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As filed with the Securities and Exchange Commission on May 5, 2017

Registration No. 333-          

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

 

ROSEHILL RESOURCES INC.

(Exact Name of Registrant as Specified in its Charter)

 

 

 

Delaware		6770		47-5500436
(State or other jurisdiction of incorporation)		(Primary Standard Industrial Classification Code Number)		(I.R.S. Employer Identification No.)

J. A. (Alan) Townsend

President and Chief Executive Officer

16200 Park Row, Suite 300

Houston, Texas 77084

(281) 675-3400

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

 

 

Copies to:

Sarah K. Morgan

W. Matthew Strock

Vinson & Elkins L.L.P.

1001 Fannin St., Suite 2500

Houston, Texas 77002

(713) 758-2222

 

 

Approximate date of commencement of proposed sale to the public:

From time to time after the effective date of this Registration Statement.

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

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

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

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

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

 

Large accelerated filer		☐		Accelerated filer		☐
Non-accelerated filer		☒  (Do not check if a smaller reporting company)		Smaller reporting company		☐
				Emerging growth company		☒

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided to Section 7(a)(2)(B) of the Securities Act.  ☒

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CALCULATION OF REGISTRATION FEE

 

Title of each class of securities to be registered		Amount to be registered		Proposed maximum offering price per share		Proposed maximum aggregate offering price		Amount of registration fee
8.000% Series A Cumulative Perpetual Convertible Preferred Stock, par value $0.0001 per share		114,441(1)		$1,000		$114,441,000		$13,264

(1)

Represents the resale of 75,000 shares of 8.000% Series A Cumulative Perpetual Convertible Preferred Stock (“Series A Preferred Stock”) that were issued to Anchorage Illiquid Opportunities V, L.P., AIO V AIV 3 Holdings, L.P., Geode Diversified Fund and The K2 Principal Fund, L.P. pursuant to a private placement in connection with the Business Combination (as defined herein) as well as 2,200 shares of Series A Preferred Stock that were issued to KLR Energy Sponsor LLC pursuant to the Side Letter (as defined herein), including 37,241 shares of Series A Preferred Stock potentially issuable over the next five years as dividends.

 

 

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, or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission acting pursuant to said Section 8(a), may determine.

 

 

 

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The information contained in this prospectus is not complete and may be changed. No securities may be sold 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 state where the offer or sale is not permitted.

 

Subject to Completion, dated May 5, 2017

Preliminary Prospectus

 

ROSEHILL RESOURCES INC.

8.000% SERIES A CUMULATIVE PERPETUAL CONVERTIBLE PREFERRED STOCK

 

 

 

This prospectus relates to the offer and sale by the selling stockholders identified in this prospectus, or their permitted transferees, of up to 114,441 shares of Series A Preferred Stock of Rosehill Resources Inc. (formerly known as “KLR Energy Acquisition Corp.”) (the “Company,” “we,” “our” or “us”), including 37,241 shares of Series A Preferred Stock potentially issuable over the next five years as dividends which are sometimes referred to in this prospectus as the “Securities.”

The selling securityholders may offer, sell or distribute all or a portion of their Securities publicly or through private transactions at prevailing market prices or at negotiated prices. We will not receive any of the proceeds from the sale of the Securities owned by the selling securityholders. We will bear all costs, expenses and fees in connection with the registration of the Securities, including with regard to compliance with state securities or “blue sky” laws. The selling securityholders will bear all commissions and discounts and transfer taxes, if any, attributable to their sale of the Securities. See “Plan of Distribution” beginning on page 134 of this prospectus.

Our Class A Common Stock and Warrants are listed on The NASDAQ Capital Market (“NASDAQ”) under the symbol “ROSEU”, “ROSE” and “ROSEW.” There is no established trading market for the Series A Preferred Stock. On May 3, 2017, the closing prices of our Units, Class A Common Stock and Warrants were $10.98, $10.06 and $1.57, respectively. As of May 3, 2017, we had 5,856,579 shares of Class A Common Stock, 25,594,158 Warrants and 95,000 shares of Series A Preferred Stock issued and outstanding.

We are an “emerging growth company” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”) and are subject to reduced public company reporting requirements. This prospectus complies with the requirements that apply to an issuer that is an emerging growth company.

INVESTING IN OUR SECURITIES INVOLVES RISKS. PLEASE SEE “RISK FACTORS ” ON PAGