized fees relating to loans repaid or refinanced as debt extinguishments are expensed as interest and finance costs in the period the repayment or extinguishment is made.

Revenue and related expenses: Revenues: Our services and deliverables are generally sold based upon contracts with our customers that include fixed or determinable prices. We recognize revenue when delivery

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occurs, as directed by our customer, or the customer assumes control of physical use of the asset and collectability is reasonably assured. We evaluate if there are multiple deliverables within our contracts and whether the agreement conveys the right to use the drillships for a stated period of time and meet the criteria for lease accounting, in addition to providing a drilling services element, which are generally compensated for by dayrates. In connection with drilling contracts, we may also receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to the drillships and dayrate or fixed price mobilization and demobilization fees. Revenues are recorded net of agents’ commissions. There are two types of drilling contracts: well contracts and term contracts.

Well contracts: Well contracts are contracts under which the assignment is to drill a certain number of wells. Revenue from dayrate-based compensation for drilling operations is recognized in the period during which the services are rendered at the rates established in the contracts. All mobilization revenues, direct incremental expenses of mobilization and contributions from customers for capital improvements are initially deferred and recognized as revenues and expenses, as applicable, over the estimated duration of the drilling period. To the extent that expenses exceed revenue to be recognized, they are expensed as incurred. Demobilization fees and expenses are recognized over the demobilization period. All revenues for well contracts are recognized as “Service revenues” in the statement of operations.

Term contracts: Term contracts are contracts under which the assignment is to operate the drilling unit for a specified period of time. For these types of contracts we determine whether the arrangement is a multiple element arrangement containing both a lease element and drilling services element. For revenues derived from contracts that contain a lease, the lease elements are recognized as “Leasing revenues” in the statement of operations on a basis approximating straight line over the lease period. The drilling services element is recognized as “Service revenues” in the period in which the services are rendered at fair value. Revenues related to the drilling element of mobilization and direct incremental expenses of drilling services are deferred and recognized over the estimated duration of the drilling periods. To the extent that expenses exceed revenue to be recognized, they are expensed as incurred. Demobilization fees and expenses are recognized over the demobilization period. Contributions from customers for capital improvements are initially deferred and recognized as revenues over the estimated duration of the drilling contract.

Income taxes: Income taxes have been provided for based upon the tax laws and rates in effect in the countries in which our operations are conducted and income is earned. There is no expected relationship between the provision for/or benefit from income taxes and income or loss before income taxes because the countries in which we operate have taxation regimes that vary not only with respect to the nominal rate, but also in terms of the availability of deductions, credits and other benefits. Variations also arise because income earned and taxed in any particular country or countries may fluctuate from year to year. Deferred tax assets and liabilities are recognized for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of our assets and liabilities using the applicable jurisdictional tax rates in effect at the year end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. We accrue interest and penalties related to its liabilities for unrecognized tax benefits as a component of income tax expense.

Factors Affecting Our Results of Operations

We charter our drilling units to customers primarily pursuant to long-term drilling contracts. Under the drilling contracts, the customer typically pays us a fixed daily rate, depending on the activity and up-time of the drilling unit. The customer bears all fuel costs and logistics costs related to transport to and from the unit. We remain responsible for paying the unit’s operating expenses, including the cost of crewing, catering, insuring, repairing and maintaining the unit, the costs of spares and consumable stores and other miscellaneous expenses.

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We believe that the most important measures for analyzing trends in the results of our operations consist of the following:

• Employment Days:We define employment days as the total number of days the drilling units are employed on a drilling contract.

• Dayrates or maximum dayrates:We define drilling dayrates as the maximum rate in U.S. Dollars possible to earn for drilling services for one 24 hour day at 100% economic utilization under the drilling contract. Such dayrate may be measured by quarter-hour, half-hour or hourly basis and may be reduced depending on the activity performed according to the drilling contract.

• Economic utilization: We measure our revenue earning performance over a period as a percentage of the maximum revenues that we could earn under our drilling contracts in such period. More specifically, all drilling contracts provide for an operating or base rate that applies for the period during which the drillship is operational and at the client’s drilling location. Furthermore, drilling contracts typically provide for situations where the drillship operates in standby, force majeure weather, equipment breakdown or other reduced operating day rate, at which instances we are compensated with a portion of the base rate. In addition there are circumstances that due to equipment failure or other events defined in our drilling contracts, we do not earn the base rate. For the year ended December 31, 2013 OPCO’s Initial Fleet’s economic utilization was 93.6%.

• Mobilization / demobilization fees:In connection with drilling contracts, we may receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to the drilling vessels, dayrate or fixed price mobilization and demobilization fees.

• Revenue: For each contract, we determine whether the contract, for accounting purposes, is a multiple element arrangement, meaning it contains both a lease element and a drilling services element, and, if so, identify all deliverables (elements). For each element we determine how and when to recognize revenue.

Term contracts:These are contracts pursuant to which we agree to operate the unit for a specified period of time. For these types of contracts, we determine whether the arrangement is a multiple element arrangement. For revenues derived from contracts that contain a lease, the lease elements are recognized as “Leasing revenues” in the statement of operations on a basis approximating straight line over the lease period. The drilling services element is recognized as “Service revenues” in the period in which the services are rendered at fair value rates. Revenues related to the drilling element of mobilization and direct incremental expenses of drilling services are deferred and recognized over the estimated duration of the drilling period.

Well contracts:These are contracts pursuant to which we agree to drill a certain number of wells. Revenue from dayrate based compensation for drilling operations is recognized in the period during which the services are rendered at the rates established in the contracts. All mobilization revenues, direct incremental expenses of mobilization and contributions from customers for capital improvements are initially deferred and recognized as revenues over the estimated duration of the drilling period.

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

References in this section to “the Partnership,” “we’, “us” and “our”, in each case for the periods and of the dates indicated, are of the Ocean Rig partners LP Predecessor, which includes the subsidiaries of Ocean Rig that have interests in the drillships in OPCO’s initial fleet and the associated service companies.

	Year Ended December 31, 2012			Year Ended December 31, 2013			Change			Percentage Change
REVENUES:
Total revenues	$	—		$	37,325		$	37,325			—
EXPENSES:
Drillships operating expenses		—			13,576			13,576			—
Depreciation expense		—			11,740			11,740			—
General and administrative expenses		6,720			25,827			19,107			284.3	%
Operating loss		(6,720	)		(13,818	)		(7,098	)		105.6	%
OTHER INCOME/(EXPENSES):
Interest and finance costs		(3	)		(21,022	)		(21,019	)		700633.3	%
Interest income		—			90			90			—
Gain/(Loss) on interest rate swaps		(3,674	)		8,510			12,184			(331.6	)%
Other, net		(219	)		613			832			(379.9	)%
Total other expenses, net		(3,896	)		(11,809	)		(7,913	)		203.1	%
Loss before income taxes		(10,616	)		(25,627	)		(15,011	)		141.4	%
Income taxes		—			—			—			—
Net Loss	$	(10,616	)	$	(25,627	)	$	(15,011	)		141.4	%

Revenues

Revenues from drilling contracts increased by $37.3 million, to $37.3 million for the year ended December 31, 2013, as compared to $0 million for the year ended December 31, 2012 primarily due to the delivery ofOcean Rig Myloson August 19, 2013 and its commencement of operations on November 4, 2013. $2.1 million of the increase is attributable to the equipment testing of theOcean Rig Skyros which was delivered on December 20, 2013 and commenced operations on March 2, 2014, while the remaining increase of $0.7 million is attributable to the recharges under contract terms, for the construction ofOcean Rig Athena, which was delivered on March 24, 2014.

Drillships Operating expenses

Drillships operating expenses increased by $13.6 million, to $13.6 million for the year ended December 31, 2013, compared to $0 million for the year ended December 31, 2012. The increase in operating expenses was due to the addition of the Ocean Rig Mylos and the Ocean Rig Skyros to OPCO’s Initial Fleet which resulted in operating expenses.

Depreciation expense

Depreciation expense increased by $11.7 million, to $11.7 million for the year ended December 31, 2013, as compared to $0 million for the year ended December 31, 2012. The increase in depreciation expense was attributable to the depreciation expense ofOcean Rig Mylos andOcean Rig Skyros, which were added to the OPCO’s Initial Fleet.

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General and administrative expenses

General and administrative expenses increased by $19.1 million, or 284.3%, to $25.8 million for the year ended December 31, 2013, as compared to $6.7 million for year ended December 31, 2012. This increase is mainly due to increased costs for the operation of offices in Athens and Angola and increased consultancy fees.

Interest and finance costs

Interest and finance costs increased by $21.0 million, to $21.0 million for year ended December 31, 2013, compared to $0 million for the year ended December 31, 2012. The increase is due to increased interest expense of long term debt and other financial expenses as a result of the $1.35 billion senior secured facility we entered into in February 2013.

Gain/ (Loss) on interest rate swaps

Gains on interest rate swaps increased by $12.2 million, or 331.6%, to $8.5 million for year ended December 31, 2013, as compared to a $3.7 million loss for the year ended December 31, 2012. The gain for the year ended December 31, 2013 was mainly due to mark-to-market gains of outstanding swap positions.

Other, net

Other, net increased by $0.8 million, or 400.0% to a gain of $0.6 million for year ended December 31, 2013, compared to a loss of $0.2 million for the year ended December 31, 2012. The increase is mainly due to foreign currency exchange rate differences.

B. Liquidity and Capital Resources

As of December 31, 2013, we had $50.0 million of restricted cash relating to minimum cash required under the $1.35 billion senior secured facility we entered into in February 2013. Our restricted cash balances as of December 31, 2013 increased by $44.0 million, or 733.3%, to $50.0 million, compared to $6.0 million as of December 31, 2012. The increase in restricted cash balances was primarily increased due to the classification of $50.0 million as restricted cash under the terms of our credit facility which was partly offset by the release of $6.0 million upon delivery of theOcean Rig Mylos and theOcean Rig Skyros.

As of December 31, 2013, we had $6.1 million of cash and cash equivalents. Our cash and cash equivalents increased by $4.6 million, or 318.9%, to $6.1 million as of December 31, 2013, compared to $1.5 million as of December 31, 2012. The increase in our cash and cash equivalents relates mainly to the receipt of $900.0 million in gross proceeds from our Senior Secured Facility and net cash provided by operating activities of $83.4 million, which were partly offset by payments of yard installments and other related construction costs and drillship machinery and equipment amounting to $950.0 million in aggregate and loan repayments amounting to $10.0 million in the aggregate. Our total indebtedness as of December 31, 2013 increased to $890.0 million, compared to $0 million as of December 31, 2012 due to the $1.35 billion senior secured facility entered in February 2013, which was partly offset by scheduled loan repayments made during 2013.

As of December 31, 2013, we had $450.0 million available borrowing capacity under the Existing Senior Secured Loan Facility outstanding of $890.0 million. As of December 31, 2013, we were in compliance with all covenants related to our outstanding debt agreement. Please refer to the discussion on Long-term Debt as detailed in Note 8 of our audited combined carve-out financial statements.

As of December 31, 2013, our total purchase commitments consisted of the remaining construction expenses of approximately $365.6 million relating to the construction of our seventh generation drillship under construction, which was delivered in March 2014. As of December 31, 2013, we have made pre-delivery payments of

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$242.1 million in the aggregate for the newbuilding drillship. The remaining total construction payment for this drillship, excluding financing costs, amounted to approximately $365.6 million as of December 31, 2013. We used the available borrowings to partially finance the acquisition of our seventh generation drillship which was delivered in March 2014.

Working capital is defined as current assets minus current liabilities (including the current portion of long-term debt). Our working capital deficit amounted to $96.3 million as of December 31, 2013, as compared to a working capital surplus of $9.5 million as of December 31, 2012. Working capital deficit as of December 31, 2013, as compared to December 31, 2012, was primarily due to part of our long term debt falling due within a year and deferred revenue of $47.5 million.

Our internally generated cash flow is directly related to our business and the market sectors in which we operate. Should the drilling market deteriorate, or should we experience poor results in our operations, cash flow from operations may be reduced. As of December 31, 2013, assuming the drilling or financing markets do not deteriorate, we believe that our current cash balances and operating cash flow, together with the proceeds of any debt or equity issuances in the future, will be sufficient to meet our liquidity needs for the next 12 months, including minimum cash requirements under our secured credit facilities, under which $82.1 million is due in 2014 and our newbuilding contract, under which approximately $365.6 million is due in 2014. Our access to debt and equity markets may be reduced or closed due to a variety of events, including a credit crisis, credit rating agency downgrades of our debt, industry conditions, general economic conditions, market conditions and market perceptions of us and our industry.

The New Senior Secured Term Loan Facility

On February 28, 2013, DOV I, as borrower, entered into a facilities agreement with, inter alia, DNB Bank ASA, as facility agent and security trustee, for up to $1.35 billion to fund a portion of the purchase price of OPCO’s Initial Fleet, or the Existing Senior Secured Loan Facility.

Ocean Rig, DOV I and a financing subsidiary of DOV I, or the “Borrowers,” expect to enter into the New Senior Secured Term Loan Facility that will initially provide for a $1.3 billion of senior secured term loan and optional revolving credit obligations not exceeding $50 million. The New Senior Secured Term Loan Facility also will provide that, at the discretion of the lenders and subject to certain conditions and limitations, including the entering of definitive amendments, the Borrowers may add (1) one or more incremental term loan facilities in an aggregate principal up to $150.0 million and (ii) a revolving credit facility. The proceeds from the New Senior Secured Term Loan Facility together with cash on hand will be used to refinance the Existing Senior Secured Loan Facility.

The New Senior Secured Term Loan Facility will have a maturity date in the third quarter of 2021. Borrowings under the New Senior Secured Term Loan Facility will bear interest at the applicable margin to the either the base rate or the Eurodollar rate, as applicable, provided in accordance with the New Senior Secured Term Loan Facility.

The New Senior Secured Term Loan Facility will be fully and unconditionally guaranteed by our Sponsor and certain issuer subsidiary guarantors. The guarantee by our Sponsor will be automatically released upon the consummation of this offering. The New Senior Secured Term Loan Facility will be secured, on a first priority basis by a security interest in theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena and a pledge of certain other assets of DOV I and certain of its subsidiary guarantors, subject to certainexceptions.

The proceeds from the New Senior Secured Term Loan Facility, together with cash on hand, will be used to refinance the outstanding amounts under the Existing Senior Secured Loan Facility and to pay related fees and expenses. The entry into the New Senior Secured Term Loan Facility is subject, among other things, to the negotiation and execution of definitive documentation.

In connection with the closing of this offering, OPCO, through DOV II, will assume the debt of DOV I under the New Senior Secured Term Loan Facility and our Sponsor will be unconditionally released as guarantor under the New Senior Secured Term Loan Facility.

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The New Senior Secured Term Loan Facility will contain customary covenants, including restrictive covenants, which include restrictions on, among other things, (i) our ability to enter into affiliate transactions, (ii) the creation of liens on our assets, (iii) mergers or consolidations without the prior consent of the lenders, (iv) the sale, lease, transfer or other disposition of the collateral securing the facility other than for market value on an arm’s length basis and in compliance with the terms of the facility, (v) the incurrence of additional indebtedness and (vi) the making of additional investments.

In addition, the New Senior Secured Credit Agreement will restrict our ability to pay dividends or make other distributions in respect of our capital stock . Such restrictions will change depending on, among other things, whether this offering has been consummated, certain financial tests, and the cash available (as calculated in accordance with the New Senior Secured Term Loan Facility).

The New Senior Secured Term Loan Facility will require that DOV meet certain financial tests, including that its Consolidated Net Leverage Ratio (as defined in the New Senior Secured Term Loan Facility) as of the last day of any period of four consecutive fiscal quarters (each, a “Test Period”) shall not exceed (i) the ratio of 5.50:1.00 for each such Test Period up to and including the Test Period ending with the fiscal quarter ending December 31, 2015, and (ii) 5.00:1.00 for each such Test Period thereafter.

The New Senior Secured Term Loan Facility will contain customary events of default, including non-payment of principal or interest, breach of covenants or material representations and bankruptcy and imposes insurance requirements and restrictions on the employment of the mortgaged drillships. In addition, the New Senior Secured Term Loan Facility will contain a cross-default provision that is triggered, when any of our other financial indebtedness is not paid when due or is declared to be, or otherwise becomes, due and payable prior to its specified maturity as a result of an event of default and in each case such amount equals or exceeds $25.0 million. In these situations our lenders may accelerate our indebtedness under the New Senior Secure Term Loan Facility.

Cash Flows

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

Our cash and cash equivalents increased to $6.1 million as of December 31, 2013, compared to $1.5 million as of December 31, 2012, primarily due to cash provided by financing and operating activities partly offset by cash used in investing activities. Our working capital deficit was $96.3 million as of December 31, 2013, compared to a $9.5 million working capital surplus as of December 31, 2012.

Net Cash Provided by Operating Activities

Net cash provided by operating activities was $83.4 million for the year ended December 31, 2013. In determining net cash provided by operating activities for the year ended December 31, 2013, net loss was adjusted for the effects of certain non-cash items, including $11.7 million of depreciation, $0.7 million of amortization of deferred financing costs and general and administrative expenses which were allocated from other subsidiaries of Ocean Rig UDW to the Partnership, amounting to $19.1 million. Moreover, for the year ended December 31, 2013, net loss was also adjusted for the effects of non-cash items, such as the gain in the change in fair value of derivatives of $9.4 million compared to a loss in the change in fair value of $3.7 million as at December 31, 2012. The Partnership had net cash inflows of $139.9 million relating to the increase in deferred revenue, $55.1 million attributable to the increase in accrued liabilities and $36.9 million due to the increase in accounts payable and other liabilities. These cash inflows were partly offset by the increase in trade account receivables by $93.4 million and the increase of 51.6 million of other assets. Net cash used in operating activities was $3.8 million for the year ended December 31, 2012.

Net Cash Used in Investing Activities

Net cash used in investing activities was $989.7 million for the year ended December 31, 2013, compared to $45.3 million for the year ended December 31, 2012. We made expenditures related to drillships under

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construction and drillships, machinery and equipment of approximately $945.7 million for the year ended December 31, 2013, compared to $ 39.3 million for shipyard payments for the year ended December 31, 2012. The increase in restricted cash was $44.0 million during the year ended December 31, 2013, compared to an increase of $6.0 million in the corresponding period of 2012.

Net Cash Provided by Financing Activities

Net cash provided by financing activities was $911.0 million for the year ended December 31, 2013, consisting of proceeds from the $1.35 billion Senior Secured Facility amounting to $900.0 million and increase in invested equity amounting to $43.6 million which were partly offset with repayments of our credit facility amounting to $10.0 million and payments of financing fees amounting to $22.6 million.

Swap Agreements

As of December 31, 2013, we had 3 interest rate swap and cap and floor agreements outstanding, with a notional amount of $1.2 billion, maturing from July 2017 through October 2017. These agreements were entered into in order to economically hedge our exposure to interest rate fluctuations with respect to our borrowings. As of December 31, 2013, the aggregate fair value the above agreements was a net asset of $5.7 million. This fair value equates to the amount that would be receivable from us if the agreements were cancelled at the reporting date, taking into account current interest rates and our creditworthiness.

As of December 31, 2012, we had three interest rate swap and cap and floor agreements outstanding, with a notional amount of $1.2 billion, maturing from July 2017 through October 2017. These agreements were entered into in order to economically hedge our exposure to interest rate fluctuations with respect to our borrowings. As of December 31, 2012, the aggregate fair value the above agreements was a net liability of $3.7 million.

As of December 31, 2012, a security deposit of $6.0 million was provided as security by the Partnership. This amount was released upon the delivery ofOcean Rig Mylos andOcean Rig Skyroson August 19, 2013 and December 20, 2013, respectively.

Contractual obligations

The following table sets forth our contractual obligations and their maturity dates as of December 31, 2013:

Obligations	Total		Less than 1 year		1-3 years		3-5 years
(U.S. Dollars in thousands)
Drillship under construction(1)		365,609		365,609		—		—
Loan payments		890,000		82,105		164,210		643,685
Interest payments(2)		182,036		43,534		81,893		56,609
Total		1,437,645		491,248		246,103		700,294

(1) The figure includes contracted purchase obligations only.

(2) Based on assumed interest rate of 5.48%.

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THE OFFSHORE DRILLING INDUSTRY

All the information and data presented in this section, including the analysis of the various sectors of the offshore drilling industry has been provided by Drewry Maritime Research, or Drewry, an independent consulting and research company. Drewry has advised that the statistical and graphical information contained herein is drawn from its database and other sources. In connection therewith, Drewry has advised that: (a) certain information in Drewry’s database is derived from estimates or subjective judgments; (b) the information in the databases of other maritime data collection agencies may differ from the information in Drewry’s database; (c) while Drewry has taken reasonable care in the compilation of the statistical and graphical information and believes it to be accurate and correct, data compilation is subject to limited audit and validation procedures.

Deepwater Market Overview

The current market for offshore drilling units is characterised by strong demand for deepwater and ultra-deepwater rigs, with multiple new building orders for drillships and semisubmersibles to meet both rising demand and the need to replace an aging and increasingly obsolete fleet.

High energy demand and oil prices consistently above $100 per barrel have stimulated growing capital expenditure on exploration and Production (E&P) activity, which is turn, has led to increased offshore activity, as many onshore oil and gas fields are reaching a stage of maturity. As such, a large part of future offshore capital expenditure is expected to be directed to deepwater and ultra-deepwater locations. Deepwater in this context means water depths in excess of 750 feet.

Offshore oil and gas drilling is moving towards the exploration of more complex reservoirs located further offshore and into deeper and more challenging environments as energy companies seek to discover new sources of production in low-risk areas. Producers are potentially incentivized in part by the prospect of significant discoveries of large recoverable reserves and attractive economies of scale with the ability to produce profitably, even in high production cost areas.

To meet the growing demand for offshore drilling, the size of the global fleet has increased. As of April 2014 the fleet of jackup rigs, semisubmersibles and drillships consisted of 849 units, of which 526 units are jackups, 220 semisubmersibles and 103 drillships. Semisubmersibles and drillships in this context are collectively referred to as the “floater” fleet. The ultra-deepwater fleet (drillships and semisubmersibles capable of drilling in water depths in excess of 7,500 feet) is comprised of 157 units, of which 84 are drillships and 73 semisubmersibles.

The floater fleet has been subject to a number of building booms over the last four decades and in the period from 2004 to 2014 increased in size by a compound average growth rate (CAGR) of 6%.

The Offshore Floater Fleet—April 2014

Type	Current Fleet No		Average Age Years		Orderbook No		Orderbook % Existing Fleet
Semisubmersible		220		24.0		28		12.7
Drillship		103		9.9		69		67.0
Total		323		19.4		97		30.0

Source: Drewry

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The stop-start nature of newbuilding activity has left the age profile of the floater fleet heavily polarised at both ends of the age spectrum. The average age of the floater fleet in April 2014 was 19.4 years, but almost 46% of the floater fleet is over 25 years of age. Conversely, some 29% of the fleet is less than 5 years of age. The average age of the ultra-deepwater fleet is 6.7 years.

As of April 2014, in total 97 floaters were on order, equivalent to 30.0% of the existing floater fleet. Orders for new drilling rigs have been driven by a combination of rising demand for offshore drilling services driven by oil & gas companies’ E&P programs; increasingly stringent safety regulations; the need to replace obsolete existing units and the technological complexity dictated by moving into deeper water and harsher environments. Delivery of the newbuilding units on order is spread out over the remainder of the decade.

There is a strong correlation between oil prices and orders for new rigs, as high oil prices increase the viability of exploration and development of technically challenging reserves.

Demand for offshore drilling units is largely a function of the number of offshore wells drilled, and in the period 2004 to 2014 the number of wells drilled in water depths of 400 feet or more is provisionally estimated to have increased by a CAGR of 6.6%.

Number of Floater Wells Drilled (>400 ft) 2004-2014⁽¹⁾

(1) Preliminary assessment

Source: Drewry, Industry Estimates

Demand for rigs capable of drilling in deep and ultra-deepwater is currently high as a result of increased spending on E&P by oil and gas companies in offshore locations. As the industry moves further offshore and into more challenging environments, larger and more technically advanced assets will be required. There is a backlog in developing existing deepwater reserves and also an expectation that future offshore discoveries will be in deeper and more technically challenging locations than those discovered to date. This implies increased demand for deepwater drilling and there is an expectation in the industry of a rise in the number of exploration and appraisal wells that will need to be drilled. In addition, much more drilling capacity will be required per well given the increasing complexity of deepwater and ultra-deepwater drilling.

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Utilization levels in high-end ultra-deepwater rigs capable of drilling in water depths in excess of 7,500 feet were above 90% in April 2014. In lower capability units, utilization levels were less, but for floaters as whole utilization levels remain quite high. Furthermore, any spare capacity which exists in the floater fleet tends be to located in older and less technically capable units, most of which are not suitable for deepwater and ultra-deepwater drilling.

The Floater⁽¹⁾ Fleet—Utilization and Dayrates

(1) Semisubmersibles and Drillships

Source: Drewry

One important effect of high utilization rates has been improved unit earnings. In April 2014 dayrates for semisubmersibles (>1,500 ft) were approximately $345,000 per day, with average earnings in the period between 2010 and 2014 of approximately $346,000 per day. For high end drillships (>4,000 ft) the April 2014 dayrate was just over $500,000 per day, compared with an average of $465,000 per day in the period between 2010 and 2014. Dayrates for ultra-deepwater units were even higher, and were in excess of $600,000 per day in parts of 2013 and 2014.

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Indicative Floater Dayrates (>7,500 ft): 2004 to 2014

(US$ Per Day)

Period Average	Deepwater		Ultra- deepwater
2004		230,000		137,000
2005		430,000		300,000
2006		475,000		480,000
2007		510,000		520,000
2008		550,000		560,000
2009		470,000		640,000
2010		430,000		525,000
2011		457,000		445,000
2012		460,000		515,000
2013		477,200		610,000
2014(1)		501,000		615,000
Averages
2004-2014		453,655		486,091
2010-2014		465,040		542,000
2012-2014		479,400		580,000

(1) January to April

Source: Drewry

One consequence of a tighter market has been an increase in the length of contract terms, although the maximum duration of contracts has been approximately three years, as most exploration and production companies have been reluctant to commit to high rates for long periods. Furthermore, although rates in the various deepwater segments have been almost parallel in the past, operators tend to see added value in newer and more capable units with higher capacities for deepwater requirements, both for exploration (which is spreading to more remote areas and deeper waters) and for technically challenging developments. This trend is expected to become even more pronounced in the years ahead.

Offshore Market Fundamentals

Introduction

Oil and gas remain the world’s primary energy sources, collectively accounting for approximately 70% of global energy demand. The first offshore oil well was drilled in the Gulf of Mexico in 1947, but it was not until the 1960s that production from offshore oil fields began to have an impact, initially in the Arabian Gulf and Gulf of Mexico, and later in the North Sea and other regions of the world. As a result, oil production from offshore oil and gas fields has increased rapidly, and oil produced offshore now accounts for approximately one-third of global oil supply.

One important consequence of the geographical spread in offshore oil and gas production has been the move into deeper and harsher waters, which in turn has increased demand for new technology and new equipment. Deepwater oil and gas production is important, because with the possible exception of the Middle East and Russia, it probably represents the only real option for large scale additions to oil and gas reserves.

As the world’s oil and gas producers have turned their attention to deeper and more inhospitable waters, demand for high capability floaters has also risen. Demand for floaters is not only a function of the number of wells being drilled, but also the location and type of drilling required. Improved technology has led to more complex wells being drilled, which usually requires longer drilling periods, which has resulted in additional demand for drilling units.

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Structure of the Offshore Industry

The offshore oil and gas industry consists of the following key business activities:

• Survey

• Exploration

• Development/Construction

• Production

• Well Maintenance and Upgrading

Each of these activities tends to be distinct by virtue of life cycles, technology, assets required and expertise. Offshore drilling is part of the Exploration and Development/Construction phases, although additional drilling is sometimes part of Well Maintenance and Upgrading. Offshore markets tend to be regional in nature and often with high regulatory barriers to entry, where technology is a critical driver.

Direct drivers of the offshore market include trends in the world economy and oil and gas prices, with other key influences being oil and gas consumption patterns and growth rates, production and reserve replacement ratios and government policies.

To develop offshore oil and gas fields; investment is required in exploration, production, storage, transportation and associated support facilities. Some of the technological solutions that have been put in place to exploit oil and gas located in deep water harsh environments include:

• Semi-submersible drilling units and drillships;

• Floating production systems;

• Shuttle tankers; and

• Sub-sea installations.

The actual system that is used to develop an offshore oil or gas field will depend on a number of factors, including water depth, the size and content of the oil or gas field and geography. Once seismic surveys confirm the presence or possibility of hydrocarbons present in the region, the next step taken is the drilling of an exploratory well to confirm the available amount of hydrocarbon present and the nature, properties and commercial viability of the hydrocarbons reserve. If the results of an exploratory drilling are satisfactory, then developmental wells are drilled. The amount of resources used, in terms of drilling units and offshore logistics, in developmental drilling are greater than those used in exploratory drilling.

Offshore Regions

Offshore activity occurs in many regions of the world. The key areas for deep and ultra-deepwater development are Brazil, West Africa, the Gulf of Mexico (collectively often referred to as the Golden Triangle), the North Sea and South East Asia. However, in recent years many areas have seen increased demand for offshore drilling, including China, New Zealand and East Africa. The main offshore regions are shown in the map below.

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The Main Offshore Regions of the World

Source: Drewry

Water Depths

There is no industry standard definition of water depths, but within the context of this prospectus, water depths are defined as follows:

• Shallow water: drilling in water depths up to 400 feet.

• Deepwater: drilling in water depths from 400 to 7,500 feet.

• Ultra-deepwater: drilling in water depths from 7,500 feet to 12,000 feet.

Regionally, South America (Brazil), West Africa and the US Gulf of Mexico are driving deepwater growth, with Western Europe remaining an important but smaller sector.

Types of Drilling Rigs

Drilling rigs within the context of this report are defined as jackups, semisubmersibles and drillships. Semisubmersibles and drillships are collectively known as “floaters”, because they often float on water and are not secured to the sea floor. The floater fleet can be further divided between deepwater rigs (from 400 and up to 7,500 feet drilling capability) and ultra-deepwater rigs (drilling capability up to 12,000 feet).

Principal Types of Offshore Drilling Rig

Source: Drewry

Jackups

Jack-up rigs stand on the sea floor with their hull and drilling equipment elevated above the water on three or four connected leg supports. In order to move from one location to another the rig can lower its platform down

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onto the water until it floats and it will then be towed by a supply vessel to its next location, where the legs will be lowered to the sea floor and the platform elevated above the sea level. Jack-up rigs are generally preferred over other rig types in water depths of 400 feet or less primarily because they provide a more stable drilling platform with above water blow-out prevention. High end jack-up rigs are normally defined as rigs capable of drilling in water depths of 400 feet or more and are of independent leg design. A modern jack-up rig will normally have the ability to move its drill floor aft of its own hull (cantilever), in order that multiple wells can be drilled in open water locations or over wellhead platforms without repositioning the rig.

Semisubmersibles

Semisubmersible rigs are floating offshore drilling units with pontoons and columns that, when sea water is permitted to enter, cause the rig to partially submerge to a predetermined depth/and survival draft when drilling operations are underway. Dynamically positioned (DP) semisubmersible rigs are held in a fixed location over the ocean floor by computer controlled propellers or thrusters, while non DP units use conventional mooring systems consisting of anchors and chains and/or cables. The propulsion capability of a semisubmersible may range from having i) no propulsion, ii) propulsion assistance and iii) being completely self-propelled, which means the rig has the ability to relocate independently of a towing vessel. The first semisubmersibles entered service in the early 1970s and since there have been a number of developments in rig design. Most modern semisubmersible units possess the capability to operate in water depths in excess of 10,000 feet. In addition, the hull design of semisubmersible units allows them to operate in adverse weather conditions.

Drillships

Drillships are maritime vessels with a normal hull structure which have been outfitted with drilling apparatus. They are often used for exploratory and development drilling of new oil and gas wells in deep to ultra-deep waters, although they can also be used as platforms to carry out well maintenance or completion work such as casing and tubing installation or subsea tree installations. Drilling takes place via openings in the hull which are known as “moon pools”. Drillships are capable of drilling in ultra-deepwater of up to 12,000 feet, with vertical drilling depths of up to 40,000 feet. They normally have a higher load capacity than semisubmersibles and are well suited to drilling in remote areas due to both load capacity and mobility. Drillships can be equipped with conventional mooring systems or dynamic positioning (DP) systems.

Oil and Gas Consumption and Prices

Two primary factors will continue to influence energy demand – population and economic growth. The world’s population is expected to rise to 8 billion by 2030, with some 90% of this growth to occur in the non-OECD world. A growing population and continued growth in the world economy will continue to drive energy demand upwards and new sources of oil and gas supplies will need to be found.

The chart below shows the latest projection of oil supply through to 2040 from the International Energy Agency (IEA). By 2040 the IEA anticipates that oil and gas will supply approximately 60% of world energy demand and that sustained growth in oil and gas supply will be required to meet this commitment. The chart below highlights the expected contribution of deepwater oil to overall oil supply over this period. Given that it is recognised that the scope for developing onshore resources is quite limited, much of this new oil will have to come from offshore locations and the IEA projections point to rising supplies from deepwater locations. To meet this demand oil companies will need to spend more on E&P in waters which will be more rig intensive than onshore and shallow water locations.

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World Oil Supply to 2040

(Million Barrels Per Day)

Source: IEA

The anticipation of increased demand for energy is placing pressure to discover larger oil and gas reserves every year to ensure replacement and to delay the point at which peak reserves start to diminish. Oil prices are an important factor in the process of exploring and finding new oil and gas reserves. Since 2006, oil prices have been volatile, but have remained at relatively high levels. In the period 2010 to 2014 the average price of North Sea Brent crude oil was just over $100 per barrel. Spending on E&P programmes is closely linked to oil and gas company earnings and high oil prices are an important factor in company results.

In a relatively high oil price environment there is increased investment in E&P by oil and gas producers and greater emphasis on developing unexplored potential reserves. In this context a recent report from major financial institution suggest that worldwide expenditure on offshore E&P will rise by 6% between 2013 and 2014 to over $720 billion. It will also be the fifth straight year of growth. Furthermore, a large part of this expenditure is scheduled to take place in deepwater and ultra-deepwater locations.

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Brent Oil Price 1990-2014

(US$ Per Barrel)

Source: Drewry

Developing new sources of oil and gas is important as energy use in countries such as China and India is growing rapidly. Some estimates suggest that China and India alone will account for in excess of 40% of the total world increase in oil demand in the next decade. Oil production continues to rise to meet the underlying trends in oil consumption and an increasing proportion of total supplies is being met by offshore resources. The chart below shows the trend in global oil production between 1970 and 2013 and the relative split between onshore and offshore supplies. During this period, production from offshore fields increased by a CAGR of 4%, whereas for onshore production the CAGR was 1%.

World Oil Production 1970-2014

(Million Barrels Per Day)

Source: Drewry

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Offshore Drilling Rig Markets

The offshore drilling rig market can be divided into three sectors based on rig type and in turn between shallow water, deepwater and ultra-deepwater locations.

The Offshore Drilling Rig Market

Source: Drewry

Drilling in shallow water is undertaken by jackups and drill barges whereas in deepwater and ultra-deepwater, semisubmersibles and drillships are used.

The marketable supply of rigs at any given point in time is a function of the size of the existing fleet, less units which are undergoing repair or upgrading, and units which are stacked. However, total rig supply comprises of both the active fleet, plus stacked units and those undergoing repair or upgrading, as they form part of the fleet which can be put into operation if demand rises. For the purposes of this analysis Drewry has considered stacked units to be part of the total fleet. Fleet size describes the total number of rigs in a given class and is normally further sub divided by water depth capability.

Demand is expressed in terms of the active fleet, that is, units which are either drilling or in transit to a drilling location. The relationship between supply and demand is known as utilization, and is a measure based on the number of drilling rigs at a given point in time to the available fleet within a specific region. Drilling capacity is not entirely fixed as companies can add rigs through newbuilding and relocation to respond to higher demand and also idle rigs during period of weak demand. Adding new rigs can however take several years as newbuilding capacity in the rig sector is somewhat limited, but once delivered rigs tend to have useful lives in excess of 25 years. Idling units, or stacking as it is sometimes known can be undertaken relatively quickly, and is used to help match supply with demand and therefore support dayrates.

Dayrates depend on multiple factors including the country and region of operation, water depth, rig capabilities and technical specifications, contract length, as well as the fleet’s utilization rate. Dayrates are a good indicator of market conditions as a whole.

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The number of offshore drilling companies has varied over time and in 2014 there were approximately 100 different owners/operators. Around 50% of the fleet is owned by a small group of companies which include Transocean, Noble, Ensco, Seadrill, Diamond Offshore and our Sponsor. The principal oil companies operating rigs are Petrobras, Statoil, Shell, BP, Total, Chevron, Anadarko, ONGC, Eni, Exxon Mobil and Pemex.

The Floater Market

The following analysis focuses on the semisubmersible and drillship markets or “floaters”; and in particular on the ultra-deepwater sector, which in this context is defined as units also capable of drilling in water depths in excess of 7,500 feet.

Existing Rig Supply and Orderbooks

In April 2014 the overall floater fleet consisted of 323 units with a further 97 units in order, equivalent to 30% of the existing fleet. The existing fleet is split between 220 semisubmersibles and 103 drillships. By water depth capability the existing fleet is split roughly 50:50 between units with water drilling capability up to 7,500 feet and the ultra-deepwater fleet also capable of drilling in water depths in excess of 7,500 feet. In the ultra-deepwater fleet the approximate split between semisubmersibles and drillships is 40:60.

The Floater Fleet & Orderbook: April 2014

(Number of Units)

Water Depth—Capability (ft)	Current Fleet		Scheduled Deliveries—No.														Total		Orderbook
	No.		2014		2015		2016		2017		2018		2019		2020		Orderbook		% Fleet
<7,499—Deepwater		166		5		3		5		3								16		9.6	%
>7,500—Ultra-deepwater		157		22		21		18		8		7		4		1		81		51.6	%
Total		323		27		24		23		11		7		4				97		30.0	%

Source: Drewry

Given the general move into deeper and harsher environments, the bulk of the existing orderbook is for units capable of drilling in water depths of 7,500 feet. In the ultra-deepwater sector there are currently 81 units on order, equivalent to 51% of the existing fleet. Based on scheduled deliveries a further 22 ultra-deepwater units are due to be delivered between May and December 2014, 21 units in 2015 and 18 units in 2016. The remaining deliveries are spread out to 2020. Assuming no deletions and that units are delivered on time, supply in the ultra-deepwater sector will rise by just under 39% by the end of 2016. Quite possibly the increase in supply will have a dampening on day rates in the short term, but in the long term demand outlook for ultra-deepwater units at the present time remains relatively robust.

Of the 81 units on order, 65 are drillships and 16 semisubmersibles. Overall the orderbook reflects a growing popularity for drillships which have somewhat greater flexibility than semisubmersibles. The focus of ordering in this sector is further testament to the move by the offshore industry into deep and ultra-deepwater and into harsher environments. It also illustrates the growing popularity of drillships over semisubmersibles.

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Age Profile

The age profile of the fleet reflects the fact that fleet development has taken place in “stages” and some 29% of the current floater fleet is less than 5 years old.

The Floater Fleet Age Profile: April 2014

	No of Units
Type	< 5 Yrs			5-9 Yrs			10-14 Yrs			15-19 Yrs			20-25 Yrs			25+ Yrs			Total
Drillship		57			10			10			6			0			20			103
Semisubmersible		37			23			16			11			3			130			220
Total		94			33			26			17			3			150			323
% of Total		29.1	%		10.2	%		8.0	%		5.3	%		0.9	%		46.4	%

Source: Drewry

The fleet is often divided into 2nd, 3rd, 4th, 5^th, 6^th and 7th generation units and the drilling capability of each generation has naturally improved over time. The age profile of the ultra-deepwater fleet is therefore quite young, with the average age of units currently in service being 6.5 years.

The Ultra-deepwater Drilling Rig Fleet—Age Profile: April 2014

(Number of Units)

Source: Drewry

Rig Demand and Employment

Overall, utilization levels have remained quite high since 2007 as a result of the steady increase in the number of offshore wells drilled.

Utilization levels for ultra-deepwater units in April 2014 were 85%, compared with 67% for rigs capable of drilling in water depths up to 7,500 feet.

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The Floater Fleet: Activity Status: April 2014

(Number of Units)

Water Depth Capability (ft)	Current Fleet		Active Fleet (Drilling)		Current Utilization - %
<7,499		166		111		67	%
>7,500		157		134		85	%
Total		323		245		76	%

Source: Drewry

In the ultra-deepwater sector if other activities (such as work-over and en-route to employment) are taken into account current utilisation levels are running well in excess of 90%. Only 2% of the existing ultra-deepwater fleet is ready stacked and idle, but waiting for employment.

The Ultra-deepwater Drilling Rig Fleet—Activity Status: April 2014

(Based on Number of Units)

Source: Drewry

Overall, deepwater and ultra-deepwater markets have proved to be less prone to cyclical fluctuations than the shallow water floater segments, and as a result activity levels and unit earnings have been more stable.

The fleet is deployed in a large number of regions across the world, but in April 2014 the key areas providing employment were Brazil, the North Sea, the Gulf of Mexico, West Africa and South East Asia.

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The Floater Fleet by Location: April 2014

(Number of Units)

	Water Depth Capability (ft)
Location	<7,499		>7,500		Total
West Africa		14		38		52
Rest of Africa		4		3		7
Caspian		7				7
Far East Asia		7		2		9
South Asia		8		4		12
South East Asia		21		5		26
Australia		8		4		12
Black Sea				1		1
East Europe				1		1
North Sea		40		8		48
Mediterranean		8		1		9
Red Sea				1		1
Canadian Atlantic		1		1		2
Mexico		2		4		6
US GoM		13		43		56
Brazil		30		41		71
Caribs		1				1
Venezuela		2				2
Total		166		157		323

Source: Drewry

In the ultra-deepwater the key employment region is the so called “Golden Triangle” with 78% of the total active fleet currently working in Brazil, the US Gulf of Mexico and West Africa.

The Ultra-deepwater Drilling Rig Fleet by Location: April 2014

(Based on Number of Units)

Source: Drewry

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Utilization and Dayrates

In the ultra-deepwater sector total supply has grown from 25 units at the start of 2000 to 157 units in April 2014. With the exception of 2004 utilization across the sector has been at or in excess of 90% for the last decade and this has had a beneficial impact on dayrates.

The Ultra-deepwater Fleet Summary

(Number of Units)

Year	Fleet Start Year		Deliveries		Deletions		Fleet End Year		Average Fleet		Demand		Utilization %			Dayrates(1) US$ Per day
2004		42		0		0		42		42		38		90	%		137,000
2005		42		3		0		45		44		39		92	%		300,000
2006		45		0		0		45		45		42		93	%		480,000
2007		45		1		0		46		46		43		96	%		520,000
2008		46		8		0		54		50		45		97	%		560,000
2009		54		21		0		75		65		52		97	%		640,000
2010		75		21		1		95		85		72		96	%		525,000
2011		95		27		0		122		109		87		92	%		445,000
2012		122		19		2		139		131		116		95	%		515,000
2013		139		18		0		157		148		133		96	%		610,000
2014(2)		157		29		0		186		172		141		90	%		615,000

(1) Ultra-deepwater rates.

(2) 2014 includes units scheduled to be delivered in year

Source: Drewry

With high utilization rates, dayrates for ultra-deepwater units have risen from $300,000 per day in 2005 to in excess of $600,00 per day in 2013 and 2014.

The Ultra-deepwater Fleet—Utilization and Dayrates: 2004-2014

Source: Drewry

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Utilization levels among this relatively small fleet have been consistently high throughout the period, and at times have been close to 100%. In effect, the fleet has enjoyed more or less full employment.

SUMMARY OF CERTAIN INDUSTRY TERMS

Generations

Although there are no agreed industry standard definitions the Floater fleet is often divided into “generations”; which basically refers to the period in which the rigs were built. There are therefore so called 1^st, 2^nd, 3^rd, 4^th, 5^th, 6^th and 7^th generation floaters.

The 2^nd generation consists primarily of semi-submersible rigs built in the 1970s, which were an enhancement of the original 1^st generation of semi-submersibles built for service in the Gulf of Mexico. The 3^rd generation of floaters drew heavily on the experiences of 2^nd generation units and generally had improved drilling capacities. Most of this fleet was built in the early 1980s. A small number of 4^th generation floaters were then built in mid 1980s, which were suitable for operation in harsher environments.

The first 5^th generation units were launched in 1996. These units were designed to work in deeper and harsher environments and to meet the needs of an offshore industry that was increasingly being asked to work in more hostile environments. Typically, 5^th generation units were able to operate in water depths up to 7,500 feet and were fitted with blow out preventors (BOPs), which have since become a standard feature in all future rig generations.

The first 6^th generation units entered service post 2005 and they were normally designed to operate in water depths of 10,000 to 12,000 feet. 7^th generation units have only entered service in the last couple of years and they usually have the capability to operate in ultra-deepwater in excess of 12,000 feet. Some of the 7^th generation units currently on order can be considered to be advanced 7^th generation floaters due to their enhanced technical features, such as blow out preventors, dual mud capability (for drilling and completion) and the ability to operate in water depths up to 12,000 feet in arctic conditions.

6^th and 7^th generation units represent the UDW fleet and the most advanced floaters in service. An indicative profile of the floater fleet by generation is provided below. The development of the floater fleet through the various generations is illustrated in the chart below.

The Development of the Floater Fleet

Source: Drewry

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Including conversions, 125 floaters were delivered between 2008 and 2014, representing roughly 30% of the total floater fleet today. Of these, 67 are defined as 6^th generation units and 43 are defined as 7^th generation floaters, which are capable of working in water depths of 12,000 feet or more. The remaining units are mainly older units having been fully refurbished and some newbuilds with less advanced capabilities.

As of April 2014, a total of 97 floaters are under construction, with deliveries stretching to 2019. The current newbuilding orderbook represents approximately 23% of the total floater fleet. Of the 97 units on order 36 are capable of drilling at water depths ranging from 10,000 to 12,000 feet, and a further 43 units on order are capable of drilling at water depths in excess of 12,000 feet.

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BUSINESS

We are a growth-oriented limited partnership recently formed by Ocean Rig to own, operate and acquire offshore drilling units, including through our ownership interest in OPCO. OPCO’s Initial Fleet consists of three ultra-deepwater drillships theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena, all of which are currently in operation. The drillships that comprise OPCO’s Initial Fleet are employed under multi-year contracts with affiliates of major oil companies, including Repsol, Total and Conoco Phillips with an average remaining term of approximately 4.0 years as of June 13, 2014. We intend to grow our per unit distributions and our exposure to the offshore drilling market initially by acquiring additional interests in OPCO and at a later stage by acquiring ownership interests in other drilling units of our Sponsor and third parties, subject to limitations in our and our Sponsor’s debt and other agreements. OPCO intends to leverage the relationships, expertise and reputation of our Sponsor to operate OPCO’s Initial Fleet in an efficient manner, to re-contract OPCO’s Initial Fleet under multi-year contracts and to identify opportunities to expand upon OPCO’s Initial Fleet through other acquisitions. We also plan to grow through the acquisition of Additional Fleet Interests (defined below) and other acquisitions. We believe our Sponsor will be motivated to facilitate our growth because of its significant ownership interest in us. See “—Our Relationship with our Sponsor.”

OPCO’s Initial Fleet

We believe that OPCO’s Initial Fleet is one of the most modern fleets in the offshore drilling industry and all of the drillships in OPCO’s Initial Fleet were built during or after the third quarter of 2013. Upon completion of this offering, we will own a % interest, through OPCO, in theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena.These drillships are “sister-drillships” constructed by Samsung Heavy Industries Co. Ltd., or “Samsung,” to the same high-quality and provenEnhanced SAIPEM 10000 vessel design and specifications and are capable of drilling in water depths of up to 12,000 feet. We believe that owning and operating “sister-drillships” helps OPCO maintain cost efficient operations through shared inventory and use of spare parts and the ability of offshore maritime crews to work seamlessly across all of OPCO’s drillships.

The following table provides information about OPCO’s Initial Fleet as of June 13, 2014:

Drilling Unit	Year Built / Generation	Water Depth to Welhead (ft)		Drilling Depth to Oil Field (ft)		Customer	Expected Contract Term	Contract Backlog	Drilling Location
Operating Drillships
Ocean Rig Mylos	Q3 2013/7th		12,000		40,000	Repsol	Q4 2013–Q4 2016(1)	$445 million	Brazil
Ocean Rig Skyros	Q4 2013/7th		12,000		40,000	Total(2)	Q1 2014–Q4 2014	$93 million	Angola
						Total E&P Angola(2)	Q4 2015–Q3 2021	$1.234 billion West Africa
Ocean Rig Athena	Q1 2014/7th		12,000		40,000	ConocoPhillips	Q2 2014–Q2 2017(3)	$681 million	Angola

(1) On November 4, 2013 theOcean Rig Mylos commenced drilling operations with Repsol at an average maximum dayrate of approximately $507,804 over the term of the contract.

(2) TheOcean Rig Skyros commenced a five well contract for a minimum of 275 days for drilling offshore West Africa with Total on March 2, 2014, with a maximum dayrate of $546,250 plus a mobilization fee of $29.0 million. This drillship is also contracted on a six year contract with Total for drilling operations offshore Angola . Under the new contract, we are entitled to a maximum dayrate of approximately $555,723, which is the average maximum dayrate applicable during the initial six-year term of the contract, plus mobilization fees of $20 million. Under the contract, the initial maximum dayrate of $513,000 is subject to a fixed annual escalation of 2% during the contract period.

(3) On March 24, 2014, theOcean Rig Athena was delivered from the shipyard and commenced drilling operations on June 7, 2014, at an average maximum dayrate of $623,045, which is the average maximum dayrate applicable during the initial three- year term of the contract. Under the contract, the initial maximum dayrate of $601,825 is subject to a fixed annual escalation of approximately 2% during the contract period.

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Pursuant to the omnibus agreement that we will enter into with our Sponsor and our General Partner upon the completion of this offering, or the Omnibus Agreement, we will have the following purchase rights:

• a right of first offer to purchase additional interests in OPCO, which we refer to as Additional Fleet Interests;

• a right to purchase from our Sponsor any drilling units it acquires or any of its existing drillships that it employs under contracts of four or more years, which we refer to as the Four-Year Drillships; and

• a right to purchase interests in four drillships owned by our Sponsor,Ocean Rig Corcovado,Ocean Rig Olympia,Ocean Rig Poseidon, andOcean Rig Mykonos, which we refer to as the Optional Drillship Interests.

Rights to Purchase Additional Interests in OPCO’s Fleet

We will have a right of first offer to purchase the Additional Fleet Interests from our Sponsor at a purchase price to be determined pursuant to the terms and conditions of the Omnibus Agreement. These purchase rights will expire 24 months following the completion of this offering. Please see “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Rights to Purchase Additional Interests in OPCO’s Fleet” for information on how the purchase price will be calculated.

Rights of First Offer on Drillships

Under the Omnibus Agreement, our Sponsor will agree (and will cause their subsidiaries, other than us, to agree) to grant a right of first offer to us for any Four-Year Drillships they might own. These rights of first offer will not apply to a (a) sale, transfer or other disposition of drillships between or among any affiliated subsidiaries, or the (b) merger with or into, or sale of all or substantially all of the assets to, an unaffiliated third-party. Please see “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Rights of First Offer on Drillships”

Right to Purchase Interests in the Optional Drillships

Pursuant to the Omnibus Agreement, we will have the right to purchase ownership interests, including the related drilling contracts, or the Optional Drillship Interests, in four sixth generation advanced capability ultra-deepwater drillships, currently 100% owned by our Sponsor. The purchase price for the Optional Drillships Interests will be determined pursuant to the terms and conditions of the Omnibus Agreement. These purchase rights will expire 36 months following the completion of the offering. Please see “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Rights to Purchase Optional Drillship Interests” for information on how the purchase price will be calculated. Please see “Risk Factors—Our Sponsor may be unable to service its debt requirements and comply with the provisions contained in the debt agreements secured by the Optional Drillships. If our Sponsor fails to perform its obligations under its debt agreements, our business and expected plans for growth may be materially affected” and “–Our Sponsor’s debt agreements, including its aggregate principal amount $800 million 6.5% senior secured notes due 2017, or the Senior Secured Notes due 2017, contain restrictions that may limit our growth plans.”

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The Optional Drillships

The Optional Drillships consist of the Ocean Rig Corcovado, theOcean Rig Olympia, theOcean Rig Poseidonand theOcean Rig Mykonos, delivered in January 2011, March 2011, July 2011 and September 2011, respectively. The Optional Drillships are “sister-ships” constructed by Samsung to the same high-quality vessel design and specifications and are capable of drilling up to 40,000 feet in water depths of up to 10,000 feet.

The following table provides information about the Optional Drillships as of June 13, 2014:

Drilling Unit	Year Built / Generation		Water Depth to Welhead (ft)		Drilling Depth to Oil Field (ft)		Customer	Expected Contract Term	Average Maximum Dayrate		Contract Backlog		Drilling Location
Operating Drillships
Ocean Rig Corcovado		2011/6th		10,000		40,000	Petrobras	Q2 2012–Q2 2015(1)		459,954	$	154.255	Brazil
Ocean Rig Olympia		2011/6th		10,000		40,000	Total	Q3 2012–Q3 2015(2)		589,032	$	252,394	Angola
Ocean Rig Poseidon		2011/6th		10,000		40,000	Eni	Q2 2013–Q2 2016(3)		700,452	$	507,379	Angola
Ocean Rig Mykonos		2011/6th		10,000		40,000	Petrobras	Q1 2012–Q1 2015		454,954	$	127,301	Brazil

(1) TheOcean Rig Corcovadois currently employed under a three-year drilling contract, plus a mobilization period, with Petrobras for drilling operations offshore Brazil at an average maximum dayrate of $459,954 (including average service fees of $85,796 per day, based on the contracted rate in Real per day and the June 13, 2014 exchange rate of Real$2.24:$1.00, plus a mobilization fee of $30.0 million. The contract is scheduled to be completed in the second quarter of 2015.

(2) TheOcean Rig Olympiacommenced a three-year drilling contract with Total in July 2012 for drilling operations offshore West Africa at an average maximum dayrate of $589,032, plus mobilization and demobilization fees of $9.0 million and $3.5 million, respectively, plus the cost of fuel.

(3) TheOcean Rig Poseidoncommenced a three-year drilling contract with ENI in May 2013 for drilling operations offshore Angola at an average maximum dayrate of $700,452, which is the average maximum dayrate applicable during the initial three-year term of the contract. During the term of the contract, the initial maximum dayrate of $670,000 will increase annually at a rate of 3%, beginning twelve months after the commencement date. The contract also includes a mobilization rate of $656,600 per day, plus reimbursement for the cost of fuel, and a demobilization fee of $5.0 million.

(4) TheOcean Rig Mykonoscommenced a three-year drilling contract, plus a mobilization period, with Petrobras, on September 30, 2011, for drilling operations offshore Brazil at an average maximum dayrate of $454,954 (including average service fees of $84,863 per day, based on the contracted rate in Real and the June 13, 2014 exchange rate of Real$2.24:$1.00), plus a mobilization fee of $30.0 million. The contract is scheduled to expire in March 2015.

Our Relationship with our Sponsor

Ocean Rig, a corporation organized under the laws of the Republic of the Marshall Islands, was formed in 2007 as a wholly-owned subsidiary of DryShips for the purpose of acquiring offshore drilling rigs and drillships. As of the date hereof, Ocean Rig’s fleet, including OPCO’s Initial Fleet, includes 13 offshore ultra deepwater drilling units, comprised of two ultra deepwater semisubmersible drilling rigs and nine ultra deepwater drillships, two of which are scheduled to be delivered during 2015 and two of which are scheduled to be delivered during 2017. Ocean Rig’s shares commenced trading on the NASDAQ Global Select Market under the symbol “ORIG” on October 6, 2011.

One of our principal strengths is our relationship with our Sponsor. We expect our relationship with our Sponsor to give us access to its long-standing relationships with major energy companies and shipbuilders and its technical, commercial and managerial expertise. In addition, we expect to have access to our Sponsor’s customer and supplier relationships which we believe will allow us to compete more effectively when seeking additional customers. However, we can provide no assurance that we will realize any benefits from our relationship with our Sponsor.

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Upon completion of this offering, our Sponsor will own all of our incentive distribution rights, through our General Partner, and a     % ownership interest in us as well as a     % interest in OPCO and thus will have significant incentives to contribute to our success.

We will be managed by the board of directors and executive officers of our General Partner. Our General Partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. Ocean Rig owns all of the membership interests in our General Partner. Our common unitholders will not be entitled to elect the directors of our General Partner or to participate directly or indirectly in our management or operations.

Business Strategies

Our primary business objective is to increase the quarterly cash distributions to our unitholders over time. We intend to accomplish this objective by executing the following strategies:

• Growth Though Strategic and Accretive Acquisitions. We initially intend to capitalize on growth opportunities by acquiring from time to time Additional Fleet Interests from our Sponsor. In addition, we plan to grow through acquisitions of other offshore drilling units owned by our Sponsor or third parties, subject to the limitations imposed in our and our Sponsor’s debt agreements. Pursuant to the terms of the Omnibus Agreement, we will have a right of first offer to acquire or right to purchase from our Sponsor, as the case may be, Additional Fleet Interests, Four Year Drillships and Optional Drillships Interests. We will not be obligated to purchase the Additional Fleet Interests, the Four-Year Drillships or the Optional Drillship Interests at the determined prices and, accordingly, we may not complete the purchase of such interests or vessels, which may have an adverse effect on our expected plans for growth. In addition, our ability to purchase the Additional Fleet Interests, the Four-Year Drillships or the Optional Drillship Interests, should we exercise our right to purchase such interests, is dependent on our ability to obtain additional financing to fund all or a portion of the purchase price of these acquisitions. As of the date of this prospectus, we have not secured any financing in connection with the potential acquisition of Additional Fleet Interests or Optional Drillship Interests. In addition, debt arrangements of us and our Sponsor may restrict our ability to complete these acquisitions. Please see “Risk Factors—Our Sponsor may be unable to service its debt requirements and comply with the provisions contained in the debt agreements secured by the Optional Drillships. If our Sponsor fails to perform its obligations under its debt agreements, our business and expected plans for growth may be materially affected” and “—Our Sponsor’s debt agreements, including its aggregate principal amount $800 million 6.5% senior secured notes due 2017, or the Senior Secured Notes due 2017, contain restrictions that may limit our growth plans.”

• Pursue Multi-year contracts and Maintain Stable Cash Flow. We will seek to maintain stable cash flows by continuing to pursue multi-year contracts and focusing on minimizing operational downtime. Our focus on multi-year contracts improves the stability and predictability of our operating cash flows, which we believe will enable us to access equity and debt capital markets on attractive terms and, therefore, facilitate our growth strategy.

• Maintain a Modern and Reliable Fleet. We believe OPCO has a modern and technologically advanced fleet. In addition, OPCO’s Initial Fleet consists solely of ultra-deepwater drillships with the ability to operate at water depths of up to 12,000 feet. OPCO intends to grow its Initial Fleet over time in order to continue to meet its customers’ demands while optimizing its fleet size from an operational and logistical perspective.

• Provide Excellent Customer Service and Continue to Prioritize Safety As A Key Element Of Our Operations. Our and our Sponsor’s mission is to become the preferred offshore drilling contractors in the ultra-deepwater regions of the world and to deliver excellent performance to our clients by exceeding their expectations for operational efficiency and safety standards. We seek to deliver exceptional performance to our customers by consistently meeting or exceeding their expectations for operational performance, including by maintaining high safety standards and minimizing downtime.

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We can provide no assurance, however, that we will be able to implement our business strategies described above. For further discussion of the risks that we face, please read “Risk Factors.”

Competitive Strengths

We believe we are well positioned to achieve our primary business objectives and execute our business strategies based on the following competitive strengths:

• Relationship with our Sponsor. We expect to rely on our relationship with our Sponsor to facilitate our acquisition and growth strategy, and we also expect to benefit from our Sponsor’s operational expertise and relationships with suppliers and shipyards. There is no assurance however that our Sponsor will be able to maintain these relationships or reap the benefits of these relationships in order to facilitate our acquisition and growth strategy.

• Focused and established track record in ultra-deepwater drilling operations. We believe that our Sponsor has a well-established record of operating drilling units with a primary focus on ultra-deepwater offshore locations and has gained significant experience operating in challenging environments through the completion of 185 wells for 30 different customers to date. We believe we will be able to capitalize on our high-specification drillships and we believe that we, through our Sponsor, have earned a reputation for operating performance excellence, customer service and safety.

• Modern, Technologically Advanced UDW Fleet. We believe that OPCO’s Initial Fleet is one of the most modern, technologically advanced fleets in the offshore drilling industry. OPCO’s Initial Fleet was built during or after the third quarter of 2013, with an an average age of approximately four months and consists of ultra deepwater drillships with the ability to operate at water depths of up to 12,000 feet. We believe that OPCO’s modern fleet enables customers to drill wells more efficiently and more reliably than older drilling units.

• “Sister- Drillship” Efficiencies.We believe that OPCO’s fleet of sister drillships, which are vessels of the same type and specification, will enable OPCO to benefit from more chartering opportunities, economies of scale and operating and cost efficiencies in crew training, crew rotation and shared spare parts.

• Multi-year contracts with High Quality Customers. All of our revenues and associated cash flows are derived from OPCO’s existing multi-year contracts. As of June 13, 2014, these contracts have an average remaining term of 4.0 years, and we believe these contracts enhance the stability and predictability of our revenues.

We can provide no assurance, however, that we will be able to utilize our strengths described above. For further discussion of the risks that we face in implementing our business strategy, please read “Risk Factors.”

Seasonality

In general, seasonal factors do not have a significant direct effect on OPCO’s business. OPCO has operations in certain parts of the world where weather conditions during parts of the year could adversely impact the operation of its rigs, but generally such operational interruptions do not have a significant impact on OPCO’s revenues. Please read “—Drilling Contracts.”

Customers

Our customers are oil and gas exploration and production companies, including major integrated oil companies, independent oil and gas producers and government-owned oil and gas companies. During the year ended             , OPCO generated revenues from only Respol, which accounted for     % of its revenues. OPCO’s customers are as follows:

• Repsol Sinopec Brasil, S.A., or Respol;

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• Total;

• Total E&P Angola; and

• ConocoPhillips.

OPCO’s drillships are contracted to customers for periods between one and three years ahead, and its future contracted revenue, or backlog, at December 31, 2013 totaled approximately $1.4 billion. OPCO expects approximately $563 million of our backlog to be realized in 2014. The amount of actual revenues earned and the actual periods during which revenues are earned will be different from the backlog projections due to various factors. Downtime, caused by unscheduled repairs, maintenance, weather and other operating factors, may result in lower applicable daily rates than the full contractual operating daily rate.

The following table shows the percentage of drillships days committed by year as of December 31, 2013. The percentage of rig days committed is calculated as the ratio of total days committed under contracts to total available days in the period. Total available days for our units under construction are based on their expected delivery dates.

	Year ending December 31,
% of drillships-days committed	2013			2014			2015
Drillships		100	%		97.3	%		66.7	%

Competition

The offshore drilling industry is highly competitive, with market participants ranging from large multinational companies to smaller companies, like us, with fewer than five drilling rigs.

The demand for offshore drilling services is driven by oil and natural gas companies’ exploration and development drilling programs. These drilling programs are affected by oil and natural gas companies’ expectations regarding oil and natural gas prices, anticipated production levels, worldwide demand for oil and natural gas products and many other factors. The availability of quality drilling prospects, exploration success, availability of qualified rigs and operating personnel, relative production costs, availability and lead time requirements for drilling and production equipment, the stage of reservoir development and political and regulatory environments also affect our customers’ drilling programs. Oil and natural gas prices are volatile, which has historically led to significant fluctuations in expenditures by customers for drilling services. Variations in market conditions impact us in different ways, depending primarily on the length of drilling contracts in different markets. Short-term changes in these markets may have a minimal short-term impact on revenues and cash flows, unless the timing of contract renewals coincides with short-term movements in the market.

Offshore drilling contracts are generally awarded on a competitive bid basis or through privately negotiated transactions. In determining which qualified drilling contractor is awarded a contract, the key factors are pricing, drillship availability, drillship location, condition and integrity of equipment, their record of operating efficiency, including high operating uptime, technical specifications, safety performance record, crew experience, reputation, industry standing and customer relations.

Competition for drillships is generally on a global basis, as rigs are highly mobile. However, the cost associated with mobilizing drillships between regions is sometimes substantial, as entering a new region could necessitate modifications of the drillship and its equipment to specific regional requirements.

We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future. We believe that OPCO’s Initial Fleet of recently constructed technologically advanced drillships provides it with a competitive advantage over competitors with older fleets, as OPCO’s drillships are generally better suited to meet the requirements of customers for drilling in deepwater. However, certain competitors have greater financial resources than we do, which may enable them to better withstand periods of low utilization, and compete more effectively on the basis of price.

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Crewing and Staff

As of                 , approximately                 offshore staff served on OPCO’s drillships and approximately                 staff served onshore in technical, commercial and administrative roles in various countries. OPCO directly employs approximately     % of the onshore staff and employs no offshore staff directly; instead certain subsidiaries of our Sponsor employ the crews, who serve on the drillships pursuant to agreements with the subsidiaries. Likewise, certain subsidiaries of our Sponsor provide onshore advisory, operational and administrative support to OPCO’s operating subsidiaries pursuant to service agreements. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Advisory, Technical and Administrative Services Agreements.”

Some of our Sponsor’s employees that provide services for OPCO and OPCO’s contracted labor are represented by collective bargaining agreements. Some of these agreements require the contribution of certain amounts to retirement funds and pension plans and special procedures for the dismissal of employees. In addition, many of these represented individuals are working under agreements that are subject to salary negotiation. These negotiations could result in higher personnel costs for OPCO, other increased costs or increased operating restrictions that could adversely affect our financial performance.

Risk of Loss and Insurance

OPCO’s operations are subject to hazards inherent in the drilling of oil and natural gas wells, including blowouts and well fires, which could cause personal injury, suspend drilling operations, destroy the equipment involved or cause serious environmental damage. Offshore drilling contractors such as DOV I are also subject to hazards particular to marine operations, including capsizing, grounding, collision and loss or damage from severe weather. DOV I’s marine insurance package policy provides insurance coverage for physical damage to DOV I’s drillships, loss of hire for some of its rigs and third-party liability.

DOV I’s insurance claims are subject to a deductible, or non-recoverable, amount. We currently maintain a deductible per occurrence of up to $1.5 million related to physical damage to its drillships. However, a total loss of, or a constructive total loss of, a drilling rig is recoverable without being subject to a deductible. For general and marine third-party liabilities, DOV I generally maintains a deductible of up to $250,000 per occurrence on personal injury liability for crew claims, non-crew claims and third-party property damage and 10,000 eev exert for oil pollution from the drillships. Furthermore, for some of DOV I’s drillships DOV I purchases insurance to cover loss due to the drillship being wholly or partially deprived of income as a consequence of damage to the unit. The loss of hire insurance has a deductible period of 45 days after the occurrence of physical damage. Thereafter, insurance policies are limited to         days. If the repair period for any physical damage exceeds the number of days permitted under DOV I’s loss of hire policy, it will be responsible for the costs in such period.

Environmental and Other Regulations in the Offshore Drilling Industry

OPCO’s operations are subject to numerous laws and regulations in the form of international conventions and treaties, national, state and local laws and national and international regulations in force in the jurisdictions in which its drilling rigs operate or are registered, which can significantly affect the operation of OPCO’s drillships. These requirements include, but are not limited to, the International Convention for the Prevention of Pollution from Ships, or MARPOL, the International Convention on Civil Liability for Oil Pollution Damage of 1969, generally referred to as CLC, the International Convention on Civil Liability for Bunker Oil Pollution Damage, or Bunker Convention, the International Convention for the Safety of Life at Sea of 1974, or SOLAS, the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention, or ISM Code, the International Convention for the Control and Management of Ships’ Ballast Water and Sediments of February 2004, or the BWM Convention, the U.S. Oil Pollution Act of 1990, or OPA, the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, the U.S. Clean Water Act, the U.S. Clean Air Act, the U.S. Outer Continental Shelf Lands Act, the U.S. Maritime Transportation Security Act of 2002, or the MTSA, Brazil’s National Environmental Policy Law (6938/81), Environmental Crimes Law

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(9605/98) and federal law (9966/2000) relating to pollution in Brazilian waters and, Angola’s Petroleum Activities Law. These laws govern the discharge of materials into the environment or otherwise relate to environmental protection. In certain circumstances, these laws may impose strict liability, rendering DOV liable for environmental and natural resource damages without regard to negligence or fault on its part.

International Maritime Regimes

The United Nations’ International Maritime Organization, or IMO, provides international regulations governing shipping and international maritime trade. The requirements contained in the International Management Code for the Safe Operation of Ships and for Pollution Prevention (the ISM Code) promulgated by the IMO, govern our operations. Among other requirements, the ISM Code requires the party with operational control of a vessel to develop an extensive safety management system that includes, among other things, the adoption of a policy for safety and environmental protection policy setting forth instructions and procedures for operating its vessels safely and also describing procedures for responding to emergencies. The IMO regulations, and others, have been adopted by the member countries, including the United States, Brazil and Angola. In certain jurisdictions, notably in the United States, national laws have been enacted to implement, or expand, the IMO regulations and they are discussed below by country.

The IMO has adopted MARPOL, including Annex VI to MARPOL which sets limits on sulfur dioxide and nitrogen oxide emissions from ship exhausts and prohibits deliberate emissions of ozone depleting substances. Annex VI applies to all ships, fixed and floating drilling rigs and other floating platforms and, among other things, imposes a global cap on the sulfur content of fuel oil and allows for specialized areas to be established internationally with even more stringent controls on sulfur emissions. For vessels 400 gross tons and greater, platforms and drilling rigs, Annex VI imposes various survey and certification requirements. Moreover, recent amendments to Annex VI require the imposition of progressively stricter limitations on sulfur emissions from ships. These limitations require that fuels of vessels in covered Emission Control Areas, or ECAs, contain no more than 1% sulfur. Amended Annex VI established procedures for designating new ECAs. The Baltic Sea and the North Sea have been so designated.

In August 2012, the North American ECA became enforceable. The North American ECA includes areas subject to the exclusive sovereignty of the United States and extends up to 200 nautical miles from the coasts of the United States, which area includes parts of the U.S. GOM. Consequently, the sulfur limit in marine fuel in the North American ECA is capped at 1%, which is the capped amount for all other ECA areas since July 1, 2010. These capped amounts will then decrease progressively until they reach 0.5% by January 1, 2020 for non-ECA areas and 0.1% by January 1, 2015 for ECA areas, including the North American ECA. The amendments also establish new tiers of stringent nitrogen oxide emissions standards for new marine engines, depending on their date of installation. Our operation of vessels in international waters, outside of the North American ECA, are subject to the requirements of Annex VI in those countries that have implemented its provisions.

The IMO has negotiated international conventions that impose liability for oil pollution in international waters and the territorial waters of the signatory to such conventions such as the BWM Convention. The BWM Convention’s implementing regulations call for a phased introduction of mandatory ballast water exchange requirements (beginning in 2009), to be replaced in time with a requirement for mandatory ballast water treatment. The BWM Convention will not become effective until 12 months after it has been adopted by 30 states, the combined merchant fleets of which represent not less than 35% of the gross tonnage of the world’s merchant shipping. Though this has not occurred to-date, the IMO has passed a resolution encouraging the ratification of the BWM Convention and calling upon those countries that have already ratified to encourage the installation of ballast water management systems on new ships. As referenced below, the United States Coast Guard issued new ballast water management rules on March 23, 2012. Under the requirements of the BWM Convention for units with ballast water capacity of more than 5000 cubic meters that were constructed in 2011 or before, ballast water management exchange or treatment will be accepted until 2016. From 2016 (or not later than the first intermediate or renewal survey after 2016), only ballast water treatment will be accepted by the BWM Convention. All of our vessels are compliant with the BWM Convention.

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The Bunker Convention provides a liability, compensation and compulsory insurance system for the victims of oil pollution damage caused by spills of bunker oil. Ship owners must pay compensation for pollution damage (including the cost of preventive measures) caused in the territory, including the territorial sea of a State Party, as well as its economic zone or equivalent area. Registered owners of any sea going vessel and seaborne craft over 1,000 gross tons, of any type whatsoever, and registered in a State Party, or entering or leaving a port in the territory of a State Party, must maintain insurance which meets the requirements of the Bunker Convention and to obtain a certificate issued by a State Party attesting that such insurance is in force. The State issued certificate must be carried on board at all times. P&I Clubs in the International Group issue the required Bunkers Convention “Blue Cards” to enable signatory states to issue certificates. Each drillship in OPCO’s Initial Fleet has received a “Blue Card” from its P&I Club and is in possession of a CLC state-issued certificate attesting that the required insurance coverage is in force and are currently compliant in all material respects with these regulations.

The IMO continues to review and introduce new regulations. It is impossible to predict what additional regulations, if any, may be passed by the IMO and what effect, if any, such regulation may have on our operations.

United States

Heightened environmental concerns in the U.S. GOM have led to higher drilling costs and a more difficult and lengthy well permitting process and, in general, have adversely affected drilling decisions of oil and natural gas companies. In the United States, our operations are subject to federal and state laws and regulations that require us to obtain and maintain specified permits or governmental approvals; control the discharge of materials into the environment; remove and cleanup materials that may harm the environment; or otherwise comply with the protection of the environment. We are subject to the jurisdiction of the U.S. Coast Guard, or Coast Guard, the National Transportation Safety Board, the U.S. Customs and Border Protection, or CBP, the Department of Interior, the Bureau of Ocean Energy Management, or BOEM, and the Bureau of Safety and Environmental Enforcement, or BSEE, as well as classification societies such as the American Bureau of Shipping. The Coast Guard and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards, and the CBP is authorized to inspect vessels at will. Coast Guard regulations also require annual inspections and periodic drydock inspections or special examinations of our vessels.

Furthermore, any drillship that DOV may operate in United States waters, including the U.S. territorial sea and the 200 nautical mile exclusive economic zone around the United States, would have to comply with OPA and CERCLA requirements, among others, that impose liability (unless the spill results solely from the act or omission of a third party, an act of God or an act of war) for all containment and clean-up costs and other damages arising from discharges of oil or other hazardous substances, other than discharges related to drilling.

Oil Pollution Act. The U.S. Oil Pollution Act of 1990, or OPA, as amended, and related regulations impose a variety of requirements on “responsible parties” related to the prevention and/or reporting of oil spills and liability for damages resulting from such spills in waters off the U.S. A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. Under OPA, “responsible parties” are jointly, severally and strictly liable (unless the spill results solely from the act or omission of a third party, an act of God or an act of war) for all containment and clean-up costs and other damages arising from discharges or threatened discharges of oil from their vessels.

CERCLA.The U.S. Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the “Superfund” law, imposes liability without regard to fault or the legality of the original conduct on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of a facility where

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a release occurred, the owner or operator of a vessel from which there is a release, and entities that disposed or arranged for the disposal of the hazardous substances found at a particular site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the cost of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Prior owners and operators are also subject to liability under CERCLA. It is also not uncommon for third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We generate wastes in the course of our routine operations that may be classified as hazardous substances. The United States is a member country to the IMO and is subject to MARPOL which imposes environmental standards on the shipping industry relating to oil spills, management of garbage, the handling and disposal of noxious liquids, harmful substances in packaged forms, sewage and air emissions.

OPA and CERCLA both require owners and operators of vessels to establish and maintain with the U.S. Coast Guard evidence of financial responsibility sufficient to meet the maximum amount of liability to which the particular responsible person may be subject. Vessel owners and operators may satisfy their financial responsibility obligations by providing a proof of insurance, a surety bond, qualification as a self-insurer or a guarantee.

OCSLA.The Outer Continental Shelf Lands Act (“OCSLA”) authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the outer continental shelf. Included among these are regulations that require the preparation of spill contingency plans and establish air quality standards for certain pollutants, including particulate matter, volatile organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific design and operational standards may apply to outer continental shelf vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations related to the environment issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement liabilities can result from either governmental or citizen prosecution.

In the United States in 2010, the Department of the Interior undertook a substantial reorganization of regulatory authority for offshore drilling following the Macondo well blowout incident in the GOM in April 2010. Primary regulatory responsibility for offshore drilling was transferred to the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, and on October 1, 2011, BOEMRE was reorganized into two new organizations, the BOEM and the BSEE. As a result of this reorganization, BSEE is now responsible for the issuance of permits for offshore drilling activities and BOEM for all oil and gas leasing activities that were previously handled by BOEMRE. From time to time, new rules, regulations and requirements have been proposed and implemented by BOEM, BSEE or the United States Congress that materially limit or prohibit, and increase the cost of, offshore drilling in the U.S. GOM. These new rules, regulations and requirements include the moratorium on drilling that was lifted in May 2010, but which resulted in a significant delay in permits being issued in the U.S. GOM, the adoption of new safety requirements and policies relating to the approval of drilling permits in the U.S. GOM, and restrictions on oil and gas development and production activities in the U.S. GOM. In February 2014, BOEM published a proposed increase to the limit of liability for oil-spill removal costs and damages, from $75 million to approximately $134 million. The increase would apply to offshore facilities in federal and state waters under the OPA.

The BSEE periodically issues guidelines for rig fitness requirements in the U.S. GOM and may take other steps that could increase the cost of operations or reduce the area of operations for OPCO’s drillships, thus reducing their marketability. On August 21, 2013, BSEE proposed a rule to revise an existing federal regulations regarding oil and gas production safety systems to address technological advances. On April 5, 2013, BSEE published a final rule amending the Workplace Safety Rule by requiring the imposition of certain added safety procedures to a company’s Safety and Environmental Management Systems (SEMS) not covered by the original rule. The amended SEMS rule (SEMS II) requires third-party audits of a company’s SEMS and gives all rig workers authority to stop work. In addition, a new Notice to Lessees 2012-N06 regarding the preparation of

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regional oil spill response plans became effective on August 10, 2012. Implementation of new BSEE or BOEM guidelines or regulations may subject us to increased costs or limit the operational capabilities of our drillships and could materially and adversely affect our operations and financial condition.

Clean Water Act. The United States Clean Water Act, or CWA, prohibits the discharge of oil or hazardous substances in United States navigable waters unless authorized by a permit or exemption, and imposes strict liability in the form of penalties for unauthorized discharges. The CWA also imposes substantial liability for the costs of removal, remediation and damages and complements the remedies available under OPA and CERCLA. In the United States, two federal agencies regulate ballast water discharges, the EPA, through the VGP and the U.S. Coast Guard, through approved ballast water management systems (or BWMS). On March 28, 2013, the EPA published a new VGP to replace the existing VGP when it expires in December 2013. The new VGP includes numeric effluent limits for ballast water expressed as the maximum concentration of living organisms in ballast water, as opposed to the current “Best Management Practices” requirements. The new VGP also imposes a variety of changes for non-ballast water discharges including more stringent BMPs for discharges of oil-to-sea interfaces in an effort to reduce the toxicity of oil leaked into U.S. waters. For certain existing vessels, the EPA has adopted a staggered implementation schedule to require vessels to meet the ballast water effluent limitations by the first drydocking after January 1, 2014 or January 1, 2016, depending on the vessel size. Several U.S. states have added specific requirements to the VGP and, in some cases, may require vessels to install ballast water treatment technology to meet biological performance standards. Vessels that are constructed after December 1, 2013 are subject to the ballast water numeric effluent limitations immediately upon the effective date of the new VGP.

NISA.The Nonindigenous Aquatic Nuisance Prevention and Control Act of 1990, as amended by the National Invasive Species Act of 1996 (NISA), authorized the Coast Guard to develop a regulatory program to prevent the introduction and spread of aquatic nuisance species. On March 23, 2012, the U.S. Coast Guard issued a final rule establishing standards for the allowable concentration of living organisms in ballast water discharged in U.S. waters and requiring the phase-in of Coast Guard approved ballast water management systems. The rule went into effect on June 20, 2012 and adopts ballast water discharge standards for vessels calling on U.S. ports and intending to discharge ballast water equivalent to those set in IMO’s BWM Convention. The final rule requires that ballast water discharge have no more than 10 living organisms per milliliter for organisms between 10 and 50 micrometers in size. For organisms larger than 50 micrometers, the discharge can have 10 living organisms per cubic meter of discharge. New ships constructed on or after December 1, 2012 must comply with these standards and some existing ships must comply by their first dry dock after January 1, 2014. The Coast Guard will review the practicability of implementing a more stringent ballast water discharge standard and publish the results no later than January 1, 2016.

Numerous governmental agencies issue regulations to implement and enforce the laws of the applicable jurisdiction, which often involve lengthy permitting procedures, impose difficult and costly compliance measures, particularly in ecologically sensitive areas, and subject operators to substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. Some of these laws contain criminal sanctions in addition to civil penalties. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance or limit contract drilling opportunities, including changes in response to a serious marine incident that results in significant oil pollution or otherwise causes significant adverse environmental impact, such as the April 2010 Macondo well blowout incident, could adversely affect OPCO’s financial results. Although significant capital expenditures may be required to comply with these governmental laws and regulations, such compliance has not materially adversely affected our earnings or competitive position. We believe that we are currently in compliance in all material respects with the environmental regulations to which we are subject.

Clean Air Act. The U.S. Clean Air Act of 1970, as amended (or the CAA) requires the EPA to promulgate standards applicable to emissions of volatile organic compounds and other air contaminants. The units in our portfolio are subject to vapor control and recovery requirements for certain cargoes when loading, unloading,

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ballasting, cleaning and conducting other operations in regulated port areas and emission standards for so called “Category 3” marine diesel engines operating in U.S. waters. The marine diesel engine emission standards are currently limited to new engines beginning with the 2004 model year. On April 30, 2010, the EPA promulgated final emission standards for Category 3 marine diesel engines equivalent to those adopted in the amendments to Annex VI to MARPOL. The emission standards apply in two stages: near-term standards for newly built engines will apply from 2011, and long-term standards requiring an 80% reduction in nitrogen dioxides (or NOx) will apply from 2016. The CAA also requires states to draft State Implementation Plans, or SIPs, designed to attain national health-based air quality standards in each state. Although state-specific, SIPs may include regulations concerning emissions resulting from vessel loading and unloading operations by requiring the installation of vapor control equipment. Compliance with these standards may cause us to incur costs to install control equipment on our vessels in the future.

We may also be affected by or subject to permitting and other requirements under a variety of other environmental laws not discussed above, such as the federal Clean Air Act, Endangered Species Act, Marine Mammal Protection Act, and National Environmental Policy Act.

Brazilian Environmental Regulations

Brazilian environmental law includes international treaties and conventions to which Brazil is a party, as well as federal, state and local laws, regulations and permit requirements related to the protection of health and the environment. Brazilian oil and gas business is subject to extensive regulations by several governmental agencies, including the National Agency for Oil and Gas (“ANP”), the Brazilian Navy and the Brazilian Authority for Environmental Affairs and Renewable Resources (“IBAMA”). Onshore environmental, health and safety conditions which are applicable to our onshore base are controlled by state rather than by federal authorities. Failure to comply may subject us to administrative, criminal and civil liability, with strict liability in administrative and civil cases. While we believe that we are in substantial compliance with the current environmental laws and regulations, there is no assurance that compliance with current laws and regulations or amended or newly adopted laws and regulations can be maintained in the future or that future expenditures required to comply with all such laws and regulations in the future will not be material.

Environmental license from IBAMA is a legal requirement for any activity considered hazardous, including offshore drilling. The main piece of legislation concerning environmental licensing at federal level is Law No. 6,938/1981, which established the Environmental National Policy and provides for licenses for the installation and operation of oil and gas platforms within the Brazilian territory. Such licenses are usually required from the oil and gas companies, however we, as a drilling contractor, are jointly and severally liable with the oil and gas companies for any environmental damage arising out of drilling activities. Furthermore, drilling operations are subject to federal regulations of National Council for the Environment (“CONAMA”). CONAMA regulation No. 23/94 deals specifically with oil and gas operations.

Pursuant to environmental impact studies which are required from oil and gas companies as part of the licensing process, an Individual Emergency Plan (“IEP”) describing the measures to be taken in case of oil spills must be submitted to the competent authorities, as provided for in Law No. 9,966/2000, which has in fact adopted the provisions found in the International Convention for the Prevention of Pollution from Ships (MARPOL) and the International Convention for Preparedness, Response and Cooperation for Oil Pollution Situations (OPRC).

ANP Regulation No. 43/07 sets forth the regulatory framework for safety of operations concerning oil & gas exploration and production activities in the Brazilian territory. ANP Regulation No. 43/07 establishes the System of Management of Operational Safety (“SGSO”) of Oil & Gas Drilling and Production Facilities. Accordingly, our clients will require us to put in place a risk management system as well as an audit program which meets the ANP criteria. ANP is empowered to carry out any inspections at any time. The oil and gas companies must present to the ANP the Documentation of Operational Safety (“DSO”) for all drilling facilities not later than

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ninety (90) days prior to the expected date of commencement of operations. The DSO approval from the ANP is required prior to commencement of operations. In the event of risk to equipment and facilities as well as to the environment and to human life, operations may be suspended for a period ranging from one (1) to one hundred and eighty (180) months. The termination of the concession contract may take place in the event the situation is not rectified within the deadline set out by the ANP. In such circumstances the oil and gas company prevented from taking part in ANP bids for up to five (5) years, as set forth in ANP Regulation No. 243/03.

Law No. 9,605/98 is the main Brazilian legislation providing for criminal and administrative liabilities for environmental damage. We, as well as our officers, directors and employees may be subject to criminal liability and penalties which include but are not limited to imprisonment, fines of up to R$ 50,000,000.00, suspension of activities, prohibition to enter into any agreement with the Brazilian government (including Petrobras) or to receive any public subsidies or incentives for up to ten (10) years. The administrative penalties contemplated by Law No. 9,605/95 also include seizure of assets, suspension of activities, revocation of licenses, prohibition to enter into any agreement with the Government (including Petrobras) for up to three (3) years and cancellation or suspension of financing arrangements with state-owned banking institutions.

Our Brazilian operations are exposed to administrative and criminal sanctions, including warnings, fines and closure orders for non-compliance with the environmental regulations. Authorities such as IBAMA and ANP routinely inspect our facilities, and may impose fines, restrictions on operations, or other sanctions as provided in the applicable legislation

Angola

The Petroleum Activities Law, as implemented by the Petroleum Operations Regulations approved in 2009, is the key Angolan legislation that covers the oil and gas industry. We are also subject to the Environmental Framework Law, the Regulations on Liability for Environmental Damages, Decree 39/00 (setting forth specific rules on environmental protection in the performance of petroleum operations), and were subject to Executive Decree 12/05 (setting out procedures for reporting of the occurrence of oil spills) which was repealed by Executive Decree No. 224/12 when it went into effect on June 16, 2012. There is no assurance that compliance with current laws and regulations or amended or newly adopted laws and regulations can be maintained in the future or that future expenditures required to comply with all such laws and regulations in the future will not be material.

Other International Operations

In addition to the requirements described above, DOV I’s international operations in the offshore drilling segment are subject to various other international conventions and laws and regulations in countries in which OPCO operates, including laws and regulations relating to the importation of and operation of drillships and equipment, currency conversions and repatriation, oil and natural gas exploration and development, environmental protection, taxation of offshore earnings and earnings of expatriate personnel, the use of local employees and suppliers by foreign contractors and duties on the importation and exportation of drillships and other equipment. New environmental or safety laws and regulations could be enacted, which could adversely affect OPCO’s ability to operate in certain jurisdictions. Governments in some countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exploration for oil and natural gas and other aspects of the oil and natural gas industries in their countries. In some areas of the world, this governmental activity has adversely affected the amount of exploration and development work done by major oil and natural gas companies and may continue to do so. Operations in less developed countries can be subject to legal systems that are not as mature or predictable as those in more developed countries, which can lead to greater uncertainty in legal matters and proceedings.

Implementation of new environmental laws or regulations that may apply to ultra-deepwater drillships may subject DOV to increased costs or limit the operational capabilities of its drillships and could materially and

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adversely affect OPCO’s operations and financial condition. In addition to the regulatory changes taking place in the United States, other countries are undertaking a review of the regulation of the offshore drilling industry following the Macondo incident, with which we were not involved.

Regulation of Greenhouse Gas Emissions

In February 2005, the Kyoto Protocol entered into force. Pursuant to the Kyoto Protocol, adopting countries are required to implement national programs to reduce emissions of certain gases, generally referred to as greenhouse gases, which are suspected of contributing to global warming. Currently, the emissions of greenhouse gases from international shipping are not subject to the Kyoto Protocol. However, international negotiations are continuing with respect to a successor to the Kyoto Protocol, which set emission reduction targets through 2020, and restrictions on shipping emissions may be included in any new treaty. In December 2009, more than 27 nations, including the United States, signed the Copenhagen Accord, which includes a non-binding commitment to reduce greenhouse gas emissions.

On January 1, 2013, the IMO approved mandatory measures to reduce emissions of greenhouse gases from international shipping went into force. These include amendments to MARPOL Annex VI Regulations for the prevention of air pollution from ships adding a new Chapter 4 to Annex VI on Regulations on energy efficiency requiring the Energy Efficiency Design Index, or EEDI, for new ships, and the Ship Energy Efficiency Management Plan, or SEEMP, for all ships. Other amendments to Annex VI add new definitions and requirements for survey and certification, including the format for the International Energy Efficiency Certificate. The regulations apply to all ships of 400 gross tonnage and above. These new rules will likely affect the operations of vessels that are registered in countries that are signatories to MARPOL Annex VI or vessels that call upon ports located within such countries. The implementation of the EEDI and SEEMP standards could cause us to incur additional compliance costs. The IMO is also considering the development of a market-based mechanism for greenhouse gas emissions from ships, but it is impossible to predict the likelihood that such a standard might be adopted or its potential impact on our operations at this time.

In the United States, the EPA has issued a final finding that greenhouse gases threaten public health and safety, and has promulgated regulations that regulate the emission of greenhouse gases. In 2009 and 2010, EPA adopted greenhouse reporting requirements for various onshore facilities, and also adopted a rule in 2011 imposing control technology requirements on certain stationary sources subject to the federal Clean Air Act. The EPA may decide in the future to regulate greenhouse gas emissions from ships and has already been petitioned by the California Attorney General to regulate greenhouse gas emissions from ocean-going vessels. Other federal and state regulations relating to the control of greenhouse gas emissions may follow, including climate change initiatives that have been considered in the U.S. Congress. Any passage of climate control legislation or other regulatory initiatives by the IMO, the United States, Brazil, Angola, or other countries where we operate, or any treaty adopted at the international level, that restrict emissions of greenhouse gases could require us to make significant financial expenditures that we cannot predict with certainty at this time. In addition, even without such regulation, our business may be indirectly affected to the extent that climate change results in sea level changes or more intense weather events.

Properties

Other than the drillships, we do not own any material property.

Legal Proceedings

From time to time we have been, and we expect that in the future us to be, subject to legal proceedings and claims in the ordinary course of business, principally personal injury and property casualty claims. These claims, even if lacking merit, could result in the expenditure of significant financial and managerial resources. We are not aware of any legal proceedings or claims that we believe will have, individually or in the aggregate, a

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material adverse effect on us or OPCO. Please also see Note 14, “Commitments and Contingencies” to the audited Combined Carve-out Financial Statements of our predecessor included elsewhere in this prospectus.

Taxation of the Partnership

We are organized as a limited partnership under the laws of the Republic of the Marshall Islands. Certain of our controlled affiliates are subject to taxation in the jurisdictions in which they are organized, conduct business or own assets. We intend that our business and the business of our controlled affiliates will be conducted and operated in a tax efficient manner. However, we cannot assure this result as tax laws in these or other jurisdictions may change or we may enter into new business transactions, which could affect our tax liabilities.

Marshall Islands

Because we and our controlled affiliates do not conduct business or operations in the Republic of the Marshall Islands, neither we nor our controlled affiliates will be subject to income, capital gains, profits or other taxation under current Marshall Islands law, and we do not expect this to change in the future. As a result, distributions DOV II receives from our controlled affiliates, and distributions we receive from DOV II, are not expected to be subject to Marshall Islands taxation.

United States

We will elect to be treated as a corporation for U.S. federal income tax purposes. As a result, we will be subject to U.S. federal income tax to the extent we earn income from U.S. sources or income that is treated as effectively connected with the conduct of a trade or business in the United States. We do not expect to earn a material amount of such income; however, we have a controlled affiliate that conducts drilling operations in the GOM that will be subject to taxation by the United States on its net income and may be required to withhold U.S. federal tax from distributions it makes to its owner.

Other Jurisdictions and Additional Information

We directly and indirectly own or control various additional subsidiaries that are subject to taxation in other jurisdictions. For additional information regarding the taxation of our subsidiaries, please read note 5 of our Combined Carve-out Financial Statements included elsewhere in this prospectus.

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MANAGEMENT

Management of Ocean Rig Partners LP

Our limited partnership agreement will provide that we will be managed by the board of directors and executive officers of our General Partner. Our General Partner will not be elected by our unitholders and will not be subject to re-election by our unitholders in the future. Our Sponsor owns all of the membership interests in our General Partner. Our General Partner will have a board of directors, and our common unitholders will not be entitled to elect the directors to participate directly or indirectly in our management or operations.

Following the closing of this offering, we expect that our General Partner will have at least five directors. Our Sponsor will appoint all members to the board of directors of our General Partner. Neither we nor our subsidiaries have any employees. Our Sponsor and its affiliates, including our General Partner will have the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business will be employed by our Sponsor and its affiliates, including our General Partner, but we sometimes refer to these individuals in this prospectus as our employees.

Corporate Governance Practices

Upon our listing on the Nasdaq Global Select Market, our General Partner will certify to Nasdaq that its corporate governance practices are in compliance with, and are not prohibited by, the laws of the Republic of the Marshall Islands. Therefore, it will be exempt from many of Nasdaq’s corporate governance practices other than the requirements regarding the disclosure of a going concern audit opinion, submission of a listing agreement, notification to Nasdaq of non-compliance with Nasdaq corporate governance practices, prohibition on disparate reduction or restriction of shareholder voting rights, and the establishment of an audit committee satisfying Nasdaq Listing Rule 5605(c)(3) and ensuring that such audit committee’s members meet the independence requirement of Listing Rule 5605(c)(2)(A)(ii). The practices we follow in lieu of Nasdaq’s corporate governance rules applicable to U.S. domestic issuers are as follows:

Audit Committee. Nasdaq requires, among other things, that a listed U.S. partnership have an audit committee with a minimum of three members, all of whom are independent. As permitted by Rule 10A-3 under the Exchange Act, our General Partner’s audit committee will be, effective as of the closing of this offering, comprised of one independent director.

Nominating/Corporate Governance Committee. Nasdaq requires that director nominees be selected, or recommended for the board’s selection, either by a nominating committee comprised solely of independent directors or by a majority of independent directors. Each listed company also must certify that it has adopted a formal charter or board resolution addressing the nominations process. As permitted under Marshall Islands law and our Partnership Agreement, our General Partner will not have a nominating or corporate governance committee.

Executive Sessions. Nasdaq requires that non-management directors meet regularly in executive sessions without management. Nasdaq also requires that all independent directors meet in an executive session at least once a year. As permitted under Marshall Islands law and our Partnership Agreement, we do not expect our General Partner’s non-management directors to hold executive sessions without management.

Corporate Governance Guidelines. Nasdaq requires that a listed U.S. partnership adopt a code of conduct applicable to all directors, officers and employees, which must provide for an enforcement mechanism. Disclosure of any director or officer’s waiver of the code and the reasons for such waiver is required. Our general partner is not required to adopt such guidelines under Marshall Islands law and we do not expect it to adopt such guidelines.

Proxies.As a foreign private issuer, we are not required to solicit proxies or provide proxy statements to Nasdaq pursuant to Nasdaq corporate governance rules or Marshall Islands law. Consistent with Marshall Islands

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law and as provided in our Partnership Agreement, we will notify our unitholders of meetings between 15 and 60 days before a meeting. This notification will contain, among other things, information regarding business to be transacted at the meeting. In addition, our Partnership Agreement provides that unitholders must give us between 150 and 180 days advance notice to properly introduce any business at a meeting of unitholders.

Other than as noted above, we are in compliance with all Nasdaq corporate governance standards applicable to U.S. domestic issuers. We believe that our established corporate governance practices satisfy Nasdaq’s listing standards.

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. The board of directors of our General Partner will determine whether to refer a matter to the conflicts committee on a case-by-case basis. 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 Nasdaq 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 any incentive compensation plan we may enter into. In connection with his appointment to the board, we expect that             will serve as a member of our conflicts committee. If our General Partner seeks approval from the conflicts committee, then it will be presumed that, in making its decision, the conflicts committee acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read “Conflicts of Interest and Duties.”. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Management and Administrative Services Agreement.”

Our General Partner’s officers and the other individuals providing services to us or our subsidiaries may face a conflict regarding the allocation of their time between our business and the other business interests of our Sponsor or the other companies they serve. Initially, we estimate that             will devote approximately     % of his time and             will devote approximately     % of his time to the management of our business. However, the amount of time our officers will allocate between our business and the business of our Sponsor or the other companies they serve will vary from time to time depending on various circumstances and needs of the businesses, such as the level of strategic activities of the businesses. Our general partner’s officers intend to devote as much time to the management of our business and affairs as is necessary for the proper conduct of our business and affairs.

Whenever our General Partner makes a determination or takes or declines to take an action, our Partnership Agreement provides that it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us or any member, except as required by applicable law. Specifically, our General Partner will be considered to be acting free of any fiduciary duty or obligation if it exercises its call right, pre-emptive rights, registration rights or right to make a determination to receive common units in a resetting of the target distribution levels related to its incentive distribution rights, appoints any directors or votes for the appointment of any director, votes or refrains from voting on amendments to our Partnership Agreement that require a vote of the outstanding units, voluntarily withdraws from the company, transfers (to the extent permitted under our Partnership Agreement) or refrains from transferring its units, its non-economic limited partner interest in us or the incentive distribution rights it owns or votes upon the dissolution of the company.

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Directors

The following provides information about each of the directors and director nominees of our General Partner. The business address through which the board can be contacted is c/o Ocean Rig Management Inc., 109 Kifisias Ave. and Sina Str., GR-15124, Amaroussion, Athens, Greece.

Name Age Position

Executive Officers

We currently do not employ any of our executive officers and rely solely on our Sponsor and its affiliates to provide us with personnel who will perform executive officer services for our benefit pursuant to the management and administrative services agreements and who will be responsible for our day-to-day management subject to the direction of the board of directors of our General Partner. Our Sponsor and its affiliates also provides certain advisory, technical management services to OPCO’s Initial Fleet and will provide administrative services to us pursuant to the management and administrative services agreement. The following provides information about each of the personnel of our Sponsor and its affiliates who will perform executive officer services for us. The business address for our executive officers is c/o Ocean Rig Management Inc., 109 Kifisias Ave. and Sina Str., GR-15124, Amaroussion, Athens, Greece.

Name	Age	Position
Niki Fotiou	44	President, Secretary, Treasurer and Director of Ocean Rig Partners GP LLC

Niki Fotiou was appointed President, Secretary, Treasurer and Director of our General Partner on April 16, 2014. Ms. Fotiou has served as the Senior Vice President Head of Accounting and Reporting for DryShips Inc. since January 2010. From July 2006 to December 2009, Ms. Fotiou served as the Group Controller of Cardiff Marine Inc. For the period from 1993 to 2006, Ms. Fotiou worked for Deloitte and for Hyatt International Trade and Tourism Hellas. Ms Fotiou is a graduate of the University of Cape Town and is a member of the Association of Chartered Certified Accountants. Ms Fotiou serves as Chief Financial Officer and corporate secretary of Allships Ltd. since 2009.

Reimbursement of Expenses

Our general partner will not receive compensation from us for any services it may provide on our behalf, although it will be entitled to reimbursement for expenses incurred on our behalf. In addition, we will reimburse our Sponsor and its affiliates for expenses incurred pursuant to the management and administrative services agreements that we will enter into with our Sponsor and its affiliates read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Management and Administrative Services Agreements.”

Executive Compensation

We have not paid nor do we expect to pay any compensation to the officers or directors of our General Partner nor accrue any obligations with respect to management incentive or retirement benefits prior to this offering. Under the management and administrative services agreements, we will reimburse our General Partner for its reasonable costs and expenses incurred in connection with the provision of executive officer and other administrative services to us. In addition, we will pay our General Partner a management fee equal to     % of the

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costs and expenses incurred on our behalf. We expect that we will pay approximately $             million in total under the management and administrative services agreements for the twelve months ending September 30, 2015. We have estimated this amount based on the experience of our Sponsor, which is a public company. The amount of our reimbursement to our General Partner for the time of any executive officers will depend on an estimate of the percentage of time our officers will spend on our business and will be based upon a percentage of the salary and benefits our General Partner, as applicable, will pay to such officers after the closing of this offering. We do not expect to pay any additional compensation to our officers. Officers and employees of affiliates of our Sponsor may participate in employee benefit plans and arrangements sponsored by our Sponsor or its affiliates, including plans that may be established in the future. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Management and Administrative Services Agreements.”

Compensation of Directors

Our officers or officers of our Sponsor who also serve on the board of directors of our General Partner will not receive additional compensation for their service as directors but may receive director fees in lieu of other compensation paid by our Sponsor. We anticipate that each non-management director will receive compensation for attending meetings of the board of directors of our General Partner, as well as committee meetings. We expect non-management directors will each receive a director fee of $         per year. Members of the audit and conflicts committees will each receive a committee fee of $         per year. In addition, each director will be reimbursed for out-of-pocket expenses in connection with attending meetings board of directors of our General Partner or committees. Each director will be fully indemnified by us for actions associated with being a director to the extent permitted under Marshall Islands law.

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SECURITY OWNERSHIP

OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of units of Ocean Rig Partners LP that will be issued upon the consummation of this offering and the related transactions, beneficial owners of 5% or more of the units, and all of our directors, director nominees and executive officers as a group.

Name of Beneficial Owner	Common Units to be Beneficially Owned After the Offering					Subordinated Units to be Beneficially Owned After the Offering				Percentage of Total Common and Subordinated Units to be Beneficially Owned After the Offering
	Number		Percent			Number		Percent
Ocean Rig(1)				%	(2)				%		%	(2)
All directors, director nominees and executive officers as a group		—		—			—		—		—

* Less than 1% of our outstanding common units.

(1) Our Sponsor, has a business address of 10 Skopa Street, Tribune House, 2nd Floor, Office 202, CY 1075, Nicosia, Cyprus.

(2) Assumes no exercise of the underwriters’ option to purchase additional common units. If the underwriters exercise their option in full, our Sponsor’s percentage of common units to be beneficially owned after the offering will decrease to     %, and its percentage of total common and subordinated units to be beneficially owned will decrease to     %.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, our Sponsor, the owner of our General Partner member interest and a     % limited partner interest in OPCO, will             own             common units and             subordinated units, representing a     % limited partner in us, assuming no exercise of the underwriters’ option to purchase additional common units, and all of our incentive distribution rights. In addition, our General Partner will own a non-economic general partner interest in us. our Sponsor’s ability, as the sole member of our General Partner, to control the appointment of its board of directors and to approve certain significant actions it may take, and our Sponsor’s common and subordinated unit ownership and its right to vote the subordinated units as a separate class on certain matters, means that it, together with its affiliates, will have the ability to exercise influence regarding our management.

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 our formation, ongoing operation and any liquidation. 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 our Sponsor and its affiliates for our interest in OPCO’s Initial Fleet, that we will acquire at or prior to the closing of this offering	•     We will redeem the initial limited partner interests held by our Sponsor and will refund the Sponsor’s initial contribution in the amount of $         made in connection with the formation of the Partnership and will: •     issue to our Sponsor         Common Units and Subordinated Units; •     issue to the General Partner the non-economic interest in the Partnership and all of the incentive distribution rights; •     through DOV II will assume the New Senior Secured Term Loan Facility from DOV I and the guarantee of our Sponsor will be unconditionally released; and •     cause OPCO to issue to OPCO Holdings     % of its limited partner interests. •     In this public offering, we will issue             common units representing an aggregate     % limited partner interest in us. We estimate that we will receive net proceeds from this offering of $         million, of which $         million will be paid to our Sponsor through DOV I as partial consideration paid for our interests in OPCO’s Initial Fleet. See “Use of Proceeds”;
	Please read “Summary—Formation Transactions” for further information about our formation and the assets contributed to us in connection with the closing of this offering.
	The common units and subordinated units to be owned by our Sponsor after giving effect to this offering represent a

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	% limited partner interest in us, assuming no exercise of the underwriters’ over-allotment option. For more information, please read “The Partnership Agreement—Voting Rights” and “The Partnership Agreement—Amendment of the Partnership Agreement.”
Operational Stage
Distributions of available cash to our General Partner and its affiliates	We will generally make cash distributions of all available cash to unitholders (including our Sponsor, the owner of             common units and subordinated units).
	In addition, if distributions exceed the minimum quarterly distribution and other higher target levels, our General Partner, as the holder of the incentive distribution rights, will be entitled to increasing percentages of the distributions, up to 50% of the distributions above the highest target level. We refer to the rights to the increasing distributions as “incentive distribution rights.” Please read “How We Make Cash Distributions—Incentive Distribution Rights” for more information regarding the incentive distribution rights.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, but no distributions in excess of the full minimum quarterly distribution, our Sponsor would receive an annual distribution of approximately $         million on its common and subordinated units.
Payments to our General Partner and its affiliates	Our General Partner will not receive compensation from us for any services it provides on our behalf. our General Partner and its other affiliates will be entitled to reimbursement for all direct and indirect expenses they incur on our behalf. In addition, we will (and any of our future operating subsidiaries may) pay fees to our Sponsor and its affiliates and certain other affiliates of our Sponsor for advisory, technical and administrative services. We will also reimburse these entities for costs related to the advisory, technical and administrative services they provide. We will also pay fees to our Sponsor and its affiliates and reimburse our Sponsor and its affiliates for expenses related to its provision of administrative and other management services pursuant to the management and administrative services agreement. Please read “—Agreements Governing the Transactions—Management and Administrative Services Agreements” and “—Agreements Governing the Transaction—Advisory, Technical and Administrative Services Agreements.”
Withdrawal or removal of our General Partner	If our General Partner withdraws or is removed, its non-economic limited partner interest in us and any incentive distribution rights it holds will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of our General Partner.”

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Liquidation Stage
Liquidation	Upon our liquidation, the members, including our General Partner, will be entitled to receive liquidating distributions as described in “The Partnership Agreement—Liquidation and Distribution of Proceeds.”

Agreements Governing the Transactions

We, our General Partner, our subsidiaries and certain affiliates have entered into or will enter into various documents and agreements that will affect the transactions relating to our formation and this offering, including our acquisition of interests in OPCO, the vesting of assets in, and the assumption of liabilities by, us and OPCO and the application of the proceeds of this offering. These agreements will not be the result of arm’s-length negotiations and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

Omnibus Agreement

At the closing of this offering, we and OPCO will enter into an Omnibus Agreement with our Sponsor, our General Partner and certain of our and OPCO’s other subsidiaries. The following discussion describes certain provisions of the Omnibus Agreement.

Noncompetition

Under the Omnibus Agreement, our Sponsor will agree, and will cause its controlled affiliates (other than us, our General Partner and our subsidiaries) to agree, not to acquire, own, operate or contract for any drillships operating under a contract for four or more years. We refer to these drillships, together with any related contracts, as “Four-Year Drillships” and to all other drillships, together with any related contracts, as “Non- Four-Year Drillships”. The restrictions in this paragraph will not prevent our Sponsor or any of its controlled affiliates (including us and our subsidiaries) from:

(1) acquiring, owning, operating or contracting for “Non- Four-Year Drillships”;

(2) acquiring one or more Four-Year Drillships if our Sponsor promptly offers to sell the drillships to us for the acquisition price plus any administrative costs (including reasonable legal costs) associated with the transfer to us at the time of the acquisition;

(3) putting a Non-Four Year Drillship under contract for four or more years if our Sponsor offers to sell the drillship to us for fair market value (x) promptly after the time it becomes a Four-Year Drillship and (y) at each renewal or extension of that contract for four or more years;

(4) acquiring one or more Four-Year Drillships as part of the acquisition of a controlling interest in a business or package of assets and owning, operating or contracting for those drillships; provided, however, that:

(a) if less than a majority of the value of the business or assets acquired is attributable to Four-Year Drillships, as determined in good faith by our Sponsor’s board of directors, Our Sponsor must offer to sell such drillships to us for their fair market value plus any additional tax or other similar costs that our Sponsor incurs in connection with the acquisition and the transfer of such drillships to us separate from the acquired business; and

(b) if a majority or more of the value of the business or assets acquired is attributable to Four-Year Drillships, as determined in good faith by our Sponsor’s board of directors, our Sponsor must

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notify us of the proposed acquisition in advance. Not later than 10 days following receipt of such notice, we will notify our Sponsor if we wish to acquire such drillships in cooperation and simultaneously with our Sponsor acquiring the Non- Four-Year Drillships. If we do not notify our Sponsor of our intent to pursue the acquisition within 10 days, our Sponsor may proceed with the acquisition and then offer to sell such drillships to us as provided in (a) above;

(5) acquiring a non-controlling interest in any company, business or pool of assets;

(6) acquiring, owning, operating or contracting for any Four-Year Drillships if we do not fulfill our obligation to purchase such drillship in accordance with the terms of any existing or future agreement;

(7) acquiring, owning, operating or contracting for a Four-Year Drillship subject to the offers to us described in paragraphs (2), (3) and (4) above pending our determination whether to accept such offers and pending the closing of any offers we accept;

(8) providing drillship management services relating to any drillship;

(9) owning or operating a Four-Year Drillship that our Sponsor owns and operates at the time of this offering and that is not included in OPCO’s initial fleet; or

(10) acquiring, owning, operating or contracting for a Four-Year Drillship if we have previously advised our Sponsor that we consent to such acquisition, operation or contract.

If our Sponsor or any of its controlled affiliates (other than us or our subsidiaries) acquires, owns, operates or contracts for Four-Year Drillships pursuant to any of the exceptions described above, it may not subsequently expand that portion of its business other than pursuant to those exceptions.

Under the Omnibus Agreement we will not be restricted from acquiring, operating or contracting for Non- Four-Year Drillships.

Upon a change of control of us or our General Partner, the noncompetition provisions of the Omnibus Agreement will terminate immediately. Upon a change of control of our Sponsor, the noncompetition provisions of the Omnibus Agreement applicable to our Sponsor will terminate at the time that is the later of the date of the change of control and the date on which all of our outstanding subordinated units have converted to common units.

Rights to Purchase Additional Interests in OPCO’s Fleet

We will receive the right to purchase additional interests in OPCO’s Initial Fleet or the Additional Fleet Interests, from our Sponsor at a purchase price to be determined pursuant to the terms and conditions of the Omnibus Agreement. These purchase rights will expire 24 months following the completion of this offering. If we are unable to agree with our Sponsor on the purchase price of any of the Additional Fleet Interests, the respective purchase price will be determined by an independent appraiser, such as an investment banking firm, broker or firm generally recognized in the offshore oil services and shipping industry as qualified to perform the tasks for which such firm has been engaged, and we will have the right, but not the obligation, to purchase each drilling unit at such price. The independent appraiser will be mutually appointed by our Sponsor and a committee comprised of certain of our independent directors, or the conflicts committee.

The purchase price of the Additional Fleet Interests, as finally determined by an independent appraiser, may be an amount that is greater than what we are able or willing to pay or we may be unwilling to purchase such vessel if such acquisition would not be in our best interests. We will not be obligated to purchase the Additional Fleet Interests at the determined price and, accordingly, we may not complete the purchase of such vessels, which may have an adverse effect on our expected plans for growth. In addition, our ability to purchase the Additional Fleet Interests, should we exercise our right to purchase such vessels, is dependent on our ability to obtain additional financing to fund all or a portion of the acquisition costs of these vessels. As of the date of this prospectus, we have not secured any financing in connection with the potential acquisition of the Additional Fleet Interests.

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Rights of First Offer on Drillships

Under the Omnibus Agreement, our Sponsor will agree (and will cause its subsidiaries, other than us, to agree) to grant a right of first offer to us for any Four-Year Drillships they might own. These rights of first offer will not apply to a (a) sale, transfer or other disposition of drillships between, or among, any affiliated subsidiaries or the (b) merger with or into, or sale of substantially all of the assets to, an unaffiliated third-party.

Prior to engaging in any negotiation regarding any drillship’s disposition with respect to a Four-Year Drillship with a non-affiliated third-party our Sponsor will deliver a written notice to us setting forth the material terms and conditions of the proposed transaction. During the 30-day period after the delivery of such notice, we and our Sponsor will negotiate in good faith to reach an agreement on the transaction. If we do not reach an agreement within such 30-day period, our Sponsor will be able within the next 180 calendar days to sell, transfer, dispose or re-contract the drillship to a third party (or to agree in writing to undertake such transaction with a third party) on terms generally no less favorable to us or our Sponsor, as the case may be, than those offered pursuant to the written notice.

Upon a change of control of us or our General Partner, the right of first offer provisions of the Omnibus Agreement will terminate immediately. Upon a change of control of our Sponsor, the right of first offer provisions applicable to our Sponsor under the our Omnibus Agreement will terminate at the time that is the later of the date of the change of control and the date on which all of our outstanding subordinated units have converted to common units.

Rights to Purchase Interests in the Optional Drillships

Pursuant to the Omnibus Agreement ownership, we will have the right to purchase interests, or the Optional Drillship Interests, in four sixth generation advanced capability ultra-deepwater drillships, currently 100% owned by our Sponsor. TheOcean Rig Corcovado, theOcean Rig Olympia, theOcean Rig Poseidonand theOcean Rig Mykonos, delivered in January 2011, March 2011, July 2011 and September 2011, respectively and are “sister-ships” constructed by Samsung to the same high-quality vessel design and specifications and are capable of drilling up to 40,000 feet in water depths of up to 10,000 feet.

The purchase price for the Optional Drillships will be determined pursuant to the terms and conditions of the Omnibus Agreement. These purchase rights will expire 36 months following the completion of the offering. If we are unable to agree with our Sponsor on the purchase price of any of the Optional Drillship Interests, the respective purchase price will be determined by an independent appraiser, such as an investment banking firm, broker or firm generally recognized in the shipping or offshore drilling industries as qualified to perform the tasks for which such firm has been engaged, and we will have the right, but not the obligation, to purchase each vessel at such price. The independent appraiser will be mutually appointed by our Sponsor and a committee comprised of certain of our independent directors, or the conflicts committee.

The purchase price of the Optional Drillship Interests, as finally determined by an independent appraiser, may be an amount that is greater than what we are able or willing to pay or we may be unwilling to proceed to purchase such interest if such acquisition would not be in our best interests. We will not be obligated to purchase the Optional Drillship Interests at the determined price and, accordingly, we may not complete the purchase of such vessels, which may have an adverse effect on our expected plans for growth. In addition, our ability to purchase the Optional Drillship Interests Vessels, should we exercise our right to purchase such vessels, is dependent on our ability to obtain additional financing to fund all or a portion of the acquisition costs of these interests. As of the date of this prospectus, we have not secured any financing in connection with the potential acquisition of the Optional Rig Interests and it is uncertain if and when such purchase options will be exercised. In addition, we will be subject to other restrictions contained in our Sponsor’s and our existing debt agreements. Please see “Risk Factors— Our Sponsor may be unable to service its debt requirements and comply with the provisions contained in the debt agreements secured by the Optional Drillships. If our Sponsor fails to perform its obligations under its

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debt agreements, our business and expected plans for growth may be materially affected” and “–Our Sponsor’s debt agreements, including its aggregate principal amount $800 million 6.5% senior secured notes due 2017, or the Senior Secured Notes due 2017, contain restrictions that may limit our growth plans.”

Indemnification

Under the Omnibus Agreement, our Sponsor will indemnify us after the closing of this offering for a period of         years against certain environmental and toxic tort liabilities with respect to the assets contributed or sold to us to the extent arising prior to the time they were contributed or sold to us. Liabilities resulting from a change in law after the closing of this offering are excluded from the environmental indemnity. There is an aggregate cap of $         million on the amount of indemnity coverage provided by our Sponsor for environmental and toxic tort liabilities. No claim may be made unless the aggregate dollar amount of all claims exceeds $            , in which case our Sponsor is liable for claims only to the extent such aggregate amount exceeds $            .

our Sponsor will also indemnify us for liabilities related to:

• certain defects in title to our Sponsor’s assets contributed or sold to OPCO and any failure to obtain, prior to the time they were contributed, certain consents and permits necessary to conduct, own and operate such assets, which liabilities arise within years after the closing of this offering; and

• tax liabilities attributable to the operation of the assets contributed or sold to OPCO prior to the time they were contributed or sold.

Amendments

The Omnibus Agreement may not be amended without the prior approval of the conflicts committee of the board of directors of our General Partner if the proposed amendment will, in the reasonable discretion of the board of directors of our General Partner, adversely affect holders of our common units.

Management and Administrative Services Agreements

At the closing of this offering, we will have entered into a management and administrative services agreement with our Sponsor and its affiliates, pursuant to which our Sponsor and its affiliates or its affiliates will provide certain management and administrative support services to us. The agreement will have an initial term of     years.

The management and administrative services agreement with our Sponsor and its affiliates may be terminated prior to the end of its term by us upon days’ written notice for any reason in the sole discretion of the board of directors of our General Partner. In addition, the management and administrative services agreement may be terminated by our Sponsor and its affiliates upon days’ written notice if:

• there is a change of control of us or our General Partner;

• a receiver is appointed for all or substantially all of our property;

• an order is made to wind up our company;

• a final judgment, order or decree that materially and adversely affects our ability to perform the agreement is obtained or entered and not vacated, discharged or stayed; or

• we make a general assignment for the benefit of our creditors, file a petition in bankruptcy or liquidation or are adjudged insolvent or bankrupt or commence any reorganization proceedings.

Under the management and administrative services agreement with our Sponsor and its affiliates, certain officers of our Sponsor and its affiliates will provide executive officer functions for our benefit. These officers of our Sponsor and its affiliates will be responsible for our day-to-day management subject to the direction of the

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board of directors of our General Partner. The board of directors of our General Partner will have the ability to terminate the arrangement with our Sponsor and its affiliates regarding the provision of executive officer services to us with respect to any or all of such officers at any time in its sole discretion.

The management and administrative services provided by our Sponsor and its affiliates will include:

• Corporate Governance Services: assistance in the provision of general company secretarial services;

• Partnership Records Services: the safekeeping and professional filing of all original corporate documents;

• Treasury Services: assistance in the operation of bank accounts in accordance with such principles as our the board of directors of our General Partner from time to time shall approve; assistance in collection of accounts receivable and payment of accounts payable;

• Financing: assistance in all matters relevant to the financing of our activities, including the identification of sources of potential financing and negotiation of financing arrangements;

• Insurance: assistance in arranging to insure OPCO’s drillships and other necessary insurance and assistance in management of insurance claims;

• Sale and Purchase of Assets: assistance in the sale and purchase of assets including reviewing the market for the sale and purchase of assets, arranging the financing in the case of a purchase and if necessary renegotiating existing financing, and arranging any other contractual arrangements required by such transaction and the general completion of the specific transaction;

• Accidents—Contingency Plans: assistance in handling all accidents in the course of operations, and development of a crisis management procedure, and other advice and assistance in connection with crisis response, including crisis communications assistance;

• Disputes: assistance in the prosecution or defense of any and all legal proceedings by or against us;

• Marketing Services: assistance in the marketing of OPCO’s drillships; and

• General Administrative Services: any general administrative services as we may require.

Each quarter, we will reimburse our Sponsor and its affiliates for its reasonable costs and expenses incurred in connection with the provision of these services. In addition, we will pay our Sponsor and its affiliates a management fee equal to     % of its costs and expenses incurred in connection with providing services to us for the quarter. Amounts payable under the management and administrative services agreement must be paid within 30 days after our Sponsor and its affiliates submits to us an invoice for such fees, costs and expenses, together with any supporting detail that may be reasonably required.

Under the management and administrative services agreement with our Sponsor and its affiliates, we will indemnify our Sponsor and its affiliates and its officers, employees, agents and sub-contractors against all actions which may be brought against them under the management and administrative services agreement;provided, however that such indemnity excludes losses which may be caused by or due to the fraud, gross negligence or willful misconduct of our Sponsor and its affiliates or its officers, employees, agents or sub-contractors.

We expect that we will pay approximately $         million in total under the management and administrative services agreements for the twelve months ending             , 2014.

Drillship Management Agreements

Each of OPCO and its subsidiaries will enter into certain advisory, technical and/or administrative services agreements with affiliates of our Sponsor, pursuant to which such affiliates will provide advisory, technical and administrative services. Each quarter, OPCO’s subsidiaries will reimburse such our Sponsor affiliates for their

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reasonable costs and expenses incurred in connection with the provision of these services. In addition, OPCO’s subsidiaries will pay to such our Sponsor affiliates a service fee equal to     % of their costs and expenses incurred in connection with providing services to OPCO’s subsidiaries for the quarter. Amounts payable under advisory, technical and administrative services agreements must be paid within 30 days after such our Sponsor affiliate submits to the applicable OPCO subsidiary an invoice for such fees, costs and expenses, together with any supporting detail that may be reasonably required. We expect the amount of these fees and expenses to be approximately $         million for the twelve months ending             . Such services will include:

• Operations Services: assistance and support for the development of technical standards, supervision of third-party contractors, development of maintenance practices and strategies, development of operating policies, improvement of efficiency, minimizing environmental and safety incidents, periodic auditing of operations and purchasing and logistics;

• Technical Supervision Services: assistance and advice on maintaining vessel classification and compliance with local regulatory requirements, compliance with contractual technical requirements for the drillships, ensuring that technical operations are professional and satisfactory in every respect;

• Accidents—Contingency Plans: assistance in handling all accidents in the course of operations, and development of a crisis management procedure, and other advice and assistance in connection with crisis response, including crisis communications assistance; and

• General Administrative Services: any general administrative services as needed.

Under the advisory, technical and administrative services agreements, OPCO’s operating subsidiaries will indemnify certain affiliates of our Sponsor and their officers, employees, agents and sub-contractors against all actions which may be brought against them under the advisory, technical and administrative services agreements; provided, however that such indemnity excludes losses which may be caused by or due to the fraud, gross negligence or willful misconduct of our Sponsor and its affiliates or its officers, employees, agents and sub-contractors. Except for losses that are caused by or due to the fraud of our Sponsor and its affiliates or its officers, employees, agents and sub-contractors, in no event shall such affiliates of our Sponsor’s liability to us exceed ten times the annual services fee.

Other Related Party Transactions

Historically, our predecessor and its subsidiaries were operated as an integrated part of our Sponsor. As such, our Sponsor has provided general and corporate management services, and technical and commercial management services for OPCO. As described in note 2 to the 2013 Combined Carve-out Financial Statements included elsewhere in this prospectus, we have allocated administrative expenses, expenses for technical and commercial management of the drillships and insurance costs related to these historical operations based on the number of drilling units in our Sponsor’s fleet. Amounts allocated to us and included within our administrative expenses were $16.8 million and $4.3 million for the years ended December 31, 2013 and 2012, respectively.

As a result of our relationships with our Sponsor and its affiliates, we and our subsidiaries have entered into or will enter into various agreements that will not be the result of arm’s length negotiations. We generally refer to these agreements and the transactions that they provide for as “affiliated transactions” or “related party transactions.”

Our Partnership Agreement sets forth procedures by which future related party transactions may be approved or resolved by our board. Pursuant to our Partnership Agreement, the board of directors of our General Partner may, but will not be required to, seek the approval of a related party transaction from the conflicts committee of the board of directors of our General Partner or from the common unitholders. Affiliated transactions that are not approved by the conflicts committee of the board of directors of our General Partner and that do not involve a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable” to us. In determining whether a transaction or

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resolution is “fair and reasonable,” the board of directors of our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. If the above procedures are followed, it will be presumed that, in making its decision, the board of directors of our General Partner acted in good faith, and in any proceeding brought by or on behalf of any member or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. When our Partnership Agreement requires someone to act in good faith, it requires that person to believe that he is acting in the best interests of the company, unless the context otherwise requires. Please read “Conflicts of Interest and Fiduciary Duties.”

Our conflicts committee will be comprised of at least two members the board of directors of our General Partner. The conflicts committee will be available at the board’s discretion to review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us and may consider any and all circumstances it determines to be relevant or appropriate under the circumstances. The members of the conflicts committee may not be officers or employees of us or directors, officers or employees of our General Partner or its affiliates or security holders of our Sponsor, and must meet the independence standards established by the Nasdaq Global Select Market to serve on an audit committee of the board of directors of our General Partner and certain other requirements.

Global Services Agreement

Effective as of January 1, 2013, our Sponsor Management entered into a Global Services Agreement with Cardiff Marine Inc., or Cardiff, a company controlled by the Chairman, President and Chief Executive Officer of our Sponsor and DryShips, Mr. George Economou, pursuant to which Ocean Rig Management engaged Cardiff to act as consultant on matters of chartering and sale and purchase transactions for the offshore drilling units operated by our Sponsor, including DOV II. Under the Global Services Agreement, Cardiff, or its subcontractor, (i) provides consulting services related to the identification, sourcing, negotiation and arrangement of new employment for OPCO’s offshore assets; and (ii) identified, sourced, negotiated and arranged the sale or purchase of OPCO’s offshore assets. In consideration of such services, our Sponsor pays Cardiff a fee of 1.0% in connection with employment arrangements and 0.75% in connection with sale and purchase activities. Costs from the Global Services Agreement were expensed in combined statements of operations or capitalized as a component of “Advances for drillships under construction and related costs” being a directly attributable cost to the construction, as applicable, and as a shareholders’ contribution to capital (“Additional paid-in capital”). For the year ended December 31, 2013, we incurred costs of $5.7 million, related to sale and purchase activities, which are capitalized as a component of “Drillship, machinery and equipment, net,” in the predecessor combined carve-out balance sheet and $0.7 million related to employment arrangements, which are included in “Service Revenue, net” in the predecessor combined carve-out statements of operations. Balance due to Cardiff Drilling Inc., under New Global Services Agreement, at December 31, 2013 was nil. For the period ended             , 2014, we incurred a cost of approximately $         and $         under Global Services Agreement related to employment arrangements and sale and purchase activities, respectively which are included in “Service revenue, net” in the unaudited interim condensed consolidated statement of operations and capitalized as a component of “Advances for drillships under construction,” respectively. At             , 2014, an amount of approximately $         was payable to Cardiff and is included in “Due to related party” in the accompanying consolidated balance sheets.

Vivid Finance Limited

Effective from January 1, 2013, Ocean Rig Management entered into a consultancy agreement with Vivid Finance Limited, or Vivid, a company controlled by the Chairman, President and Chief Executive Officer of our Sponsor and DryShips, Mr. George Economou, pursuant to which Vivid acts as a consultant on financing matters for DryShips and its affiliates Vivid provides our Sponsor with financing-related services such as (i) negotiating and arranging new loan and credit facilities, interest rate swap agreements, foreign currency contracts and forward exchange contracts, (ii) renegotiating existing loan facilities and other debt instruments and (iii) the raising of equity or debt in the capital markets. In exchange for its services to us, Vivid was entitled to a fee equal to 0.20% on the

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total transaction amount. The consultancy agreement has a term of five years and may be terminated (i) at the end of its term unless extended by mutual agreement of the parties; (ii) at any time by the mutual agreement of the parties; and (iii) by Ocean Rig Management after providing written notice to Vivid at least 30 days prior to the actual termination date. The Partnership does not pay for such services, provided in accordance with this agreement, since equal equity contributions are made by our Sponsor. Accordingly, these expenses were recorded in the combined statement of operations (or as otherwise required by US GAAP) and as a shareholders contribution to capital (“Additional paid-in capital”). For the years ended December 31, 2012 and 2013, total charges from Vivid under the agreement amounted to approximately $2.4 million and $8.1 million, respectively which are included in “General and administrative expenses” in the predecessor combined carve-out statement of operations. Balance due to Vivid, under the new consultancy agreement, at December 31, 2013 was nil.

Supervisory Management Agreement

Ocean Rig AS, a subsidiary of our Sponsor, provides supervisory, technical and commercial management services including onshore management, to OPCO’s operating drillships and drillships pursuant to separate management agreements entered into with each of the drilling unit-owning subsidiaries.

Under the terms of these management agreements, Ocean Rig AS, through its affiliates in Stavanger, Norway, Aberdeen, United Kingdom and Houston, Texas, is responsible for, among other things, (i) assisting in construction contract technical negotiations, (ii) securing contracts for the future employment of the drilling units, and (iii) providing commercial, technical and operational management for the drillships. Ocean Rig AS is paid a percentage mark-up of operating costs per drillship. Specifically, Ocean Rig AS is paid a 5% mark-up of all operating costs attributable to rendering administrative services, a 7% mark-up of all operating costs attributable to rendering commercial management and insurance services and a 7% mark-up of all operating costs attributable to rendering the technical management services. Balance due to Ocean Rig AS of December 31, 2013 was nil.

Ocean Rig Management Inc.:During 2013, the Sponsor’s wholly owned subsidiary, Ocean Rig Management Inc. (“Ocean Rig Management”), has entered into separate management agreements with the owning subsidiaries of the drillshipsOcean Rig SkyrosandOcean Rig Athena. Under the terms of these management agreements, Ocean Rig Management, through its affiliates in Stavanger, Norway, Aberdeen, United Kingdom and Houston, Texas, is responsible for, among other things, (i) assisting in construction contract technical negotiations, (ii) securing contracts for the future employment of the drilling units, and (iii) providing commercial, technical and operational management for the drillships. For the year ended December 31, 2013, there were no charges from Ocean Rig Management under these agreements.

Joint Venture, Agency and Sponsorship Relationships

In some areas of the world, local customs and practice or governmental requirements necessitate the formation of joint ventures with local participation. Local laws or customs in some areas of the world also effectively mandate establishment of a relationship with a local agent or sponsor. When appropriate in these areas, we will enter into agency or sponsorship agreements. For more information regarding the regulations in the countries in which we currently are contracted to operate, please see “Business—Environmental and Other Regulations in the Offshore Drilling Industry.”

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our General Partner and its affiliates, including our Sponsor, on the one hand, and us and our unaffiliated members, on the other hand. Our general partner has fiduciary duty to manage us in a manner it believes is beneficial to us. We expect that certain of our executive officers and a majority of our directors will also be directors and officers of our Sponsor or its affiliates and, as such, they will owe fiduciary duties to our Sponsor that may cause them to pursue business strategies that disproportionately benefit our Sponsor or which otherwise are not in the best interests of us or our unitholders. Certain of our executive officers are employed by our Sponsor and its affiliates and have fiduciary duties to that entity and not to us. As a result of these relationships, conflicts of interest may arise between us and our unaffiliated members on the one hand, and our Sponsor and its other affiliates, including our General Partner, on the other hand. The resolution of these conflicts may not be in the best interest of us or our unitholders.

Our partnership affairs are governed by our Partnership Agreement and the Marshall Islands Act. The provisions of the Marshall Islands Act resemble provisions of the limited partnership laws of a number of states in the United States, most notably Delaware. We are not aware of any material difference in unitholder rights between the Partnership Act and the Delaware Revised Uniform Limited Partnership Act. The Marshall Islands Act also provides that it is to be applied and construed to make it uniform with the Delaware Revised Uniform Limited Partnership Act and, so long as it does not conflict with the Marshall Islands Act or decisions of the Marshall Islands courts, interpreted according to the non-statutory law or “case law” of the courts of the State of Delaware. There have been, however, few, if any, court cases in the Marshall Islands interpreting the Marshall Islands Act, in contrast to Delaware, which has a fairly well-developed body of case law interpreting its limited partnership statute. Accordingly, we cannot predict whether Marshall Islands courts would reach the same conclusions as courts in Delaware. For example, the rights of our unitholders and fiduciary responsibilities of our General Partner and its affiliates under Marshall Islands law are not as clearly established as under judicial precedent in existence in Delaware. Due to the less-developed nature of Marshall Islands law, our public unitholders may have more difficulty in protecting their interests or seeking remedies in the face of actions by our General Partner, its affiliates or our controlling unitholders than would unitholders of a limited partnership organized in the United States.

Our Partnership Agreement contains provisions that limit the duties of our General Partner and its directors and officers would otherwise have had to the unitholders. Our Partnership Agreement also restricts the remedies available to unitholders for actions taken by our General Partner or its directors or officers that, without those limitations, might constitute breaches of those duties.

Neither our general partner nor its board of directors will be in breach of their obligations under the Partnership Agreement or their duties to us or the unitholders if the resolution of the conflict is:

• approved by the conflicts committee, although neither our General Partner nor its board of directors are obligated to seek such approval;

• approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner or any of its affiliates, although neither our General Partner nor its board of directors is obligated to seek such approval;

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties, but neither our General Partner nor its board of directors is required to obtain confirmation to such effect from an independent third party; or

• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our General Partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors, except that OPCO’s Operating Agreement requires the approval of the

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conflicts committee of our board to amend OPCO’s Operating Agreement or the limited liability company agreement of Ocean Rig Operating GP LLC. If the board of directors of our General Partner of directors does not seek approval from the conflicts committee (other than for, and only with respect to, amendments to OPCO’s Operating Agreement or the limited liability company agreement of Ocean Rig Operating GP LLC), and the board of directors of our General Partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors of our General Partner, including the board members affected by the conflict, acted in good faith, and in any proceeding brought by or on behalf of any member or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. When our Partnership Agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the company, unless the context otherwise requires. Please read “Management—Management of Ocean Rig Partners LP” for information about the composition and formation of the conflicts committee of the board of directors of our General Partner.

Conflicts of interest could arise in the situations described below, among others.

Actions Taken by the Board of Directors of our General Partner May Affect the Amount of Cash Available for Distribution to Unitholders or Accelerate the Right to Convert Subordinated Units.

The amount of cash that is available for distribution to unitholders is affected by decisions of the board of directors of our General Partner regarding such matters as:

• the amount and timing of asset purchases and sales;

• cash expenditures;

• borrowings;

• estimates of maintenance and replacement capital expenditures;

• the issuance of additional units; and

• the creation, reduction or increase of reserves in any quarter.

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our General Partner or our directors or officers to our unitholders, including borrowings that have the purpose or effect of:

• enabling our General Partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

• hastening the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common units and our subordinated units, our Partnership Agreement permits us to borrow funds, which would enable us to make this distribution on all outstanding units. Please read “How We Make Cash Distributions—Subordination Period.”

Our Partnership Agreement will provide that we and our subsidiaries may borrow funds from our General Partner and its affiliates. our General Partner and its affiliates may not borrow funds from us or our subsidiaries.

Neither Our Partnership Agreement Nor Any Other Agreement Requires Ocean Rig to Pursue a Business Strategy That Favors us or Utilizes Our Assets or Dictates What Markets to Pursue or Grow. Ocean Rig’s Directors and Executive Officers Have a Fiduciary Duty to Make These Decisions in the Best Interests of The Shareholders of Ocean Rig, Which May Be Contrary to Our Interests.

Because we expect that certain of our officers and a majority of our directors will also be directors and/or officers of our Sponsor, such officers and directors will have fiduciary duties to our Sponsor that may cause them to pursue business strategies that disproportionately benefit our Sponsor or which otherwise are not in the best interests of us or our unitholders.

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Certain of Our Officers Face Conflicts in the Allocation of Their Time to Our Business.

Certain of our officers, who are employed by our Sponsor and its affiliates and perform executive officer functions for us pursuant to the management and administrative services agreements, are not required to work full-time on our affairs and also perform services for affiliates of our Sponsor. For example             also provides services in a similar capacity for our Sponsor. The affiliates of our Sponsor conduct substantial businesses and activities of their own in which we have no economic interest. As a result, there could be material competition for the time and effort of our officers who also provide services to our Sponsor’s affiliates, which could have a material adverse effect on our business, results of operations and financial condition.

We Will Reimburse our General Partner and its Affiliates For Expenses.

We will reimburse our General Partner and its affiliates for costs incurred, if any, in managing and operating us. Our Partnership Agreement will provide that our General Partner will determine the expenses that are allocable to us in good faith. Please read “Certain Relationships and Related Party Transactions” and “Management—Reimbursement of Expenses of our General Partner.”

Common Unitholders Will Have no Right to Enforce Obligations of Ocean Rig and its Affiliates Under Agreements With us.

Any agreements between us, on the one hand, and our Sponsor and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our Sponsor and its affiliates in our favor.

Contracts Between us, on The One Hand, and Ocean Rig and its Affiliates, on the Other, Will Not Be the Result of Arm’s-length Negotiations.

Neither our Partnership Agreement nor any of the other agreements, contracts and arrangements between us and our Sponsor and its affiliates are or will be the result of arm’s-length negotiations. Our Partnership Agreement will generally provide that any affiliated transactions, such as an agreement, contract or arrangement between us and our Sponsor and its affiliates, must be:

• on terms no less favorable to us than those generally being provided to or available from unrelated third parties but our General Partner is required to obtain confirmation to such effect from an independent third party; or

• “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

Our Sponsor and its affiliates, which will provide certain management and administrative services to us, may also enter into additional contractual arrangements with any of its affiliates on our behalf; however, there is no obligation of any affiliate of our Sponsor and its affiliates to enter into any contracts of this kind.

Common Units are Subject to our General Partner’s Limited Call Right.

Our General Partner may exercise its right to call and purchase common units as provided in the Partnership Agreement or assign this right to one of its affiliates or to us. Our General Partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon the exercise of this limited call right. As a result, a common unitholder may have common units purchased from the unitholder at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

We May Choose not to Retain Separate Counsel for Ourselves or for the Holders of Common Units.

The attorneys, independent accountants and others who perform services for us will be retained by our General Partner. Attorneys, independent accountants and others who perform services for us are selected by the

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board of directors of our General Partner or the conflicts committee and may perform services for our Sponsor and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our Sponsor and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Ocean General Partner’s Affiliates, Including Ocean Rig, May Compete With us.

Our Partnership Agreement provides that our General Partner will be restricted from engaging in any business activities other than acting as our General Partner and those activities incidental to its ownership of interests in us. In addition, our Partnership Agreement provides that our General Partner, for as long as it is the holder of our General Partner interest, will cause its affiliates not to engage in, by acquisition or otherwise, the business described in “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Noncompetition.” Similarly, under the Omnibus Agreement, our Sponsor will agree and will cause their affiliates to agree, for so long as our Sponsor controls us, not to engage in the businesses described above under the caption “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement—Noncompetition.” Except as provided in our Partnership Agreement and the Omnibus Agreement, affiliates of our General Partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us

Fiduciary Duties

Our General Partner and its affiliates are accountable to us and our unitholders as fiduciaries. Fiduciary duties owed to unitholders by our General Partner and its affiliates are prescribed by law and the Partnership Agreement. The Partnership Act provides that Marshall Islands partnerships may, in their Partnership Agreements, restrict or expand the fiduciary duties owed by our General Partner and its affiliates to the limited partners and the partnership. Our directors are subject to the same fiduciary duties as our General Partner, as restricted or expanded by the Partnership Agreement.

• Our Partnership Agreement will contain various provisions restricting the fiduciary duties that might otherwise be owed by our General Partner or by our directors. We have adopted these provisions to allow our General Partner and our directors to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our officers and directors have fiduciary duties to our Sponsor, as well as to you. These modifications disadvantage the common unitholders because they restrict the rights and remedies that would otherwise be available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below. The following is a summary of:

• the fiduciary duties imposed on our General Partner and its directors by the Partnership Act;

• material modifications of these duties contained in our Partnership Agreement; and

• certain rights and remedies of unitholders contained in the Partnership Act.

Marshall Islands law fiduciary duty standards Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a Partnership Agreement providing otherwise, would generally require a General Partner and the directors of a Marshall Islands limited partnership to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a Partnership Agreement providing otherwise, would generally prohibit a General Partner or the directors of a Marshall Islands limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

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Partnership Agreement modified standards	Our Partnership Agreement will contain provisions that waive or consent to conduct by our General Partner and its affiliates and our directors that might otherwise raise issues as to compliance with fiduciary duties under the laws of the Marshall Islands. For example, our Partnership Agreement will provide that when our General Partner is acting in its capacity as our General Partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under the laws of the Marshall Islands. In addition, when our General Partner is acting in its individual capacity, as opposed to in its capacity as our General Partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our General Partner and its board of directors would otherwise be held. Our Partnership Agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unitholders and that are not approved by our conflicts committee of the board of directors of our General Partner must be:
	•   on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
	•   “fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).
	If the board of directors of our General Partner does not seek approval from the conflicts committee, and the board of directors of our General Partner determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors of our General Partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which the board of directors of our General Partner would otherwise be held.
	In addition to the other more specific provisions limiting the obligations of our General Partner and our directors, our Partnership Agreement further provides that our General Partner and our officers and directors, will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our General Partner or our officers or directors engaged in actual fraud or willful misconduct.

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Rights and remedies of unitholders

The provisions of the Partnership Act resemble the provisions of the limited partnership act of Delaware. For example, like Delaware, the Partnership Act favors the principles of freedom of contract and enforceability of Partnership Agreements and allows the Partnership Agreement to contain terms governing the rights of the unitholders. The rights of our unitholders, including voting and approval rights and our ability to issue additional units, are governed by the terms of our Partnership Agreement. See “The Partnership Agreement.”

As to remedies of unitholders, the Partnership Act permits a limited partner to institute legal action on behalf of the partnership to recover damages from a third party where a General Partner or a board of directors has refused to institute the action or where an effort to cause a General Partner or a board of directors to do so is not likely to succeed. These actions include actions against a General Partner for breach of its fiduciary duties or of the Partnership Agreement.

In becoming one of our limited partners, a common unitholder effectively agrees to be bound by the provisions in the Partnership Agreement, including the provisions discussed above. The failure of a limited partner or transferee to sign a Partnership Agreement does not render the Partnership Agreement unenforceable against that person.

Under the Partnership Agreement, we must indemnify our General Partner and our directors and officers to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our General Partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these person engaged in actual fraud or willful misconduct. We also must provide this indemnification for criminal proceedings when our General Partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC such indemnification is contrary to public policy and therefore unenforceable. Please read “Our Partnership Agreement—Indemnification.”

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units represent limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights and privileges available to limited partners under our Partnership Agreement. For a description of the relative rights and privileges of holders of common units and subordinated units in and to company distributions, please read this section and “How We Make Cash Distributions.” For a description of the rights and privileges of members under our Partnership Agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties

                                         will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:

• surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

• special charges for services requested by a holder of a common unit; and

• other similar fees or charges.

Unless our general partner determines otherwise in respect of some or all of any classes of our partnership interests, our partnership interests will be evidenced by book entry notation on our partnership register and not by physical certificates.

There is no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our General Partner may, at the direction of the board of directors of our General Partner, act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our Partnership Agreement, each transferee of common units will be admitted as a member with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

• represents that the transferee has the capacity, power and authority to become bound by our Partnership Agreement;

• automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our Partnership Agreement; and

• gives the consents and approvals contained in our Partnership Agreement, such as the approval of all transactions and agreements we are entering into in connection with our formation and this offering.

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We are entitled to treat the nominee holder of a common unit as the absolute owner in the event such nominee is the record holder of such common unit. In such case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing the transfer of securities. Until a common unit has been transferred on our register, we and the transfer agent are entitled to treat the record holder of the common unit as the absolute owner, except as otherwise required by law or stock exchange regulations.

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OUR PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement which we intend to enter into upon the closing of this offering. The form of our Partnership Agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our Partnership Agreement upon request at no charge.

We summarize the following provisions of our Partnership Agreement elsewhere in this prospectus:

• with regard to distributions of available cash, please read “How We Make Cash Distributions;”

• with regard to the duties of our General Partner, please read “Conflicts of Interest and Fiduciary Duties;”

• with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units;” and

• with regard to allocations of taxable income and taxable loss, please read “Material U.S. Federal Income Tax Considerations.”

Organization and Duration

Our partnership was organized on April 16, 2014 and will have a perpetual existence unless terminated pursuant to the terms of our Partnership Agreement.

Purpose

Our purpose under our Partnership Agreement is limited to any business activity that is approved by our General Partner and that lawfully may be conducted by a limited partnership organized under Republic of Marshall Islands law.

Although our General Partner has the ability to cause us and our subsidiaries to engage in activities other than the provision of offshore drilling services, it has no current plans to do so and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or our limited partners, other than the implied contractual covenant of good faith and fair dealing. Our General Partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Cash Distributions

Our Partnership Agreement will specify the manner in which we will make cash distributions to holders of our common units and other limited partner interests, including to the holders of our incentive distribution rights. For a description of these cash distribution provisions, please read “How We Make Cash Distributions.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require:

• during the subordination period, the approval of a majority of the outstanding common units, excluding those common units held by our General Partner and its affiliates, and a majority of the outstanding subordinated units, voting as separate classes; and

• after the subordination period, the approval of a majority of the outstanding common units.

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In voting their common and subordinated units, our General Partner and its affiliates will have no duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied covenant of good faith and fair dealing.

Issuance of additional units	No unitholder approval right.
Amendment of our Partnership Agreement	Certain amendments may be made by our General Partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of Our Partnership Agreement.”
Merger of our partnership or the sale of all or substantially all of our assets	Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”
Dissolution of our partnership	Unit majority. Please read “—Termination and Dissolution.”
Continuation of our business upon dissolution	Unit majority. Please read “—Termination and Dissolution.”
Withdrawal of our General Partner	Under most circumstances, the approval of unitholders holding at least a majority of the outstanding common units, excluding common units held by our General Partner and its affiliates, is required for the withdrawal of our General Partner prior to             in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”
Removal of our General Partner	Not less than             of the outstanding units, voting as a single class, including units held by our General Partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”
Transfer of the General Partner Interests	Our General Partner may transfer all, but not less than all, of its non-economic limited partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding common units, excluding common units held by our General Partner and its affiliates, is required in other circumstances for a transfer of the General Partner Unites to a third party prior to             . Please read “—Transfer of General Partner Interests.”
Transfer of incentive distribution rights	Our General Partner may transfer any or all of the incentive distribution rights without a vote of our unitholders. Please read “—Transfer of Incentive Distribution Rights.”
Reset of incentive distribution levels	No unitholder approval required.
Transfer of ownership interests in our General Partner	No unitholder approval required. Please read “—Transfer of Ownership Interests in Our General Partner.”

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Applicable Law; Forum, Venue and Jurisdiction

Our Partnership Agreement is governed by Marshall Islands law. Our Partnership Agreement requires that any claims, suits, actions or proceedings:

• arising out of or relating in any way to our Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our Partnership Agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

• brought in a derivative manner on our behalf;

• asserting a claim of breach of a duty (including a fiduciary duty) owed by any director, officer or other employee of us or our General Partner, or owed by our General Partner, to us or the limited partners;

• asserting a claim arising pursuant to any provision of the Marshall Islands Limited Partnership Act; or

• asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction, any other court located in the State of Delaware with subject matter jurisdiction), unless otherwise provided for by Marshall Islands law regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware (or such other Delaware courts) unless otherwise provided for by Marshall Islands law in connection with any such claims, suits, actions or proceedings. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents have been challenged in legal proceedings, and it is possible that, in connection with any action, a court could find the choice of forum provisions contained in our Partnership Agreement to be inapplicable or unenforceable in such action.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Marshall Islands Act and that it otherwise acts in conformity with the provisions of our Partnership Agreement, its liability under the Marshall Islands Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

• to remove or replace our General Partner;

• to approve some amendments to our Partnership Agreement; or

• to take other action under our Partnership Agreement

constituted “participation in the control” of our business for the purposes of the Marshall Islands Act, then the limited partners could be held personally liable for our obligations under the laws of the Marshall Islands, to the same extent as our General Partner. This liability would extend to persons who transact business with us who reasonably believe that the limited partner is a general partner. Neither our Partnership Agreement nor the Marshall Islands Limited Partnership Act specifically provides for legal recourse against our General Partner if a limited partner were to lose limited liability through any fault of our General Partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Marshall Islands or Delaware case law.

Under the Marshall Islands Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their limited

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partner interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Marshall Islands Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the non-recourse liability. The Marshall Islands Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Marshall Islands Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Marshall Islands Act, a substituted limited partner of a limited partnership is liable for the obligations of its assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time it became a limited partner and that could not be ascertained from our Partnership Agreement.

Maintenance of our limited liability as a limited partner or member of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which our operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners or members for the obligations of a limited partnership or limited liability company have not been clearly established in many jurisdictions. If, by virtue of our limited partner interest in our operating subsidiaries or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our General Partner, to approve some amendments to our Partnership Agreement, or to take other action under our Partnership Agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our General Partner under the circumstances. We will operate in a manner that our General Partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Partnership Interests

Our Partnership Agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our General Partner without the approval of the unitholders.

It is possible that we will fund acquisitions through borrowings and the issuance of additional common units, subordinated units or other equity securities, debt securities, or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Marshall Islands law and the provisions of our Partnership Agreement, we may also issue additional partnership interests that, as determined by our General Partner, may have special voting rights to which the common units are not entitled. In addition, our Partnership Agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.

The Partnership Agreement provides that the company will elect to be treated as a corporation for U.S. federal income tax purposes.

Amendment of Our Partnership Agreement

General

Amendments to our Partnership Agreement may be proposed only by our General Partner. However, our General Partner will have no duty or obligation to propose any amendment and may decline to do so free of any

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duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing. In order to adopt a proposed amendment, other than the amendments discussed below, our General Partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments

No amendment may be made that would:

• enlarge the obligations of any limited partner without its consent, unless such is deemed to have occurred as a result of an amendment approved by at least a majority of the type or class of limited partner interests so affected; or

• enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our General Partner or any of its affiliates without its consent, which consent may be given or withheld at its option.

The provisions of our Partnership Agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least     % of the outstanding units voting together as a single class (including units owned by our General Partner and its affiliates). Upon completion of the offering, our General Partner and its affiliates will own approximately     % of the outstanding common and subordinated units (or     % of the outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional common units from us).

No Limited Partner Approval

Our General Partner may generally make amendments to our Partnership Agreement without the approval of any limited partner to reflect:

• a change in our name, the location of our principal office, our registered agent or our registered office;

• the admission, substitution, withdrawal or removal of partners in accordance with our Partnership Agreement;

• a change that our General Partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

• a change in our fiscal year or taxable year and any other changes that our General Partner determines to be necessary or appropriate as a result of such change;

• an amendment that is necessary, in the opinion of our counsel, to prevent us or our General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the

Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, each as amended, whether or not substantially similar to plan asset regulations currently applied or proposed by the U.S. Department of Labor;

• an amendment that our General Partner determines to be necessary or appropriate for the authorization or issuance of additional partnership interests;

• any amendment expressly permitted in our Partnership Agreement to be made by our General Partner acting alone;

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• an amendment effected, necessitated or contemplated by a merger agreement or plan of conversion that has been approved under the terms of our Partnership Agreement;

• any amendment that our General Partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership joint venture, limited liability company or other entity, in connection with our conduct of activities permitted by our Partnership Agreement;

• conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

• any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our General Partner may make amendments to our Partnership Agreement without the approval of any limited partner if our General Partner determines that those amendments:

• do not adversely affect in any material respect the limited partners considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests;

• are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of Marshall Islands authority or statute;

• are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed or admitted to trading;

• are necessary or appropriate for any action taken by our General Partner relating to splits or combinations of units under the provisions of our Partnership Agreement; or

• are required to effect the intent expressed in this prospectus or the intent of the provisions of our Partnership Agreement or are otherwise contemplated by our Partnership Agreement.

Opinion of Counsel and Unitholder Approval

For amendments of the type not requiring unitholder approval, our General Partner will not be required to obtain an opinion of counsel to the effect that an amendment will not affect the limited liability of any limited partner under Delaware law. No other amendments to our Partnership Agreement will become effective without the approval of holders of at least     % of the outstanding units voting as a single class unless we first obtain such an opinion.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the type or class of partnership interests so affected. Any amendment that would reduce the percentage of units required to take any action, other than to remove our General Partner or call a meeting of unitholders, must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be reduced. Any amendment that would increase the percentage of units required to remove our General Partner must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than     % of outstanding units. Any amendment that would increase the percentage of units required to call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute at least a majority of the outstanding units.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of our partnership requires the prior consent of our General Partner. However, our General Partner will have no duty or obligation to consent to any merger, consolidation or

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conversion and may decline to do so free of any duty or obligation whatsoever to us or the limited partners, including any duty to act in the best interests of us or the limited partners, other than the implied contractual covenant of good faith and fair dealing.

In addition, our Partnership Agreement generally prohibits our General Partner without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions. Our General Partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our General Partner may also sell any or all of our assets under a foreclosure or other realization upon those encumbrances without that approval. Finally, our General Partner may consummate any merger with another limited liability entity without the prior approval of our unitholders if we are the surviving entity in the transaction, our General Partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to our Partnership Agreement requiring unitholder approval, each of our units will be an identical unit of our partnership following the transaction, and the partnership interests to be issued by us in such merger do not     % of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our Partnership Agreement are satisfied, our General Partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our General Partner has received an opinion of counsel regarding limited liability and tax matters, and our General Partner determines that the governing instruments of the new entity provide the limited partners and our General Partner with the same rights and obligations as contained in our Partnership Agreement. The unitholders are not entitled to dissenters’ rights of appraisal under our Partnership Agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until dissolved and terminated under our Partnership Agreement. We will dissolve upon:

• the withdrawal or removal of our General Partner or any other event that results in its ceasing to be our General Partner, other than by reason of a transfer of its non-economic limited partner interest in us in accordance with our Partnership Agreement or a withdrawal or removal followed by approval and admission of a successor;

• the election of our General Partner to dissolve us, if approved by the holders of units representing a unit majority;

• the entry of a decree of judicial dissolution of our partnership; or

• there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law.

Upon a dissolution under the first bullet point above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our Partnership Agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

• the action would not result in the loss of limited liability of any limited partner; and

• neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

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Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our General Partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our General Partner has agreed not to withdraw voluntarily as our General Partner prior to without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our General Partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after, our General Partner may withdraw as general partner without first obtaining approval of any unitholder by giving         days’ written notice, and that withdrawal will not constitute a violation of our Partnership Agreement. Notwithstanding the information above, our General Partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least     % of the outstanding units are held or controlled by one person and its affiliates other than our General Partner and its affiliates. In addition, our Partnership Agreement permits our General Partner to sell or otherwise transfer all of its non-economic limited partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Interests” and “—Transfer of Incentive Distribution Rights.”

Upon voluntary withdrawal of our General Partner by giving notice to the other partners, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree to continue our business by appointing a successor general partner. Please read “—Termination and Dissolution.”

Our General Partner may not be removed unless that removal is approved by the vote of the holders of not less than     % of the outstanding common and subordinated units, voting together as a single class, including units held by our General Partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our General Partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units voting as a separate class, and subordinated units, voting as a separate class. The ownership of more than     % of the outstanding units by our General Partner and its affiliates would give them the practical ability to prevent our General Partner’s removal. At the closing of this offering, our General Partner and its affiliates will own     % of the outstanding common and subordinated units (or     % of the outstanding common and subordinated units if the underwriters exercise in full their option to purchase additional common units from us).

Our Partnership Agreement also provides that if our General Partner is removed as our General Partner under circumstances where cause does not exist and units held by our General Partner and its affiliates are not voted in favor of that removal:

• the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• our General Partner will have the right to convert its non-economic limited partner interest in us and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests as of the effective date of its removal.

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In the event of removal of our General Partner under circumstances where cause exists or withdrawal of our General Partner where that withdrawal violates our Partnership Agreement, a successor general partner will have the option to purchase the non-economic limited partner interest in us and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our General Partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the non-economic limited partner interest in us of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner will become a limited partner and its non-economic limited partner interest in us and its incentive distribution rights will automatically convert into common units pursuant to a valuation of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing general partner or its affiliates for our benefit.

Transfer of the General Partner Interest

Except for transfer by our General Partner of all, but not less than all, of its non-economic limited partner interest in us to (1) an affiliate of our General Partner (other than an individual), or (2) another entity as part of the merger or consolidation of our General Partner with or into such entity or the transfer by our General Partner of all or substantially all of its assets to such entity, our General Partner may not transfer all or any part of its non-economic limited partner interest in us to another person prior to             without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our General Partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our General Partner, agree to be bound by the provisions of our Partnership Agreement, and furnish an opinion of counsel regarding limited liability and tax matters.

Our General Partner and its affiliates may at any time, transfer common units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in Our General Partner

At any time, our Sponsor and its subsidiaries may sell or transfer all or part of their membership interest in our General Partner to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

At any time, our General Partner may sell or transfer its incentive distribution rights to an affiliate or third party without the approval of our unitholders.

Change of Management Provisions

Our Partnership Agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Ocean Rig Partners GP LLC as our General Partner or otherwise change our

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management. If any person or group other than our General Partner and its affiliates acquires beneficial ownership of     % or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from our General Partner or its affiliates and any transferees of that person or group who are notified by our General Partner that they will not lose their voting rights or to any person or group who acquires the units with the prior approval of the board of directors of our General Partner.

Our Partnership Agreement also provides that if our General Partner is removed as our General Partner under circumstances where cause does not exist and units held by our General Partner and its affiliates are not voted in favor of that removal:

• the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

• any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

• our General Partner will have the right to convert its non-economic limited partner interest in us and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests as of the effective date of its removal.

Limited Call Right

If at any time our General Partner and its affiliates own more than     % of the then-issued and outstanding limited partner interests of any class, our General Partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of such class held by unaffiliated persons as of a record date to be selected by our General Partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of this purchase is the greater of:

• the highest cash price paid by either of our General Partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our General Partner first mails notice of its election to purchase those limited partner interests; and

• the current market price calculated in accordance with our Partnership Agreement as of the date three business days before the date the notice is mailed.

As a result of our General Partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have its limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of its common             units in the market. Please read “Material U.S. Federal Income Tax Considerations—U.S. Federal Income Taxation of U.S. Holders—Sale Exchange or Other Disposition of Common Units” and “Material U.S. Federal Income Tax Considerations—U.S. Federal Income Tax of Non-U.S. Holders—Disposition of Units.” At the closing of this offering, our General Partner and its affiliates will own approximately     % of our common units (or     % of our common units, if the underwriters exercise their option to purchase additional common units) and all of our subordinated units. At the end of the subordination period (which could occur as early as within the quarter ending             ), assuming no additional issuances of common units by us (other than upon the conversion of the subordinated units), our General Partner and its affiliates will own approximately     % of our outstanding common units and therefore would not be able to exercise the call right at that time.

Meetings; Voting

Except as described below regarding a person or group owning     % or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

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Our General Partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or, if authorized by our General Partner, without a meeting if consents in writing describing the action so taken are signed by holders of the number of units that would be necessary to authorize or take that action at a meeting where all limited partners were present and voted. Meetings of the unitholders may be called by our General Partner or by unitholders owning at least     % of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage. The non-economic general partner interest does not entitle our General Partner to any vote other than its rights as general partner under our Partnership Agreement, will not be entitled to vote on any action required or permitted to be taken by the unitholders and will not count toward or be considered outstanding when calculating required votes, determining the presence of a quorum, or for similar purposes.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our General Partner and its affiliates, a direct transferee of our General Partner and its affiliates or a transferee of such direct transferee who is notified by our General Partner that it will not lose its voting rights, acquires, in the aggregate, beneficial ownership of     % or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. Except as our Partnership Agreement otherwise provides, subordinated units will vote together with common units as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our Partnership Agreement will be delivered to the record holder by us or by the transfer agent or an exchange agent.

Status as Limited Partner

By transfer of common units in accordance with our Partnership Agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our register. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Ineligible Holders; Redemption

Under our Partnership Agreement, an “Eligible Holder” is a limited partner whose (a) federal income tax status is not reasonably likely to have a material adverse effect on the rates that can be charged by us on assets that are subject to regulation by FERC or an analogous regulatory body and (b) nationality, citizenship or other related status would not create a substantial risk of cancellation or forfeiture of any property in which we have an interest, in each case as determined by our General Partner with the advice of counsel.

If at any time our General Partner determines, with the advice of counsel, that one or more limited partners are not Eligible Holders (any such limited partner, an “Ineligible Holder”), then our General Partner may request any limited partner to furnish to our General Partner an executed certification or other information about its federal income tax status and/or nationality, citizenship or related status. If a limited partner fails to furnish such certification or other requested information within 30 days (or such other period as our General Partner may

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determine) after a request for such certification or other information, or our General Partner determines after receipt of the information that the limited partner is not an Eligible Holder, the limited partner may be treated as an Ineligible Holder. An Ineligible Holder does not have the right to direct the voting of its units and may not receive distributions in kind upon our liquidation.

Furthermore, we have the right to redeem all of the common and subordinated units of any holder that our General Partner concludes is an Ineligible Holder or fails to furnish the information requested by our General Partner. The redemption price in the event of such redemption for each unit held by such unitholder will be the current market price of such unit (the date of determination of which shall be the date fixed for redemption). The redemption price will be paid, as determined by our General Partner, in cash or by delivery of a promissory note. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Indemnification

Under our Partnership Agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

• our General Partner;

• any departing general partner;

• any person who is or was an affiliate of our General Partner or any departing general partner;

• any person who is or was a manager, managing member, general partner, director, officer, fiduciary or trustee of us, our subsidiaries or any entity set forth in the preceding three bullet points;

• any person who is or was serving as manager, managing member, general partner, director, officer, fiduciary or trustee of another person owing a fiduciary duty to us or any of our subsidiaries at the request of our General Partner or any departing general partner or any of their affiliates; and

• any person designated by our General Partner.

Any indemnification under these provisions will only be out of our assets. Unless it otherwise agrees, our General Partner will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We will purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against such liabilities under our Partnership Agreement.

Reimbursement of Expenses

Our Partnership Agreement requires us to reimburse our General Partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our General Partner in connection with operating our business. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our General Partner by its affiliates. Our General Partner is entitled to determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our General Partner are not subject to any caps or other limits. Please read “Certain Relationships and Related Party Transactions—Agreements Governing the Transactions—Omnibus Agreement” for a discussion of our obligations to our Sponsor for services provided by our Sponsor.

Books and Reports

Our General Partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

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We will mail or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also mail or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 120 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining its federal and state tax liability and filing its federal and state income tax returns, regardless of whether it supplies us with information.

Right to Inspect Our Books and Records

Our Partnership Agreement provides that a limited partner can, for a purpose reasonably related to its interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at its own expense, have furnished to him:

• a current list of the name and last known address of each record holder;

• copies of our Partnership Agreement and our certificate of limited partnership and all amendments thereto; and

• certain information regarding the status of our business and financial condition.

Our General Partner may, and intends to, keep confidential from the limited partners, trade secrets or other information the disclosure of which our General Partner determines is not in our best interests or that we are required by law or by agreements with third parties to keep confidential. Our Partnership Agreement limits the right to information that a limited partner would otherwise have under Delaware law.

Registration Rights

Under our Partnership Agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership interests proposed to be sold by our General Partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights will continue for two years following any withdrawal or removal of our General Partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units Eligible for Future Sale.”

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered by this prospectus, assuming the underwriters do not exercise their option to purchase additional common units, our General Partner and its affiliates will hold an aggregate of             common units and subordinated units. All of the subordinated units will convert into common units at the end of the subordination period. The sale of these common and subordinated units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act. However, any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption from the registration requirements of the Securities Act pursuant to Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of ours to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

• 1% of the total number of the class of securities outstanding; or

• the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell those common units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions, and notice requirements of Rule 144.

Our partnership agreement will provide that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or other limited partner interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. Please read “Our Partnership Agreement—Issuance of Additional Partnership Interests.”

Under our partnership agreement, our general partner and its affiliates, other than individuals, will have the right to cause us to register under the Securities Act and applicable state securities laws the offer and sale of any common units or other limited partner interests that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any common units or other limited partner interests to require registration of any of these common units or other limited partner interests and to include any of these common units or other limited partner interests in a registration statement by us of other partnership interests, including common units offered by us or by any unitholder. Our general partner and its affiliates will continue to have these registration rights for two years after it ceases to be our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any applicable state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts. Our general partner and its affiliates also may sell their common units or other limited partner interests in private transactions at any time, subject to compliance with applicable laws.

Our general partner’s executive officers and directors, our General Partner, our Sponsor and certain other affiliates of our Sponsor’s have agreed that for a period of         days from the date of this prospectus they will not, without the prior written consent of             , dispose of any common units or any securities convertible into or exchangeable for our common units. Please read “Underwriting” for a description of these lock-up provisions.

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a discussion of the material U.S. federal income tax considerations that may be relevant to prospective unitholders and, unless otherwise noted in the following discussion, is the opinion of Seward & Kissel L.L.P., our U.S. counsel, insofar as it contains legal conclusions with respect to matters of U.S. federal income tax law. The opinion of our counsel is dependent on the accuracy of factual representations made by us to them, including descriptions of our operations contained herein.

This discussion is based upon provisions of the Code, Treasury Regulations, and current administrative rulings and court decisions, all as in effect or existence on the date of this prospectus and all of which are subject to change, possibly with retroactive effect. Changes in these authorities may cause the tax consequences of unit ownership to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “we,” “our” or “us” are references to Ocean Rig Partners LP.

The following discussion applies only to beneficial owners of common units that own the common units as “capital assets” within the meaning of Section 1221 of the Code (i.e., generally, for investment purposes) and is not intended to be applicable to all categories of investors, such as unitholders subject to special tax rules (e.g. financial institutions, insurance companies, broker-dealers, tax-exempt organizations, retirement plans or individual retirement accounts or former citizens or long-term residents of the United States), persons who will hold the units as part of a straddle, hedge, conversion, constructive sale or other integrated transaction for U.S. federal income tax purposes, or persons that have a functional currency other than the U.S. dollar, each of whom may be subject to tax rules that differ significantly from those summarized below. If a partnership or other entity classified as a partnership for U.S. federal income tax purposes holds our common units, the tax treatment of its partners generally will depend upon the status of the partner and the activities of the partnership. If you are a partner in a partnership holding our common units, you are encouraged to consult your own tax advisor regarding the tax consequences to you of the partnership’s ownership of our common units.

No ruling has been or will be requested from the IRS regarding any matter affecting us or our prospective unitholders. The opinions and statements made herein may be challenged by the IRS and, if so challenged, may not be sustained upon review in a court.

This discussion does not contain information regarding any U.S. state or local, estate, gift or alternative minimum tax considerations concerning the ownership or disposition of common units. This discussion does not comment on all aspects of U.S. federal income taxation that may be important to particular unitholders in light of their individual circumstances, and each prospective unitholder is urged to consult its own tax advisor regarding the U.S. federal, state, local and other tax consequences of the ownership or disposition of common units.

Election to be Treated as a Corporation

We have elected to be treated as a corporation for U.S. federal income tax purposes. Consequently, among other things, U.S. Holders (as defined below) will not be directly subject to U.S. federal income tax on our income, but rather will be subject to U.S. federal income tax on distributions received from us and dispositions of units as described below.

U.S. Federal Income Taxation of U.S. Holders

As used herein, the term “U.S. Holder” means a beneficial owner of our common units that owns (actually or constructively) less than 10% of our equity and that is:

• an individual U.S. citizen or resident (as determined for U.S. federal income tax purposes),

• a corporation (or other entity that is classified as a corporation for U.S. federal income tax purposes) organized under the laws of the United States or any of its political subdivisions,

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• an estate the income of which is subject to U.S. federal income taxation regardless of its source, or

• a trust if (i) a court within the United States is able to exercise primary supervision over the administration of the trust and one or more U.S. persons have the authority to control all substantial decisions of the trust or (ii) the trust has a valid election in effect to be treated as a U.S. person for U.S. federal income tax purposes.

Distributions

Subject to the discussion below of the rules applicable to PFICs, any distributions to a U.S. Holder made by us with respect to our common units generally will constitute dividends, which will be taxable as “qualified dividend income” or ordinary income as described in more detail below to the extent of our current and accumulated earnings and profits, as determined under U.S. federal income tax principles. Distributions in excess of our earnings and profits will be treated first as a nontaxable return of capital to the extent of the U.S. Holder’s tax basis in its common units and, thereafter, as capital gain. U.S. Holders that are corporations generally will not be entitled to claim a dividends received deduction with respect to distributions they receive from us because we are not a U.S. corporation. Dividends received with respect to our common units generally will be treated as “passive category income” for purposes of computing allowable foreign tax credits for U.S. federal income tax purposes.

Under current law, dividends received from an entity treated as a corporation for U.S. federal income tax purposes, such as us, by a U.S. Holder that is an individual, trust or estate (a “U.S. Individual Holder”) generally will be treated as “qualified dividend income,” which is currently taxable to such U.S. Individual Holder at preferential capital gain tax rates provided that: (i) the stock or other equity on which such dividends are paid is readily tradable on an established securities market in the United States (such as The New York Stock Exchange on which we expect our common units to be traded); (ii) the dividend paying entity is not a PFIC for the taxable year during which the dividend is paid or the immediately preceding taxable year (which we do not believe we are, have been or will be, as discussed below under “—U.S. Federal Income Taxation of U.S. Holders—PFIC Status and Significant Tax Consequences”); (iii) the U.S. Individual Holder has owned the common stock or other equity interest on which such dividends are paid for more than 60 days during the 121-day period beginning 60 days before the date on which the common units become ex-dividend (and has not entered into certain risk limiting transactions with respect to such common units); and (iv) the U.S. Individual Holder is not under an obligation to make related payments with respect to positions in substantially similar or related property. There is no assurance that any dividends paid on our common units will be eligible for these preferential rates in the hands of a U.S. Individual Holder, and any dividends paid on our common units that are not eligible for these preferential rates will be taxed as ordinary income to a U.S. Individual Holder.

Special rules may apply to any amounts received in respect of our common units that are treated as qualified dividend income eligible for the preferential tax rates and as “extraordinary dividends.” In general, an extraordinary dividend is a dividend with respect to a common unit that is equal to or in excess of 10% of a unitholder’s adjusted tax basis (or fair market value upon the unitholder’s election) in such common unit. In addition, extraordinary dividends include dividends received within a one year period that, in the aggregate, equal or exceed 20% of a unitholder’s adjusted tax basis (or fair market value). If we pay an “extraordinary dividend” on our common units that is treated as “qualified dividend income,” then any loss recognized by a U.S. Individual Holder from the sale or exchange of such common units will be treated as long-term capital loss to the extent of the amount of such dividend.

Ratio of Dividend Income to Distributions

We will compute our earnings and profits for each taxable year in accordance with U.S. federal income tax principles. We estimate that approximately     % of the total cash distributions received by a purchaser of common units in this offering that holds such common units through December 31, 2016 will constitute dividend income. The remaining portion of these distributions, determined on a cumulative basis, will be treated first as a

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nontaxable return of capital to the extent of the purchaser’s tax basis in its common units and thereafter as capital gain. These estimates are based upon the assumption that we will pay the minimum quarterly distribution of $         per unit on our common units during the referenced period and on other assumptions with respect to our earnings, capital expenditures and cash flow for this period. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties that are beyond our control. Further, these estimates are based on current U.S. federal income tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of total cash distributions that will constitute dividend income could be higher or lower, and any differences could be material or could materially affect the value of the common units.

Sale, Exchange or Other Disposition of Common Units

Subject to the discussion of PFIC status below, a U.S. Holder generally will recognize capital gain or loss upon a sale, exchange or other disposition of our units in an amount equal to the difference between the amount realized by the U.S. Holder from such sale, exchange or other disposition and the U.S. Holder’s adjusted tax basis in such units. The U.S. Holder’s initial tax basis in its units generally will be the U.S. Holder’s purchase price for the units and that tax basis will be reduced (but not below zero) by the amount of any distributions on the units that are treated as non-taxable returns of capital (as discussed above under “—U.S. Federal Income Taxation of U.S. Holders—Distributions”). Such gain or loss will be treated as long-term capital gain or loss if the U.S. Holder’s holding period is greater than one year at the time of the sale, exchange or other disposition. Certain U.S. Holders (including individuals) may be eligible for preferential rates of U.S. federal income tax in respect of long-term capital gains. A U.S. Holder’s ability to deduct capital losses is subject to limitations. Such capital gain or loss generally will be treated as U.S. source income or loss, as applicable, for U.S. foreign tax credit purposes.

PFIC Status and Significant Tax Consequences

Adverse U.S. federal income tax rules apply to a U.S. Holder that owns an equity interest in a non-U.S. corporation that is classified as a PFIC for U.S. federal income tax purposes. In general, we will be treated as a PFIC with respect to a U.S. Holder if, for any taxable year in which the holder held our units, either:

• at least 75% of our gross income (including the gross income of our drillship owning subsidiaries) for such taxable year consists of passive income (e.g. dividends, interest, capital gains from the sale or exchange of investment property and rents derived other than in the active conduct of a rental business); or

• at least 50% of the average value of the assets held by us (including the assets of our drillship owning subsidiaries) during such taxable year produce, or are held for the production of, passive income.

Income earned, or deemed earned, by us in connection with the performance of services would not constitute passive income. By contrast, rental income generally would constitute “passive income” unless we were treated as deriving that rental income in the active conduct of a trade or business under the applicable rules.

Based on our current and projected methods of operation we do not believe that we are or will be a PFIC with respect to any taxable year. However, distinguishing between contractual arrangements treated as generating rental income, which may constitute passive income for purposes of determining our PFIC status, and those treated as generating services income involves weighing and balancing competing factual considerations, and there is no legal authority under the PFIC rules addressing our specific method of operation. Conclusions in this area therefore remain matters of interpretation. We are not seeking a ruling from the IRS on the treatment of income generated from our drilling contracts or charters. Thus, it is possible that the IRS or a court could disagree with this position. Moreover, although we intend to conduct our affairs in a manner to avoid being classified as a PFIC with respect to any taxable year, we cannot assure you that the nature of our operations will not change in the future and that we will not become a PFIC in any future year.

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As discussed more fully below, if we were to be treated as a PFIC for any taxable year, a U.S. Holder would be subject to different taxation rules depending on whether the U.S. Holder makes an election to treat us as a “Qualified Electing Fund,” which we refer to as a “QEF election.” As an alternative to making a QEF election, a U.S. Holder should be able to make a “mark-to-market” election with respect to our common units, as discussed below. If we are a PFIC, a U.S. Holder will be subject to the PFIC rules described herein with respect to any of our subsidiaries that are PFICs. However, the mark-to-market election discussed below will likely not be available with respect to shares of such PFIC subsidiaries. In addition, if a U.S. Holder owns our common units during any taxable year that we are a PFIC, such holder must file an annual report with the IRS.

Taxation of U.S. Holders Making a Timely QEF Election

If a U.S. Holder makes a timely QEF election (an “Electing Holder”), then, for U.S. federal income tax purposes, that holder must report as income for its taxable year its pro rata share of our ordinary earnings and net capital gain, if any, for our taxable years that end with or within the taxable year for which that holder is reporting, regardless of whether or not the Electing Holder received distributions from us in that year. The Electing Holder’s adjusted tax basis in the common units will be increased to reflect taxed but undistributed earnings and profits. Distributions of earnings and profits that were previously taxed will result in a corresponding reduction in the Electing Holder’s adjusted tax basis in common units and will not be taxed again once distributed. An Electing Holder generally will recognize capital gain or loss on the sale, exchange or other disposition of our common units. A U.S. Holder makes a QEF election with respect to any year that we are a PFIC by filing IRS Form 8621 with its U.S. federal income tax return. If contrary to our expectations, we determine that we are treated as a PFIC for any taxable year, we will provide each U.S. Holder with the information necessary to make the QEF election described above.

Taxation of U.S. Holders Making a “Mark-to-Market” Election

If we were to be treated as a PFIC for any taxable year and, as we anticipate, our units were treated as “marketable stock,” then, as an alternative to making a QEF election, a U.S. Holder would be allowed to make a “mark-to-market” election with respect to our common units, provided the U.S. Holder completes and files IRS Form 8621 in accordance with the relevant instructions and related Treasury Regulations. If that election is made, the U.S. Holder generally would include as ordinary income in each taxable year the excess, if any, of the fair market value of the U.S. Holder’s common units at the end of the taxable year over the holder’s adjusted tax basis in the common units. The U.S. Holder also would be permitted an ordinary loss in respect of the excess, if any, of the U.S. Holder’s adjusted tax basis in the common units over the fair market value thereof at the end of the taxable year, but only to the extent of the net amount previously included in income as a result of the mark-to-market election. A U.S. Holder’s tax basis in its common units would be adjusted to reflect any such income or loss recognized. Gain recognized on the sale, exchange or other disposition of our common units would be treated as ordinary income, and any loss recognized on the sale, exchange or other disposition of the common units would be treated as ordinary loss to the extent that such loss does not exceed the net mark-to-market gains previously included in income by the U.S. Holder. Because the mark-to-market election only applies to marketable stock, however, it would not apply to a U.S. Holder’s indirect interest in any of our subsidiaries that were determined to be PFICs.

Taxation of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election

If we were to be treated as a PFIC for any taxable year, a U.S. Holder that does not make either a QEF election or a “mark-to-market” election for that year (or a Non-Electing Holder) would be subject to special rules resulting in increased tax liability with respect to (1) any excess distribution (i.e., the portion of any distributions received by the Non-Electing Holder on our common units in a taxable year in excess of 125% of the average annual distributions received by the Non-Electing Holder in the three preceding taxable years, or, if shorter, the

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Non-Electing Holder’s holding period for the common units), and (2) any gain realized on the sale, exchange or other disposition of the units. Under these special rules:

• the excess distribution or gain would be allocated ratably over the Non-Electing Holder’s aggregate holding period for the common units;

• the amount allocated to the current taxable year and any taxable year prior to the taxable year we were first treated as a PFIC with respect to the Non-Electing Holder would be taxed as ordinary income; and

• the amount allocated to each of the other taxable years would be subject to tax at the highest rate of tax in effect for the applicable class of taxpayers for that year, and an interest charge for the deemed deferral benefit would be imposed with respect to the resulting tax attributable to each such other taxable year.

These penalties would not apply to a qualified pension, profit sharing or other retirement trust or other tax-exempt organization that did not borrow money or otherwise utilize leverage in connection with its acquisition of our common units. If we were treated as a PFIC for any taxable year and a Non-Electing Holder who is an individual dies while owning our common units, such holder’s successor generally would not receive a step-up in tax basis with respect to such units.

U.S. Federal Income Taxation of Non-U.S. Holders

A beneficial owner of our common units (other than a partnership or an entity or arrangement treated as a partnership for U.S. federal income tax purposes) that is not a U.S. Holder is referred to as a “Non-U.S. Holder.” If you are a partner in a partnership (or an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holding our common units, you should consult your own tax advisor regarding the tax consequences to you of the partnership’s ownership of our common units.

Distributions

Distributions we pay to a Non-U.S. Holder will not be subject to U.S. federal income tax or withholding tax if the Non-U.S. Holder is not engaged in a U.S. trade or business. If the Non-U.S. Holder is engaged in a U.S. trade or business, our distributions will be subject to U.S. federal income tax to the extent they constitute income effectively connected with the Non-U.S. Holder’s U.S. trade or business. However, distributions paid to a Non-U.S. Holder that is engaged in a trade or business may be exempt from taxation under an income tax treaty if the income arising from the distribution is not attributable to a U.S. permanent establishment maintained by the Non-U.S. Holder.

Disposition of Units

In general, a Non-U.S. Holder is not subject to U.S. federal income tax or withholding tax on any gain resulting from the disposition of our common units provided the Non-U.S. Holder is not engaged in a U.S. trade or business. A Non-U.S. Holder that is engaged in a U.S. trade or business will be subject to U.S. federal income tax in the event the gain from the disposition of units is effectively connected with the conduct of such U.S. trade or business (provided, in the case of a Non-U.S. Holder entitled to the benefits of an income tax treaty with the United States, such gain also is attributable to a U.S. permanent establishment). However, even if not engaged in a U.S. trade or business, individual Non-U.S. Holders may be subject to tax on gain resulting from the disposition of our common units if they are present in the United States for 183 days or more during the taxable year in which those units are disposed and meet certain other requirements.

Backup Withholding and Information Reporting

In general, payments to a non-corporate U.S. Holder of distributions or the proceeds of a disposition of common units will be subject to information reporting. These payments to a non-corporate U.S. Holder also may be subject to backup withholding if the non-corporate U.S. Holder:

• fails to provide an accurate taxpayer identification number;

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• is notified by the IRS that it has failed to report all interest or corporate distributions required to be reported on its U.S. federal income tax returns; or

• in certain circumstances, fails to comply with applicable certification requirements.

Non-U.S. Holders may be required to establish their exemption from information reporting and backup withholding by certifying their status on IRS Form W-8BEN, W-8ECI or W-8IMY, as applicable.

Backup withholding is not an additional tax. Rather, a unitholder generally may obtain a credit for any amount withheld against its liability for U.S. federal income tax (and obtain a refund of any amounts withheld in excess of such liability) by timely filing a U.S. federal income tax return with the IRS.

U.S. Holders purchasing more than $100,000 of our common units in this offering generally will be required to file IRS Form 926 reporting that payment to us. For purposes of determining the total dollar value of common units purchased by a U.S. Holder in this offering, units purchased by certain related parties (including family members) are included. Substantial penalties may be imposed upon a U.S. Holder that fails to comply with this reporting obligation. Each U.S. Holder should consult its own tax advisor as to the possible obligation to file IRS Form 926.

Individuals who are U.S. Holders (and to the extent specified in applicable Treasury regulations, Non-U.S. Holders and certain U.S. entities) who hold “specified foreign financial assets” (as defined in Section 6038D of the Code) are required to file IRS Form 8938 with information relating to the asset for each taxable year in which the aggregate value of all such assets exceeds $75,000 at any time during the taxable year or $50,000 on the last day of the taxable year (or such higher dollar amount as prescribed by applicable Treasury Regulations). Specified foreign financial assets would include, among other assets, our common units, unless the common units are held in an account maintained with a U.S. financial institution. Substantial penalties apply to any failure to timely file IRS Form 8938, unless the failure is shown to be due to reasonable cause and not due to willful neglect. Additionally, in the event an individual U.S. Holder (and to the extent specified in applicable Treasury Regulations, a Non-U.S. Holder or a U.S. entity) that is required to file IRS Form 8938 does not file such form, the statute of limitations on the assessment and collection of U.S. federal income taxes of such holder for the related tax year may not close until three years after the date that the required information is filed. U.S. Holders (including U.S. entities) and Non-U.S. Holders are encouraged consult their own tax advisors regarding their reporting obligations in respect of our common units.

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NON-UNITED STATES TAX CONSIDERATIONS

Unless the context otherwise requires, references in this section to “we,” “our” or “us” are references to Ocean Rig Partners LP.

Marshall Islands Tax Consequences

The following discussion is based upon the opinion of Seward & Kissel LLP, our counsel as to matters of the laws of the Republic of the Marshall Islands, and the current laws of the Republic of the Marshall Islands applicable to persons who do not reside in, maintain offices in or engage in business in the Republic of the Marshall Islands.

Because we and our subsidiaries do not and do not expect to conduct business or operations in the Republic of the Marshall Islands, and because all documentation related to this offering will be executed outside of the Republic of the Marshall Islands, under current Marshall Islands law you will not be subject to Marshall Islands taxation or withholding on distributions, including upon distribution treated as a return of capital, we make to you as a unitholder. In addition, you will not be subject to Marshall Islands stamp, capital gains or other taxes on the purchase, ownership or disposition of common units, and you will not be required by the Republic of the Marshall Islands to file a tax return relating to your ownership of common units.

EACH PROSPECTIVE UNITHOLDER IS URGED TO CONSULT HIS OWN TAX COUNSEL OR OTHER ADVISOR WITH REGARD TO THE LEGAL AND TAX CONSEQUENCES OF UNIT OWNERSHIP UNDER THEIR PARTICULAR CIRCUMSTANCES.

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UNDERWRITING

Barclays Capital Inc., Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc. are acting as the representatives of the underwriters and the sole book-running managers of this offering. Under the terms of an underwriting agreement, which will be filed as an exhibit to the registration statement, each of the underwriters named below has severally agreed to purchase from us the respective number of common units shown opposite its name below:

Underwriters	Number of Units
Barclays Capital Inc.
Credit Suisse Securities (USA) LLC
Deutsche Bank Securities Inc.
Total

The underwriting agreement provides that the underwriters’ obligation to purchase common units depends on the satisfaction of the conditions contained in the underwriting agreement including:

• the obligation to purchase all of the common units offered hereby (other than those common units covered by their option to purchase additional units as described below), if any of the units are purchased;

• the representations and warranties made by us and Ocean Rig to the underwriters are true;

• there is no material change in our business or the financial markets; and

• we deliver customary closing documents to the underwriters.

Commissions and Expenses

The following table summarizes the underwriting discounts and commissions we will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us for the common units.

	No Exercise	Full Exercise
Per Common Unit	$	$
Total	$	$

The representatives have advised us that the underwriters propose to offer the common units directly to the public at the public offering price on the cover of this prospectus and to selected dealers, which may include the underwriters, at such offering price less a selling concession not in excess of $             per common unit. After the offering, the representatives may change the offering price and other selling terms.

The expenses of the offering that are payable by us are estimated to be approximately $             (excluding underwriting discounts and commissions).

Option to Purchase Additional Units

We have granted the underwriters an option exercisable for 30 days after the date of this prospectus to purchase, from time to time, in whole or in part, up to an aggregate of              common units from us at the public offering price less underwriting discounts and commissions. This option may be exercised to the extent the underwriters sell more than              common units in connection with this offering. To the extent that this option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional common units based on the underwriter’s percentage underwriting commitment in the offering as indicated in the table at the beginning of this Underwriting section.

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Lock-Up Agreements

We, our general partner, Ocean Rig and the directors and executive officers of our general partner, have agreed that, for a period of              days after the date of this prospectus, we and they will not directly or indirectly, without the prior written consent of                                                                               (1) offer for sale, sell, pledge, or otherwise dispose of (or enter into any transaction or device that is designed to, or could be expected to, result in the disposition by any person at any time in the future of) any common units (including, without limitation, common units that may be deemed to be beneficially owned by us or them in accordance with the rules and regulations of the SEC and common units that may be issued upon exercise of any options or warrants) or securities convertible into or exercisable or exchangeable for common units, or sell or grant options, rights or warrants with respect to any common units or securities convertible into or exchangeable for common units, (2) enter into any swap or other derivatives transaction that transfers to another, in whole or in part, any of the economic benefits or risks of ownership of common units, whether any such transaction described in clause (1) or (2) above is to be settled by delivery of common units or other securities, in cash or otherwise, (3) make any demand for or exercise any right or file or cause to be filed a registration statement, including any amendments thereto, with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities, or (4) publicly disclose the intention to do any of the foregoing.

                                                                               in their sole discretion, may release the common units and other securities subject to the lock-up agreements described above in whole or in part at any time. When determining whether or not to release common units and other securities from lock-up agreements,                                                                               will consider, among other factors, the holder’s reasons for requesting the release, the number of common units and other securities for which the release is being requested and market conditions at the time.

Offering Price Determination

Prior to this offering, there has been no public market for our common units. The initial public offering price was negotiated between the representatives and us. In determining the initial public offering price of our common units, the representatives considered:

• the history and prospects for the industry in which we compete;

• our financial information;

• the ability of our management and our business potential and earning prospects;

• the prevailing securities markets at the time of this offering; and

• the recent market prices of, and the demand for, publicly traded shares of generally comparable companies.

Indemnification

We and certain of our affiliates have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, and to contribute to payments that the underwriters may be required to make for these liabilities.

Stabilization, Short Positions and Penalty Bids

The representatives may engage in stabilizing transactions, short sales and purchases to cover positions created by short sales, and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common units, in accordance with Regulation M under the Exchange Act:

• Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

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• A short position involves a sale by the underwriters of units in excess of the number of units the underwriters are obligated to purchase in the offering, which creates the syndicate short position. This short position may be either a covered short position or a naked short position. In a covered short position, the number of units involved in the sales made by the underwriters in excess of the number of units they are obligated to purchase is not greater than the number of units that they may purchase by exercising their option to purchase additional units. In a naked short position, the number of units involved is greater than the number of units in their option to purchase additional units. The underwriters may close out any short position by either exercising their option to purchase additional units and/or purchasing units in the open market. In determining the source of units to close out the short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase units through their option to purchase additional units. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the units in the open market after pricing that could adversely affect investors who purchase in the offering.

• Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions.

• Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the NASDAQ Global Select Market or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the representatives will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of common units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriters or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

Listing on the NASDAQ Global Select Market

We have applied to list our common units on the NASDAQ Global Select Market under the symbol “ORLP.”

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Discretionary Sales

The underwriters have informed us that they do not expect to sell more than 5% of the common units to accounts over which they exercise discretionary authority.

Stamp Taxes

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

Other Relationships

The underwriters and certain of their affiliates are full service financial institutions engaged in various activities, which may include securities trading, commercial and investment banking, financial advisory, investment management, investment research, principal investment, hedging, financing and brokerage activities. The underwriters and certain of their affiliates have, from time to time, performed, and may in the future perform, various commercial and investment banking and financial advisory services for us and our affiliates, for which they received or may in the future receive customary fees and expenses. Affiliates of certain of the underwriters acted as bookrunners and arrangers under the New Senior Secured Term Loan Facility and have served as initial purchasers, arrangers and bookrunners under certain other indebtedness of Ocean Rig and its affiliates.

In the ordinary course of their various business activities, the underwriters and certain of their affiliates may make or hold a broad array of investments and actively trade debt and equity securities (or related derivative securities) and financial instruments (including bank loans) for their own account and for the accounts of their customers, and such investment and securities activities may involve securities and/or instruments of the issuer or its affiliates. If the underwriters or their affiliates have a lending relationship with us, the underwriters or their affiliates may hedge their credit exposure to us consistent with their customary risk management policies. Typically, the underwriters and their affiliates would hedge such exposure by entering into transactions which consist of either the purchase of credit default swaps or the creation of short positions in our securities or the securities of our affiliates, including potentially the common units offered hereby. Any such credit default swaps or short positions could adversely affect future trading prices of common units offered hereby. The underwriters and certain of their affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such securities or instruments and may at any time hold, or recommend to clients that they acquire, long and/or short positions in such securities and instruments.

Direct Participation Program Requirements

Because FINRA views the common units offered hereby as interests in a direct participation program, the offering is being made in compliance with FINRA Rule 2310. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Selling Restrictions

This prospectus does not constitute an offer to sell to, or a solicitation of an offer to buy from, anyone in any country or jurisdiction (i) in which such an offer or solicitation is not authorized, (ii) in which any person making such offer or solicitation is not qualified to do so or (iii) in which any such offer or solicitation would otherwise be unlawful. No action has been taken that would, or is intended to, permit a public offer of the common units or possession or distribution of this prospectus or any other offering or publicity material relating to the common units in any country or jurisdiction (other than the United States) where any such action for that purpose is

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required. Accordingly, each underwriter has undertaken that it will not, directly or indirectly, offer or sell any common units or have in its possession, distribute or publish any prospectus, form of application, advertisement or other document or information in any country or jurisdiction except under circumstances that will, to the best of its knowledge and belief, result in compliance with any applicable laws and regulations and all offers and sales of common units by it will be made on the same terms.

European Economic Area

This prospectus has been prepared on the basis that the transactions contemplated by this prospectus in any Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”) (other than Germany) will be made pursuant to an exemption under the Prospectus Directive from the requirement to publish a prospectus for offers of securities. Accordingly, any person making or intending to make any offer in that Relevant Member State of the securities which are the subject of the transactions contemplated by this prospectus, may only do so in circumstances in which no obligation arises for us or any of the underwriters to publish a prospectus pursuant to Article 3 of the Prospectus Directive in relation to such offer. Neither we nor any of the underwriters have authorized, nor do they authorize, the making of any offer of securities or any invitation relating thereto in circumstances in which an obligation arises for us or any of the underwriters to publish a prospectus for such offer or invitation.

In relation to each Relevant Member State, other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”), no offer to the public of the securities subject to this supplement has been or will be made in that Relevant Member State other than:

(a) to any legal entity which is a qualified investor as defined in the Prospectus Directive (“Qualified Investors”);

(b) to fewer than 100 or, if the Relevant Member State has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than Qualified Investors), as permitted under the Prospectus Directive subject to obtaining our prior consent for any such offer; or

(c) in any other circumstances falling within Article 3(2) of the Prospectus Directive,

provided that no such offer or invitation shall require us or any of the underwriters to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer to the public” means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase the securities, as the same may be further defined in that Relevant Member State by any measure implementing the Prospectus Directive in that Member State. The expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the Relevant Member State), and includes any relevant implementing measure in each Relevant Member State, and the expression “2010 Amending Directive” means Directive 2010/73/EU.

We have not authorized and do not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of us or the underwriters.

United Kingdom

We may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (“FSMA”) that is not a “recognised collective investment scheme” for the purposes of FSMA

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(“CIS”) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and are only directed at (i) investment professionals falling within the description of persons in Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the “CIS Promotion Order”) or Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Financial Promotion Order”) or (ii) high net worth companies and other persons falling with Article 22(2)(a) to (d) of the CIS Promotion Order or Article 49(2)(a) to (d) of the Financial Promotion Order, or (iii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”). Our common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this prospectus or any of its contents.

Switzerland

The distribution of our common units in Switzerland will be exclusively made to, and directed at, regulated qualified investors (“Regulated Qualified Investors”), as defined in Article 10(3)(a) and (b) of the Swiss Collective Investment Schemes Act of 23 June 2006, as amended (“CISA”). Accordingly, we have not, and will not be, registered with the Swiss Financial Market Supervisory Authority (“FINMA”) and no Swiss representative or paying agent has been or will be appointed for us in Switzerland. This prospectus and/or any other offering materials relating to our common units may be made available in Switzerland solely to Regulated Qualified Investors.

Germany

This prospectus has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Asset Investment Act (Vermôgensanlagengesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht—BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this prospectus and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1 in connection with Section 2 no. 6 of the German Securities Prospectus Act, Section 2 no. 4 of the German Asset Investment Act, and in Section 2 paragraph 11 sentence 2 no.1 of the German Investment Act. This prospectus is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation or an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

Hong Kong

Our common units may not be offered or sold in Hong Kong by means of this prospectus or any other document other than to (a) professional investors as defined in the Securities and Futures Ordinance of Hong

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Kong (Cap. 571, Laws of Hong Kong) (“SFO”) and any rules made under the SFO or (b) in other circumstances which do not result in this prospectus being deemed to be a “prospectus,” as defined in the Companies Ordinance of Hong Kong (Cap. 32, Laws of Hong Kong) (“CO”), or which do not constitute an offer to the public within the meaning of the CO or the SFO; and no person has issued or had in possession for the purposes of issue, or will issue or has in possession for the purposes of issue, whether in Hong Kong or elsewhere, any advertisement, invitation or document relating to our common units which is directed at, or the contents of which are likely to be accessed or read by, the public of Hong Kong (except if permitted to do so under the securities laws of Hong Kong) other than with respect to our common units which are or are intended to be disposed of only to persons outside Hong Kong or only to professional investors as defined in the SFO.

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SERVICE OF PROCESS AND ENFORCEMENT OF CIVIL LIABILITIES

We are organized under the laws of the Marshall Islands as a limited partnership. The Marshall Islands has a less developed body of securities laws as compared to the United States and provides protections for investors to a significantly lesser extent.

Most of our directors and officers and those of our subsidiaries are residents of countries other than the United States. Substantially all of our and our subsidiaries’ assets and a substantial portion of the assets of our directors and officers are located outside the United States. As a result, it may be difficult or impossible for United States investors to effect service of process within the United States upon us, our directors or officers, our subsidiaries or to realize against us or them judgments obtained in United States courts, including judgments predicated upon the civil liability provisions of the securities laws of the United States or any state in the United States. However, we have expressly submitted to the jurisdiction of the U.S. federal and New York state courts sitting in the City of New York for the purpose of any suit, action or proceeding arising under the securities laws of the United States or any state in the United States. The Trust Company of the Marshall Islands, Inc., Trust Company Complex, Ajeltake Island, Ajeltake Road, Majuro, Marshall Islands MH96960, as our registered agent, can accept service of process on our behalf in any such action.

In addition, there is uncertainty as to whether the courts of the Marshall Islands would (1) recognize or enforce against us, or our directors or officers judgments of courts of the United States based on civil liability provisions of applicable U.S. federal and state securities laws; or (2) impose liabilities against us or our directors and officers in original actions brought in the Marshall Islands, based on these laws.

LEGAL MATTERS

Certain legal matters with respect to United States Federal and New York law and Marshall Islands law in connection with this offering will be passed upon for us by Seward & Kissel LLP, One Battery Park Plaza, New York, New York 10004. Certain legal matters with respect to this offering will be passed upon for the underwriters by Latham & Watkins LLP, Houston, Texas.

EXPERTS

The combined carve-out financial statements of Ocean Rig Partners LP Predecessor at December 31, 2012 and 2013, and for each of the two years in the period ended December 31, 2013, appearing in this prospectus and registration statement have been audited by Ernst & Young (Hellas) Certified Auditors Accountants S.A., independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein and are included in reliance upon such report given on the authority of such firms as experts in auditing and accounting. Ernst & Young (Hellas) Certified Auditors Accountants S.A. is located at 11th km National Road Athens—Lamia, Athens, Greece and is registered as a corporate body with the public register for company auditors-accountants kept with the Body of Certified-Auditors-Accountants (“SOEL”), Greece with registration number 107,257.

This prospectus has been reviewed by Drewry Shipping Consultants Ltd., (“Drewry”), 15-17 Christopher Street, London, EC2A 2BS, UK and the section in this prospectus entitled “Offshore Drilling Industry” has been supplied by Drewry, which has confirmed to us that this prospectus and such sections accurately describe, to the best of its knowledge, the offshore drilling industry, subject to the availability and reliability of the data supporting the statistical information presented in this prospectus.

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WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the SEC a registration statement on Form F-1 regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered in this prospectus, you may wish to review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at 100 F Street, N.E., Washington, D.C. 20549, at prescribed rates or from the Commission’s web site on the Internet at http://www.sec.gov free of charge. Please call the SEC at 1-800-SEC-0330 for further information on public reference room. Our registration statement can also be inspected and copied at the offices of Nasdaq Global Select Market, 20 Broad Street, New York, NY, 10005.

Upon completion of this offering, we will be subject to the information requirements of the Securities Exchange Act of 1934, and, in accordance therewith, we will be required to file with the Commission annual reports on Form 20-F within four months of our fiscal year-end, and provide to the Commission other material information on Form 6-K. These reports and other information may be inspected and copied at the public reference facilities maintained by the Commission or obtained from the Commission’s website as provided above. We expect to make our periodic reports and other information filed with or furnished to the Commission available, free of charge, through our website, which will be operational after this offering, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the Commission.

As a foreign private issuer, we are exempt under the Exchange Act from, among other things, certain rules prescribing the furnishing and content of proxy statements, and our executive officers, directors and principal unitholders are exempt from the reporting and short-swing profit recovery provisions contained in Section 16 of the Exchange Act. In addition, we will not be required under the Exchange Act to file periodic reports and financial statements with the SEC as frequently or as promptly as U.S. companies whose securities are registered under the Exchange Act, including the filing of quarterly reports or current reports on Form 8-K. However, we intend to furnish or make available to our unitholders annual reports containing our audited financial statements prepared in accordance with U.S. GAAP and make available to our unitholders quarterly reports containing our unaudited interim financial information for the first four fiscal quarters of each fiscal year. Our annual report will contain a detailed statement of any transactions between us and our related parties, including our Sponsor and our General Partner.

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OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

The following table sets forth the main costs and expenses, other than the underwriting discounts and commissions and the structuring fee, in connection with this offering, which we will be required to pay.

U.S. Securities and Exchange Commission registration fee	$	*
Financial Industry Regulatory Authority filing fee		*
Nasdaq Global Select Marketlisting fee		*
Legal fees and expenses		*
Accounting fees and expenses		*
Printing and engraving costs		*
Transfer agent fees and other		*
Miscellaneous		*
Total	$	*

All amounts are estimated, except the SEC registration fee, the Financial Industry Regulatory Authority filing fee and Nasdaq Global Select Market listing fee.

* To be filed by amendment.

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INDEX TO BALANCE SHEET OF OCEAN RIG PARTNERS LP

	Page
Report of Independent Registered Public Accounting Firm		F-2
Balance Sheet as of April 16, 2014 (date of inception)		F-3
Notes to the Balance Sheet		F-4

OCEAN RIG PARTNERS LP PREDECESSOR

INDEX TO COMBINED CARVE-OUT FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm		F-5
Predecessor Combined Carve-Out Balance Sheets as of December 31, 2012 and 2013		F-6
Predecessor Combined Carve-Out Statements of Operations for the years ended December 31, 2012 and 2013		F-7
Predecessor Combined Carve-Out Statements of Stockholders’ Equity for the years ended December  31, 2012 and 2013		F-8
Predecessor Combined Carve-Out Statements of Cash Flows for the years ended December 31, 2012 and 2013		F-9
Notes to Predecessor Combined Carve-Out Financial Statements		F-10

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The General Partner and Limited Partner of OCEAN RIG PARTNERS LP

We have audited the accompanying balance sheet of Ocean Rig Partners LP (the “Partnership”) as of April 16, 2014 (date of inception). This balance sheet is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this balance sheet based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Partnership’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the balance sheet referred to above present fairly, in all material respects, the financial position of Ocean Rig Partners LP at April 16, 2014, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young (Hellas) Certified Auditors Accountants S.A.

Athens, Greece

April 17, 2014

F-2

OCEAN RIG PARTNERS LP

Balance Sheet

as of April 16, 2014 (date of inception)

(Expressed in United States Dollars)

	AS OF APRIL 16, 2014
ASSETS
Total assets	$	—
LIABILITIES AND PARTNER’S EQUITY
COMMITMENTS AND CONTINGENCIES:		—
PARTNER’S EQUITY:
Ocean Rig UDW Inc’s equity	$	1,000,000
Receivable from partner		(1,000,000	)
Total partner’s equity		—
Total liabilities and partner’s equity	$	—

The accompanying notes are an integral part of this balance sheet.

F-3

OCEAN RIG PARTNERS LP

Notes to Balance Sheet

April 16, 2014 (date of inception)

(Expressed in United States Dollars)

1. Organization and Operations

Ocean Rig Partners LP (the “Partnership”) is a Marshall Islands limited partnership formed on April 16, 2014 to own, operate and acquire offshore drillships.

In the context of a proposed initial public offering the Partnership intends to acquire three drillships, theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena and interests in several wholly-owned subsidiaries of Ocean Rig UDW Inc., the Partnership’s Unitholder, that have entered into the respective revenue contracts and operate these three drillships. All these elements combined, are deemed to be a business.

Ocean Rig UDW Inc has committed to contribute $1,000,000 to the Partnership. These contributions receivable are reflected as a reduction to Partner’s equity.

2. Significant Accounting Policies

Basis of Presentation

This accompanying balance sheet has been prepared in accordance with U.S. generally accepted accounting principles (U.S. GAAP). Separate statement of income, of changes in Partners’ Equity and of cash flows have not been presented in the financial statement because there have been no activities of the Partnership.

F-4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The General Partner and Limited Partner of OCEAN RIG PARTNERS LP

We have audited the accompanying combined carve-out balance sheets of the carved-out companies listed in Note 1, the predecessor entities to Ocean Rig Partners LP (the “Ocean Rig Partners LP Predecessor”), as of December 31, 2012 and 2013, and the related combined carve-out statements of operations, stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2013. These financial statements are the responsibility of the Ocean Rig Partners LP Predecessor’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Ocean Rig Partners LP Predecessor’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Ocean Rig Partners LP Predecessor’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of the Ocean Rig Partners LP Predecessor at December 31, 2012 and 2013, and the combined results of its operations and its cash flows for each of the two years in the period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young (Hellas) Certified Auditors Accountants S.A.

Athens, Greece

April 17, 2014

F-5

OCEAN RIG PARTNERS LP PREDECESSOR

Combined Carve-Out Balance Sheets

As of December 31, 2012 and 2013

(Expressed in thousands of U.S. Dollars)

	December 31, 2012			December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,452		$	6,083
Restricted cash (Note 10)		6,000			—
Trade accounts receivable		—			93,358
Other current assets (Notes 4 and 10)		8,000			25,798
Total current assets		15,452			125,239
FIXED ASSETS, NET:
Advances for drillships under construction and related costs (Note 5)		770,858			292,692
Drillships, machinery and equipment, net (Note 6)		—			1,412,164
Total fixed assets, net		770,858			1,704,856
OTHER NON-CURRENT ASSETS:
Financial instruments (Note 10)		935			13,517
Restricted cash (Note 8)		—			50,000
Other non-current assets (Note 7)		—			41,322
Total non-current assets		935			104,839
Total assets	$	787,245		$	1,934,934
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt, net of deferred financing costs (Note 8)	$	—		$	78,552
Accounts payable and other current liabilities		3,607			31,760
Accrued liabilities		851			55,902
Deferred revenue		—			47,512
Financial instruments (Note 10)		1,503			7,788
Total current liabilities		5,961			221,514
NON-CURRENT LIABILITIES
Long term debt, net of current portion and deferred financing costs (Note 8)		—			797,114
Financial instruments (Note 10)		3,106			—
Other non-current liabilities		—			8,750
Deferred revenue		—			92,379
Total non-current liabilities		3,106			898,243
COMMITMENTS AND CONTINGENCIES(Note 14)		—			—
STOCKHOLDERS’ EQUITY:
Common stock		184			184
Additional paid-in capital (Note 9)		790,894			853,520
Accumulated deficit		(12,900	)		(38,527	)
Total stockholders’ equity		778,178			815,177
Total liabilities and stockholders’ equity	$	787,245		$	1,934,934

The accompanying notes are an integral part of these predecessor combined carve-out financial statements.

F-6

OCEAN RIG PARTNERS LP PREDECESSOR

Combined Carve-Out Statements of Operations

For the years ended December 31, 2012 and 2013

(Expressed in thousands of U.S. Dollars)

	For the year ended December 31,
	2012			2013
REVENUES:
Service revenue, net	$	—		$	37,325
Total Revenues		—			37,325
EXPENSES:
Drillships operating expenses		—			13,576
Depreciation (Note 6)		—			11,740
General and administrative expenses		6,720			25,827
Operating loss		(6,720	)		(13,818	)
OTHER INCOME / (EXPENSES):
Interest and finance cost (Note 12)		(3	)		(21,022	)
Interest income		—			90
Gain/ (loss) on interest rate swaps, net (Note 10)		(3, 674	)		8,510
Other, net		(219	)		613
Total other expenses, net		(3,896	)		(11,809	)
LOSS BEFORE INCOME TAXES		(10,616	)		(25,627	)
Income taxes (Note 11)		—			—
NET LOSS	$	(10,616	)	$	(25,627	)

The accompanying notes are an integral part of these predecessor combined carve-out financial statements.

F-7

OCEAN RIG PARTNERS LP PREDECESSOR

Combined Carve-Out Statements of Stockholders’ Equity

For the years ended December 31, 2012 and 2013

(Expressed in thousands of U.S. Dollars)

	Common stock		Additional Paid-in Capital		Accumulated deficit			Total Stockholders’ Equity
BALANCE, December 31, 2011		60	$	733,798	$	(2,284	)	$	731,574
Net loss		—		—		(10,616	)		(10,616	)
Issuance of common stock		124		—		—			124
Movement in invested equity		—		57,096		—			57,096
BALANCE, December 31, 2012		184	$	790,894	$	(12,900	)	$	778,178
Net loss		—		—		(25,627	)		(25,627	)
Movement in invested equity		—		62,626		—			62,626
BALANCE, December 31, 2013		184	$	853,520	$	(38,527	)	$	815,177

The accompanying notes are an integral part of these predecessor combined carve-out financial statements.

F-8

OCEAN RIG PARTNERS LP PREDECESSOR

Combined Carve-Out Statements of Cash Flows

For the years ended December 31, 2012 and 2013

(Expressed in thousands of U.S. Dollars)

	For the year ended December 31,
	2012			2013
Cash Flows from Operating Activities:
Net loss	$	(10,616	)	$	(25,627	)
Adjustments to reconcile net loss to net cash from operating activities:
Depreciation		—			11,740
Change in fair value of derivatives		3,674			(9,403	)
Amortization of deferred financing costs		—			714
Other non-cash items (Notes 1 and 3)		6,705			19,060
Changes in operating assets and liabilities:
Trade accounts receivable		—			(93,358	)
Other current and non-current assets		(8,000	)		(51,596	)
Accounts payable and other current and non-current liabilities		3,607			36,903
Deferred revenue		—			139,891
Accrued liabilities		851			55,051
Net Cash Provided by /(Used in) Operating Activities		(3,779	)		83,375
Cash Flows from Investing Activities:
Advances for drillships under construction and related costs		(39,284	)		(887,471	)
Drillships, machinery and equipment		—			(58,267	)
Decrease in restricted cash (Note 10)					6,000
Increase in restricted cash		(6,000	)		(50,000	)
Net Cash Used in Investing Activities		(45,284	)		(989,738	)
Cash Flows from Financing Activities:
Proceeds from long-term credit facilities, terms loans		—			900,000
Principal payments and repayments of long-term debt		—			(10,000	)
Payment of financing costs		—			(22,572	)
Movement in invested equity		50,515			43,566
Net Cash Provided by Financing Activities		50,515			910,994
Net increase in cash and cash equivalents		1,452			4,631
Cash and cash equivalents at beginning of the year		—			1,452
Cash and cash equivalents at end of the year	$	1,452		$	6,083
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the years for:
Interest, net of amounts capitalized	$	—		$	3,999

The accompanying notes are an integral part of these predecessor combined carve-out financial statements.

F-9

OCEAN RIG PARTNERS LP PREDECESSOR

Notes to Combined Carve-Out Financial Statements

For the years ended December 31, 2012 and 2013

(Expressed in thousands of United States Dollars unless otherwise stated)

1. Basis of Presentation and General Information:

On April 16, 2014, Ocean Rig UDW Inc. (and together with its subsidiaries the “Ocean Rig” or the “Sponsor”) formed Ocean Rig Partners LP (the “Partnership”) under the laws of the Republic of the Marshall Islands for the purpose of acquiring, from the Sponsor, three drillships, theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena and interests in several wholly owned subsidiaries of the Sponsor that operate these drillships. The entities that currently own and operate the three drillships are hereinafter referred to as the “Ocean Rig Partners Predecessor” or the “Company” in these predecessor combined carve-out financial statements.

Prior to the completion of the Partnership’s initial public offering (“IPO”), the Sponsor intends to contribute to Drillships Ocean Ventures Inc. II. (“DOV II”), a company to be established as a wholly owned subsidiary of Ocean Rig Operating LP (“OPCO”), a wholly owned subsidiary of the Sponsor, theOcean Rig Mylos, the Ocean Rig Skyrosand theOcean Rig Athena and the entities that operate these drillships from Drillships Ocean Ventures Inc. (“DOV I”) and DOV I’s outstanding debt under the $1.35 billion Senior Secured Facility agreement, dated February 28, 2013 (Note 8).

In connection with the Partnership’s IPO the Sponsor will contribute to the Partnership a limited partner interest in OPCO and an 100% interest in OPCO GP LLC, and will acquire an 100% interest in Company’s general partner and the incentive distribution rights together with common units and subordinated units in the Partnership.

Ocean Rig is a publicly listed Marshall Islands company, specializing in the acquisition, ownership, operation and chartering of drilling rigs, drillships and associated services. Ocean Rig was established by DryShips Inc., a publicly listed Marshall Islands company, (“DryShips”) for the purpose of being the holding company of its drilling segment.

The predecessor combined carve-out financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) on a “carve-out” basis from the accounting records of the Sponsor using the historical carrying costs of the entities that own and operate the three drillships for all years presented including allocation of expenses from the Sponsor. Management believes the allocations have been determined on a basis that is a reasonable reflection of the utilization of services provided to, or the benefit received by, the Company during the years presented. The actual basis of allocation is described below.

These predecessor combined carve-out financial statements include the assets, liabilities, revenues, expenses and cash flows directly attributable to the Company, plus the following items which have been allocated as set forth below:

• Drillship Ocean Ventures Inc (“DOV I”): DOV I is currently the owner of the entities that comprise the Ocean Rig Partners Predecessor, with its only activity being the financing of the three vessels under construction, through entering into the $1.35 billion Senior Secured Facility agreement. Accordingly, the respective facility, together with all assets, liabilities, and expenses of DOV I have been carved out to the Ocean Rig Partners Predecessor.

• General and Administrative Expenses: General and administrative expenses consisting mainly of legal fees, salaries, share based payments and professional fees were allocated to the Company based on the owning days of the owning entities. Management believes that these allocations reasonably present the financial position, results of operations and cash flows of the Company. For the years ended December 31, 2012 and 2013, total expenses allocated by the Sponsor amounted to $4,305 and $16,798, respectively.

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Amounts due to and due from the Company to Ocean Rig and other Ocean Rig entities are recognized within stockholders’ equity in the predecessor combined carve-out financial statements. As Ocean Rig uses a centralized cash management system, whereby cash generated at a subsidiary level is swept into a centralized treasury function at Ocean Rig, intercompany payables and receivables outstanding for the years presented have been deemed to have been treated as equity by the Company.

The predecessor combined carve-out balance sheets, statements of operations and cash flows may not be indicative of the results that would have been realized had the Company operated as an independent stand–alone entity for the years presented. Had the Company operated as an independent stand-alone entity, its results could have differed significantly from those presented herein.

The predecessor combined carve-out financial statements include the following entities and drillships:

Partnership name	Country of incorporation	Drillship	Statements of Operations
			December 31, 2012	December 31, 2013
Drillship Skiathos Shareholders Inc.	Marshall Islands	—	01/01-31/12	01/01-31/12
Drillship Skyros Shareholders Inc.	Marshall Islands	—	01/01-31/12	01/01-31/12
Drillship Kythnos Shareholders Inc.	Marshall Islands	—	01/01-31/12	01/01-31/12
Drillship Skiathos Owners Inc.	Marshall Islands	Ocean Rig Mylos	01/01-31/12	01/01-31/12
Drillship Skyros Owners Inc.	Marshall Islands	Ocean Rig Skyros	01/01-31/12	01/01-31/12
Drillship Kythnos Owners Inc.	Marshall Islands	Ocean Rig Athena	01/01-31/12	01/01-31/12
Drillships Ocean Ventures Operations Inc.	Marshall Islands	—	27/7-31/12	01/01-31/12
Ocean Rig Cunene Operations Inc.	Marshall Islands	—	12/9-31/12	01/01-31/12
Ocean Rig Cubango Operations Inc.	Marshall Islands	—	12/10-31/12	01/01-31/12
Ocean Rig Block 33 Brasil Coöperatief UA.	Netherlands	—	7/8-31/12	01/01-31/12
Ocean Rig Block 33 Brasil B.V.	Netherlands	—	7/8-31/12	01/01-31/12

The Partnership’s customers are oil and gas exploration and production companies, including major integrated oil companies, independent oil and gas producers and government-owned oil and gas companies. During 2013, only one drillship generated revenues, which derived from one customer.

2. Significant Accounting Policies:

a) Principles of combination:The predecessor combined carve-out financial statements, as described above are prepared in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”) and include the accounts and operating results of the above mentioned subsidiaries of Ocean Rig. All significant inter-company balances and transactions have been eliminated in the predecessor combined carve-out financial statements. The predecessor combined carve-out financial statements have been prepared on a “carve-out” basis from the accounting records of the Sponsor using historical results of operations, assets and liabilities attributable to the Company, including allocation of expenses from the Sponsor.

b) Capitalized interest: Interest expense is capitalized during the construction period of drillships based on accumulated expenditures for the applicable project at the Company’s current rate of borrowing. The amount of interest expense capitalized in an accounting period is determined by applying an interest rate (“the capitalization rate”) to the average amount of accumulated expenditures for the asset during the period. The capitalization rate used in an accounting period is based on the rates applicable to borrowings outstanding during the period. The Company does not capitalize amounts in excess of actual interest expense incurred in the period. If the Company’s financing plans associate a specific new borrowing with a qualifying asset, the Company uses the rate on that borrowing as the capitalization rate to be applied to that portion of the average accumulated expenditures for the asset that does not exceed the amount of that borrowing. If average accumulated expenditures for the asset exceed the amounts of specific new borrowings associated with the asset, the capitalization rate applied

F-11

to such excess is a weighted average of the rates applicable to other borrowings of the Company. Capitalized interest expense for the years ended December 31, 2012 and 2013, amounted to $0 and $283, respectively (Note 12).

c) Drillships, machinery and equipment, net:Drillships are stated at historical cost less accumulated depreciation. Such costs include the cost of adding or replacing parts of drillship machinery and equipment when the cost is incurred, if the recognition criteria are met. The recognition criteria require that the cost incurred extends the useful life of a drillship increases the earnings capacity or improves the efficiency or safety of the drillship. The carrying amounts of those parts that are replaced are written off and the cost of the new parts is capitalized. Depreciation is calculated on a straight-line basis over the useful life of the assets after considering the estimated residual value as follows: bare deck 30 years and other asset parts 5 to 15 years for the drillships. The residual value of the drillships is estimated at $50,000.

d) Impairment of long-lived assets:The Company reviews for impairment long-lived assets held and used whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. In this respect, the Company reviews its assets for impairment on a drillship by drillship basis. When the estimate of undiscounted cash flows, excluding interest charges, expected to be generated by the use of the asset is less than its carrying amount, the Company evaluates the asset for impairment loss. The impairment loss is determined by the difference between the carrying amount of the asset and the fair value of the asset. The Company evaluates the carrying amounts of its drillships by obtaining independent appraisals to determine if events have occurred that would require modification to their carrying values or useful lives. In evaluating useful lives and carrying values of long-lived assets, the Company reviews certain indicators of potential impairment, such as undiscounted projected operating cash flows, drillships sales and purchases, business plans and overall market conditions. In developing estimates of future undiscounted cash flows, the Company makes assumptions and estimates about the drillships future performance, with the significant assumptions being related to drilling rates, fleet utilization, operating expenses, capital expenditures, residual value and the estimated remaining useful life of each drillship. The assumptions used to develop estimates of future undiscounted cash flows are based on historical trends as well as future expectations. To the extent impairment indicators are present the Company determines undiscounted projected net operating cash flows for each drillship and compares them to the drillship’s carrying value. The projected net operating cash flows are determined by considering the drilling revenues from existing drilling contracts for the fixed days and an estimated daily rate equivalent for the unfixed days. The salvage value used in the impairment test is estimated to be $50,000 for drillships in accordance with the Company’s depreciation policy.

d) Impairment of long-lived assets—continued:If the Company’s estimate of undiscounted future cash flows for any drillship is lower than the carrying value, the carrying value is written down, by recording a charge to operations, to the drillship’s fair market value if the fair market value is lower than the drillship’s carrying value. No impairment indicators identified by the Company as at December 31, 2012 and 2013.

e) Class costs:The Company follows the direct expense method of accounting for periodic class costs incurred during special surveys of drillships, normally every five years. Class costs and other maintenance costs are expensed in the period incurred and included in “Drillships operating expenses.”

f) Advances for drillships under construction and related costs:This represents amounts expended by the Company in accordance with the terms of the construction contracts for its drillships as well as other expenses incurred directly or under a management agreement with a related party in connection with onsite supervision. The carrying value of drillships under construction represents the accumulated costs at the balance sheet date. Cost components include payments for yard installments and variation orders, commissions to related party, construction supervision, equipment, spare parts, capitalized interest (if any), costs related to first time mobilization and commissioning costs. No charge for depreciation is made until commissioning of the new building has been completed and it is ready for its intended use.

F-12

g) Use of estimates:The preparation of predecessor combined carve-out financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the predecessor combined carve-out financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

h) Cash and cash equivalents:The Company considers highly liquid investments such as time deposits and certificates of deposit with an original maturity of three months or less to be cash equivalents.

i) Restricted cash:Restricted cash may include (i) minimum liquidity collateral requirements or minimum required cash deposits, as defined in the Company’s loan agreements; (ii) amounts pledged as collateral for bank guarantees to suppliers and, (iii) amounts pledged as collateral for credit facilities and swap agreements.

j) Concentration of credit risk: Financial instruments, which potentially subject the Company to significant concentrations of credit risk, consist principally of cash and cash equivalents, trade accounts receivable and derivative contracts (interest rate swaps and foreign currency contracts). The maximum exposure to loss due to credit risk is the book value at the balance sheet date. The Company places its cash and cash equivalents, consisting mostly of bank deposits, with qualified financial institutions. The Company performs periodic evaluations of the relative credit standing of those financial institutions. The Company is exposed to credit risk in the event of non-performance by counter parties to derivative instruments; however, the Company limits its exposure by diversifying among counter parties. When considered necessary, additional arrangements are put in place to minimize credit risk, such as letters of credit or other forms of payment guarantees. The Company limits its credit risk with trade accounts receivable by performing ongoing credit evaluations of its customers’ financial condition and generally does not require collateral for its trade accounts receivable.

k) Foreign currency translation:The functional currency of the Company is the U.S. Dollar since the Company operates in the international drilling market and, therefore, primarily transacts business in U.S. Dollars. The Company’s accounting records are maintained in U.S. Dollars. Transactions involving other currencies during the year are converted into U.S. Dollars using the exchange rates in effect at the time of the transactions. At the balance sheet dates, monetary assets and liabilities, which are denominated in other currencies, are translated into U.S. Dollars at the year-end exchange rates. Resulting gains or losses are included in “Other, net” in the predecessor combined carve-out statements of operations.

l) Financial instruments:The Company designates its derivatives based upon guidance on ASC 815, “Derivatives and Hedging” which establishes accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. The guidance on accounting for certain derivative instruments and certain hedging activities requires all derivative instruments to be recorded on the balance sheet as either an asset or liability measured at its fair value, with changes in fair value recognized in earnings unless specific hedge accounting criteria are met. Changes in the fair value of derivative instruments that have not been designated as hedging instruments are reported in current period earnings.

m) Fair value measurements:The Company follows the provisions of ASC 820, “Fair Value Measurements and Disclosures” which defines and provides guidance as to the measurement of fair value. ASC 820 creates a hierarchy of measurement and indicates that, when possible, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The fair value hierarchy gives the highest priority (Level 1) to quoted prices in active markets and the lowest priority (Level 3) to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements are separately disclosed by level within the fair value hierarchy (Note 8).

F-13

n) Commitments and contingencies:Provisions are recognized when: the Company has a present legal or constructive obligation as a result of past events; it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation; and a reliable estimate of the amount of the obligation can be made. Provisions are reviewed at each balance sheet date.

o) Deferred financing costs:Deferred financing costs include fees, commissions and legal expenses associated with the Company’s long-term debt. These costs are amortized to interest and finance costs over the life of the related debt using the effective interest method. Unamortized fees relating to loans repaid or refinanced as debt extinguishments are expensed as interest and finance costs in the period the repayment or extinguishment is made. Amortization for the years ended December 31, 2012 and 2013, amounted to $0 and $714, respectively (Note 12).

p) Revenues: The Company’s services and deliverables are generally sold based upon contracts with customers that include fixed or determinable prices. The Company recognizes revenue when delivery occurs, as directed by its customer, of the asset and collectability is reasonably assured. The Company evaluates if there are multiple deliverables within its contracts and whether the agreement conveys the right to use the drillships for a stated period of time and meets the criteria for lease accounting, in addition to providing a drilling services element, which is generally compensated for by day rates. In connection with drilling contracts, the Company may also receive revenues for preparation and mobilization of equipment and personnel or for capital improvements to the drillships and day rate or fixed price mobilization and demobilization fees. Revenues are recorded net of agents’ commissions. There are two types of drilling contracts: well contracts and term contracts.

(i) Well contracts: Well contracts are contracts under which the assignment is to drill a certain number of wells. Revenue from day-rate based compensation for drilling operations is recognized in the period during which the services are rendered at the rates established in the contracts. All mobilization revenues, direct incremental expenses of mobilization and contributions from customers for capital improvements are initially deferred and recognized as revenues and expenses, as applicable, over the estimated duration of the drilling period. To the extent that expenses exceed revenue to be recognized, they are expensed as incurred. Demobilization revenues and expenses are recognized over the demobilization period. All revenues for well contracts are recognized as “Service revenues, net” in the predecessor combined carve-out statement of operations.

(ii) Term contracts: Term contracts are contracts under which the assignment is to operate the unit for a specified period of time. For these types of contracts the Company determines whether the arrangement is a multiple element arrangement containing both a lease element and drilling services element. For revenues derived from contracts that contain a lease, the lease elements are recognized as “Leasing revenues” in the statement of operations on a basis approximating straight line over the lease period. The drilling services element is recognized as “Service revenues, net” in the period in which the services are rendered at estimated fair value. Revenues related to the drilling element of mobilization and direct incremental expenses of drilling services are deferred and recognized over the estimated duration of the drilling period. To the extent that expenses exceed revenue to be recognized, they are expensed as incurred. Demobilization fees and expenses are recognized over the demobilization period. Contributions from customers for capital improvements are initially deferred and recognized as revenues over the estimated duration of the drilling contract.

q) Income taxes: Income taxes are provided for based upon the tax laws and rates in effect in the countries in which the Company’s operations are conducted and income is earned. There is no expected relationship between the provision for/or benefit from income taxes and income or loss before income taxes because the countries in which the Company operates have taxation regimes that vary not only with respect to the nominal rate, but also in terms of the availability of deductions, credits and other benefits. Variations also arise as income earned and taxed in any particular country or countries may fluctuate from year to year. Deferred tax assets and liabilities are recognized for the anticipated

F-14

future tax effects of temporary differences between the financial statement basis and the tax basis of the Company’s assets and liabilities using the applicable jurisdictional tax rates in effect at the year end. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. The Company accrues interest and penalties related to its liabilities for unrecognized tax benefits as a component of income tax expense.

r) Segment reporting:The Company has determined that it operates in one reportable segment, the offshore drilling operations.

s) Trade accounts receivable net: The amount shown as accounts receivable, trade, at each balance sheet date, includes receivables from customers, net of allowance for doubtful receivables. At each balance sheet date, all potentially uncollectible accounts are assessed individually for purposes of determining the appropriate allowance for doubtful receivables. No allowance for doubtful receivables was recorded as at December 31, 2012 and 2013.

t) Recent accounting pronouncements:There are no recent accounting pronouncements issued in 2013, whose adoption would have a material impact on the predecessor combined carve-out financial statements in the current year or are expected to have a material impact on future years.

3. Transactions with Related Parties:

Ocean Rig:The predecessor combined carve-out financial statements have been carved out of the consolidated financial statements of Ocean Rig and include the assets, liabilities, revenues, expenses and cash flows directly attributable to the asset-owning legal entities, except for the general and administrative expenses which have been allocated to the Company as discussed in Note 1.

Ocean Rig Management Inc.: Within 2013, the Sponsor’s wholly owned subsidiary, Ocean Rig Management Inc. (“Ocean Rig Management”), entered into separate management agreements with the owning entities of the drillships Ocean Rig SkyrosandOcean Rig Athena. Under the terms of these management agreements, Ocean Rig Management, through its affiliates in Stavanger, Norway, Aberdeen, United Kingdom and Houston, Texas, is responsible for, among other things, (i) assisting in construction contract technical negotiations, (ii) securing contracts for the future employment of the drilling units, and (iii) providing commercial, technical and operational management for the drillships. For the year ended December 31, 2013, there were no charges from Ocean Rig Management under these agreements. Balance due to Ocean Rig Management Inc. at December 31, 2013 was nil.

Ocean Rig AS: Within 2013, the Sponsor’s wholly owned subsidiary, Ocean Rig AS, entered into a management agreement with the owning entity of the drillship Ocean Rig Mylos. Under the terms of this management agreement, Ocean Rig AS, through its affiliates in Stavanger, Norway, Aberdeen, United Kingdom and Houston, Texas, is responsible for, among other things, (i) assisting in construction contract technical negotiations, (ii) securing contracts for the future employment of the drilling units, and (iii) providing commercial, technical and operational management for the drillships. For the year ended December 31, 2013, the Company incurred management fees of $88 under these agreements, which are included in “General and administrative expenses” in the predecessor combined carve-out statement of operations. Balance due to Ocean Rig Management Inc. at December 31, 2013 was nil.

Global Services Agreement: On December 1, 2010, DryShips entered into a Global Services Agreement with Cardiff Marine Inc. (“Cardiff”), a company controlled by the Chairman, President and Chief Executive Officer of Ocean Rig and DryShips, Mr. George Economou, effective December 21, 2010, pursuant to which DryShips engaged Cardiff to act as consultant on matters of chartering and sale and purchase transactions for the offshore drilling units operated by Ocean Rig. Under the Global Services Agreement, Cardiff, or its subcontractor, (i) provided consulting services related to the identification, sourcing, negotiation and arrangement of new employment for offshore assets of Ocean Rig and its subsidiaries; and (ii) identified, sourced, negotiated and arranged the sale or purchase of the offshore assets of Ocean Rig and its subsidiaries. In consideration of such services, Cardiff charged a fee of 1.0% in connection with employment arrangements and 0.75% in connection with sale and purchase activities.

F-15

For the year ended December 31, 2012, the Company incurred no costs related to the Global Services Agreement, as no relevant transactions incurred during the year. Balance due to Cardiff, under Global Services Agreement, at December 31, 2012 was nil.

Effective January 1, 2013, DryShips terminated the Global Services Agreement with Cardiff. The Global Services Agreement has been replaced by the New Global Services Agreement, effective as of January 1, 2013, between Ocean Rig Management, a wholly-owned subsidiary of Ocean Rig, and Cardiff Drilling Inc. (formerly known as Cardiff Oil & Gas Management), a company controlled by Ocean Rig’s Chairman, President and Chief Executive Officer, Mr. George Economou, with the same terms and conditions as in the previous Global Services Agreement between DryShips and Cardiff. For the year ended December 31, 2013, the Company incurred costs of $5,692, related to sale and purchase activities, which are capitalized as a component of “Drillship, machinery and equipment, net,” in the predecessor combined carve-out balance sheets and $745, related to employment arrangements, which are included in “Service Revenue, net” in the predecessor combined carve-out statements of operations. Balance due to Cardiff Drilling Inc., under New Global Services Agreement, at December 31, 2013 was nil.

Vivid Finance Limited:Under the consultancy agreement effective from September 1, 2010, between DryShips and Vivid Finance Limited (“Vivid”), a company controlled by the Chairman, President and Chief Executive Officer of Ocean Rig and DryShips, Mr. George Economou, pursuant to which Vivid acts as a consultant on financing matters for DryShips and its affiliates, Vivid provided Ocean Rig with financing-related services such as (i) negotiating and arranging new loan and credit facilities, interest rate swap agreements, foreign currency contracts and forward exchange contracts, (ii) renegotiating existing loan facilities and other debt instruments and (iii) the raising of equity or debt in the capital markets. In exchange for its services, Vivid was entitled to a fee equal to 0.20% on the total transaction amount. For the year ended December 31, 2012, the Company incurred costs of $2.4 million related to this agreement, which are included in “General and administrative expenses” in the predecessor combined carve-out statement of operations. Balance due to Vivid, under the consultancy agreement, at December 31, 2012 was nil.

Effective January 1, 2013, Ocean Rig Management entered into a new consultancy agreement with Vivid, on the same terms and conditions as the consultancy agreement, dated as of September 1, 2010, between DryShips and Vivid. For the year ended December 31, 2013, total charges from Vivid under this agreement amounted to $8.1 million, which are included in “General and administrative expenses” in the predecessor combined carve-out statement of operations. Balance due to Vivid, under the new consultancy agreement, at December 31, 2013 was nil.

Ocean Rig Angola LDA:During 2012 the Company, through Ocean Rig Cunene Operations Inc. jointly with Ocean Rig Angola LDA, a related party company, owned and controlled by the Sponsor, entered into a contract with an oil company, for the commencement of drilling operations of theOcean Rig Athenawithin 2014. During 2013 the Company, through Ocean Rig Cubango Operations Inc. jointly with Ocean Rig Angola LDA entered into a contract with an oil company, for the commencement of drilling operations of theOcean Rig Skyroswithin 2014. Both contracts determine the services to be performed by Ocean Rig Cunene Operations Inc. or Ocean Rig Cubango Operations Inc. and Ocean Rig Angola LDA and the service fees that each party is entitled. Ocean Rig Angola LDA’s services under the aforementioned agreements include procurement of equipment, maintenance of drillships and administrative services incurred in Angola.

Ocean Rig Do Brasil Servicos De Petroleo LTDA:During 2012, the Company, through Ocean Rig Block 33 Brasil B.V., entered into a contract with an oil company for the commencement of drilling operations of theOcean Rig Mylos in Brazil. In connection with this contract, Ocean Rig Do Brasil Servicos De Petroleo LTDA., a related party company, owned and controlled by the Sponsor and established in Brazil, entered into a separate service agreement with this oil company for the provision of certain services, including procurement of equipment, maintenance of drillship and administrative services. During 2013 and upon commencement of the drilling operations in Brazil, the related party company has incurred certain expenses in Brazil, on behalf of the Company amounting to $2,262, which have been charged to the Company.

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4. Other Current Assets

The amounts of other current assets included in the predecessor combined carve-out balance sheets as of December 31, 2012 and 2013, are analyzed as follows:

	December 31, 2012		December 31, 2013
Swap cash collateral (Note 10)	$	8,000	$	—
Prepayments and advances		—		285
Inventories		—		3,884
Deferred mobilization expenses		—		19,628
Other		—		2,001
Total	$	8,000	$	25,798

5. Advances for Drillships under Construction and Related Costs

The amounts shown in the predecessor combined carve-out balance sheets as of December 31, 2012 and 2013 include milestone payments under the drillship building contracts with the shipyards, supervision costs and any material related expenses incurred during the construction periods, all of which are capitalized in accordance with the accounting policy discussed in Note 2.

The movement of the advances for drillships under construction and related costs during the years ended December 31, 2013 and 2012 were as follows:

Balance December 31, 2011	$	731,574
Advances for drillships under construction and related costs		39,284
Balance, December 31, 2012	$	770,858
Advances for drillships under construction and related costs		887,471
Drillships delivered		(1,365,637	)
Balance, December 31, 2013	$	292,692

On April 18, 2011, April 27, 2011 and June 23, 2011, pursuant to an option contract with Samsung, the Sponsor exercised certain of its new building drillship options, and entered into drillship building contracts for the seventh generation ultra-deep water drillships, namelyOcean Rig Mylos, Ocean Rig Skyros andOcean Rig Athena, for a total contractual cost of approximately $608,000 per drillship. On August 19, 2013 and on December 20, 2013, the Company took delivery of its newbuilding drillships Ocean Rig Mylos andOcean Rig Skyros, respectively, while theOcean Rig Athena, for which the Company has paid $242,129 up to the year ended December 31, 2013, was delivered on March 24, 2014.

6. Drillships, Machinery and Equipment, net:

The amounts in the predecessor combined carve-out balance sheets are analyzed as follows:

	Cost		Accumulated Depreciation			Net Book Value
Balance December 31, 2012	$	—	$	—		$	—
Transfer from drillships under construction		1,365,637					1,365,637
Additions		58,267		—			58,267
Depreciation				(11,740	)		(11,740	)
Balance December 31, 2013	$	1,423,904		(11,740	)		1,412,164

As of December 31, 2013, the Company’s drillships have been pledged as collateral to secure the Senior Secured Credit Facility discussed in Note 8.

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7. Other Non-Current Assets

The amounts of other non-current assets shown in the predecessor combined carve-out balance sheets as of December 31, 2012 and 2013 are analyzed as follows:

	December 31, 2012		December 31, 2013
Deferred finance costs (Note 8)	$	—	$	7,524
Deferred mobilization expenses		—		33,798
Total	$	—	$	41,322

8. Long-term Debt:

On February 28, 2013, DOV I entered into a Senior Secured Facility agreement with a syndicate of lenders and DNB Bank ASA, as facility agent and security agent, in the amount of $1.35 billion to partially finance the construction costs of theOcean Rig Mylos, theOcean Rig Skyros and theOcean Rig Athena. The facilities agreement is comprised of three secured credit facilities of up to $150,000 each (one relating to each of the aforementioned seventh generation drillships) made available by the commercial lenders, or the Commercial Facilities, three term loan facilities of up to $150,000 each (one relating to each of the aforementioned seventh generation drillships) made available by Eksportkreditt Norge AS, or the Eksportkreditt GIEK Facilities, and three term loan facilities of up to $150,000 each (one relating to each of the aforementioned seventh generation drillships) made available by the Export-Import Bank of Korea, or the Kexim Facilities. All term loan facilities bear interest at LIBOR plus a margin and are repayable in quarterly installments beginning three months after the delivery of each of the drillships. The Commercial Facilities mature five years after the first repayment date while the Eksportkreditt GIEK Facilities and Kexim Facilities mature five or eleven years after the first repayment date at the lenders option. In connection with this loan, DOV I paid $22.4 million as loan origination fees. On August 20, 2013 and December 20, 2013, DOV I drew down an amount of $900,000 in aggregate under the above facility in connection with theOcean Rig Mylos and theOcean Rig Skyros deliveries.

Under the above agreement, Ocean Rig, in its capacity as Guarantor, could only pay dividends or make other distributions in respect of its capital stock in an amount up to 50% of its net income of each previous financial year, provided in each case that Ocean Rig maintains minimum liquidity in an aggregate amount of not less than $200 million in cash and cash equivalents and restricted cash and maintain such level for the next 12 months following the date of the dividend payment.

On August 30, 2013, DOV I signed a supplemental agreement to amend certain provisions in its $1.35 billion Senior Secured Facility. Under the terms of the amendment, the existing dividend restriction of up to 50% of its net income of each previous financial year, described above, was amended to apply on a cumulative basis from July 1, 2013, onwards (50% of cumulative net income) and include a carve-out to pay additional dividends up to the higher of (i) $150,000 and (ii) 5% of the Ocean Rig’s net tangible assets. Furthermore, the minimum interest coverage ratio requirement will be 2.0 times until June 30, 2015 and the maximum leverage ratio will be 6.5 times until June 30, 2014, 6.0 times until December 31, 2014 and 5.5 times until June 30, 2015.

The Senior Secured Facility is secured by among other things, a first priority mortgage over the Company’s drillships and drillship under construction, corporate guarantee by Ocean Rig and other entities of the Group (restricted subsidiaries) and a first assignment of all earnings, insurances and requisition compensation. The loan agreement contains various covenants and securities, such as minimum value clause/minimum liquidity requirements of $25.0 million per each drillship delivered/maintaining working capital above certain level calculated at Ocean Rig’s level, other financial covenants, changes in management and ownership of the drillships, additional indebtedness and mortgaging of drillships, change in the general nature of business, and maintaining an established place of business in the United States or the United Kingdom. The covenants and restrictions apply to DOV I or Sponsor or both, as the case may be.

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Total interest incurred on long-term debt and amortization of debt issuance costs for the years ended December 31, 2012 and 2013, amounted to $0 and $7,569. These amounts, net of capitalized interest of $0 and $283 for the years ended December 31, 2012 and 2013, respectively, are included in “Interest and finance costs” in the combined carve-out statements of operations.

As of December 31, 2013, the Company is required to pay, on a quarterly basis, a commitment fee of 1.40%, per annum of its undrawn portion of the line of credit. The Company’s weighted average interest rates for its loans were 4.2%, for the year ended December 31, 2013. The aggregate available undrawn amount under the Company’s facilities at December 31, 2013, is $450,000.

The annual principal payments required to be made after December 31, 2013, including balloon payments, totaling $890,000 are as follows:

December 31, 2014	$	82,105
December 31, 2015		82,105
December 31, 2016		82,105
December 31, 2017		82,105
December 31, 2018		561,580
Total principal payments		890,000
Less: Deferred financing costs		(14,334	)
Total debt	$	875,666

9. Additional Paid-in Capital:

The amounts shown in the predecessor combined carve-out balance sheets, as additional paid-in capital, represent payments made by Ocean Rig and DryShips at various dates to finance drillships acquisitions, advances for working capital and payments relating to the management agreements with Cardiff and Vivid (Note 3). Moreover, as discussed above, amounts due to and due from the Company to other Ocean Rig entities are recognized within stockholders’ equity in the predecessor combined carve-out financial statements. As Ocean Rig uses a centralized cash management system, whereby cash generated at a subsidiary level is swept into a centralized treasury function at Ocean Rig, intercompany payables and receivables outstanding for the years presented have been deemed to have been treated as equity by the Company.

10. Financial Instruments and Fair Value Measurements:

ASC 815, “Derivatives and Hedging” requires companies to recognize all derivative instruments as either assets or liabilities at fair value in the statement of financial position. The Company recognizes all derivative instruments as either assets or liabilities at fair value on its predecessor combined carve-out balance sheets. Changes in the fair value of derivative instruments that have not been designated as hedging instruments are reported in the predecessor combined carve-out statements of operations.

The Company enters into interest rate swap transactions to manage interest costs and risk associated with changing interest rates with respect to its variable interest rate loans and credit facilities. All of the Company’s derivative transactions are entered into for risk management purposes.

As of December 31, 2012 and 2013, the Company had outstanding three interest rate swaps of $1.2 billion notional amount, maturing from July 2017 through October 2017.

As of December 31, 2012 security deposit of $8,000 was provided as security by the Company. The Company has deposited also in cash, collateral of $6,000 that was classified as current restricted cash. These amounts were released upon the delivery ofOcean Rig Mylos andOcean Rig Skyros.

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Tabular disclosure of financial instruments is as follows:

Fair values of derivative instruments in the predecessor combined carve-out balance sheets as of December 31, 2012 and 2013:

Derivatives not designated as hedging instruments	Balance Sheet Location	December 31, 2012 Fair value			December 31, 2013 Fair value
Interest rate swaps	Financial Instruments non-current assets	$	935		$	13,517
Interest rate swaps	Financial Instruments current liabilities		(1,503	)		(7,788	)
Interest rate swaps	Financial Instruments non-current liabilities		(3,106	)		—
Total derivatives		$	(3,674	)	$	5,729

The effect of derivative instruments, on the predecessor combined carve-out statement of operations, is as follows:

		Amount of Gain/ (Loss)
Derivatives not designated as hedging instruments	Location of Gain or (Loss) Recognized	Year ended December 31, 2012			Year ended December 31, 2013
Interest rate swaps	Gain / (loss) on interest rate swaps, net	$	(3,674	)	$	8,510
Total		$	(3,674	)	$	8,510

The carrying amounts of cash and cash equivalents, restricted cash, trade accounts receivable and accounts payable and other current liabilities reported in the predecessor combined carve-out balance sheet approximate their respective fair values because of the short-term nature of these accounts. The fair value of credit facilities is estimated based on current rates offered to the Company for similar debt of the same remaining maturities. Additionally, the Company considers its creditworthiness in determining the fair value of the credit facilities. The fair value of restricted cash non-current bearing interest at variable interest rates approximates its recorded values as at December 31, 2013 and 2012. The fair value of the interest rate swaps was determined using a discounted cash flow method based on market-based LIBOR swap yield curves, taking into account current interest rates and the creditworthiness of both the financial instrument counterparty and the Company.

The guidance for fair value measurement applies to all assets and liabilities that are being measured and reported on a fair value basis. This guidance enables the reader of the financial statements to assess the inputs used to develop those measurements by establishing a hierarchy for ranking the quality and reliability of the information used to determine fair values. The statement requires that assets and liabilities carried at fair value be classified and disclosed in one of the following three categories.

Fair value measurements are classified based upon inputs used to develop the measurement under the following hierarchy:

Level 1—Quoted market prices in active markets for identical assets or liabilities.

Level 2—Observable market-based inputs or unobservable inputs that are corroborated by market data.

Level 3—Unobservable inputs that are not corroborated by market data.

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The following table summarizes the valuation of assets and liabilities measured at fair value on a recurring basis as of the valuation date.

	December 31, 2012			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)
Interest rate swaps-asset position	$	935			—		935			—
Interest rate swaps-liability position		(4,609	)		—		(4,609	)		—
Total	$	(3,674	)		—		(3,674	)		—

	December 31, 2013			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Unobservable Inputs (Level 3)
Interest rate swaps-asset position	$	13,517			—		13,517			—
Interest rate swaps-liability position		(7,788	)		—		(7,788	)		—
Total	$	5,729			—		5,729			—

11. Income Taxes:

The Company has elected to use the statutory tax rate for each year based upon the location where the largest parts of its operations were domiciled. During 2012 and 2013, most of its activities were in Marshall Islands with tax rate of zero. Foreign loss during 2013 results from Company’s operation in Netherlands.

The components of the Company’s loss before income taxes are as follows:

	Year ended December 31,
Country	2012			2013
Domestic loss (Marshall Islands)	$	(8,079	)	$	(23,090	)
Foreign loss (Netherlands)		—			(2,537	)
Loss before income taxes	$	(8,079	)	$	(25,627	)

Deferred tax asset, for the anticipated future tax effects of temporary differences between the financial statement basis and the tax basis of the Company’s assets and liabilities at the applicable tax rate in Netherlands for 2013, has been fully provided, as it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.

The Company did not have any deferred tax liabilities at December 31, 2012 and 2013.

The Company’s income tax returns are subject to review and examination in the jurisdictions in which the Company operates for periods ranging from three to six years. However, no tax assessments are expected to arise from such reviews and uncertain tax positions are regarded as immaterial. The Company may contest any tax assessment that deviates from its tax filing. As of December 31, 2013, the Company was not subject to any examination on tax matters.

During the years ended December 31, 2012 and 2013, the Company had no unrecognized tax benefits and did not incur any interest or penalties.

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12. Interest and Finance Cost:

The amounts in the predecessor combined carve-out statement of operations are analyzed as follows:

	Year ended December 31,
	2012		2013
Interest costs on long-term debt	$	—	$	6,855
Amortization of financing fees		—		714
Capitalized borrowing costs		—		(283	)
Commissions, commitment fees and other financial expenses		3		13,736
Total	$	3	$	21,022

13. Geographical information for offshore drilling activities

The revenue shown in the table below is based upon the location where the drilling takes place:

	Year ended December 31,
Country	2012		2013
Brazil	$	—	$	37,325
Total service revenue, net	$	—	$	37,325

14. Commitments and Contingencies

14.1 Legal proceedings

Various claims, suits, and complaints, including those involving government regulations and product liability, arise in the ordinary course of the offshore drilling business.

The Company has obtained insurance for the assessed market value of its delivered drillships. However, such insurance coverage may not provide sufficient funds to protect the Company from all liabilities that could result from its operations in all situations. Risks against which the Company may not be fully insured or insurable for include environmental liabilities, which may result from a blow-out or similar accident, or liabilities resulting from reservoir damage alleged to have been caused by the negligence of the Company.

The occurrence of casualty or loss, against which the Company is not fully insured, could have a material adverse effect on the Company’s results of operations and financial condition.

As part of the Company’s normal course of operations, the Company’s customer may disagree on amounts due to the Company under the provision of the contracts which are normally settled through negotiations with the customer. Disputed amounts are normally reflected in revenues at such time as the Company reaches agreement with the customer on the amounts due. The Company’s loss of hire insurance coverage does not protect against loss of income from day one. It covers approximately one year for the loss of time but will be effective after 45 days’ off-hire.

The Company is not party to any litigation where claims or counterclaims have been filed against the Company other than routine legal proceedings incidental to its business.

14.2 Purchase obligations:

The following table sets forth the Company’s contractual purchase obligations as of December 31, 2013:

	1st year		Total
Drillship building contract	$	365,609	$	365,609
Total obligations	$	365,609	$	365,609

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15. Subsequent Events:

15.1 On March 24, 2014, the Company took delivery of the seventh generation drillship,Ocean Rig Athena and drew down the available undrawn amount of $450,000 from the $1.35 billion senior secured facility.

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APPENDIX A

FORM OF FIRST AMENDED AND RESTATED PARTNERSHIP AGREEMENT

OF

Ocean Rig Partners LP

[LOGO]

Ocean Rig Partners LP

Common Units

Representing Limited Partner Interests

Prospectus

                , 2014

Barclays

Credit Suisse

Deutsche Bank Securities

PART II: INFORMATION NOT REQUIRED IN THE PROSPECTUS

Item 6. Indemnification of Officers and Directors

The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our General Partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Reference is made to the Underwriting Agreement to be filed as Exhibit 1.1 to this registration statement in which Ocean Rig Partners LP and its affiliates will agree to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, as amended, or the Securities Act, and to contribute to payments that may be required to be made in respect of these liabilities.

Item 7. Recent Sales of Unregistered Securities.

The following table sets forth all private sales of our shares of our common stock since our formation:

Securities Sold	Date Sold	Consideration Per Share	Total Consideration	Registration Exemption	Purchasers
		$	$

Item 8. Exhibits and Financial Statement Schedules.

Exhibit Number	Description
1.1*	Form of Underwriting Agreement
3.1*	Certificate of Limited Partnership of Ocean Rig Partners LP
3.2*	Form of Amended and Restated Partnership Agreement of Ocean Rig Partners LP (included as Appendix A to prospectus)
3.3	Certificate of Formation of Ocean Rig Partners GP LLC
3.4*	Form of Amended and Restated Limited Liability Company Agreement of Ocean Rig Partners GP LLC
3.5*	Certificate of Formation of Ocean Rig Operating GP LLC
3.6*	Form of Limited Liability Company Agreement of Ocean Rig Operating GP LLC
5.1*	Form of Opinion of Seward & Kissel LLP as to the legality of the securities being registered
8.1*	Form of Opinion of Seward & Kissel LLP with respect to certain U.S. tax matters
10.1*	Vessel Management Agreement for the Ocean Rig Skyros
10.2*	Vessel Management Agreement for the Ocean Rig Mylos
10.3*	Vessel Management Agreement for the Ocean Rig Athena
10.4*	Form of Omnibus Agreement
10.5*	Form of Contribution Agreement
10.7*	New Senior Secured Term Loan Facility
21.1*	List of Subsidiaries
23.1*	Consent of Independent Registered Public Accounting Firm
23.2*	Consent of Drewry Shipping Consultants, Ltd.
23.3*	Consent of Seward & Kissel LLP
24.1**	Powers of Attorney

* To be filed by amendment.

** Contained on the signature page hereto.

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Item 9. Undertakings.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question of whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4), or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initialbona fide offering thereof.

The registrant undertakes to provide to the limited partners the financial statements required by Form 20-F for the first full fiscal year of operations of the partnership.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant certifies that it has reasonable grounds to believe that it meets all of the requirements for filing on Form F-1 and has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Athens, Greece, on the             , 2014 .

OCEAN RIG PARTNERS LP
By:	OCEAN RIG PARTNERS GP LLC, its General Partner
	By: Ocean Rig UDW Inc., its sole member

By:	/s/
	Name:
	Title:

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Gary J. Wolfe and Robert E. Lustrin, or either of them, with full power to act alone, his or her true and lawful attorneys-in-fact and agents, with full powers of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any or all amendments (including post-effective amendments) to this registration statement, and any registration statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing necessary to be done, as fully for all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or their substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this registration statement has been signed by the following persons on                 , 2014 in the capacities indicated.

Signature	Title
	(Principal Executive Officer)
	(Principal Financial Officer and Principal Accounting Officer)

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Authorized Representative in the United States

Pursuant to the requirement of the Securities Act of 1933, as amended, the undersigned, the duly undersigned representative in the United States of Ocean Rig Partners LP has signed this registration statement in the City of             , State of             on             , 2014.

By:
	Name:
	Title:	Authorized Representative in the United States

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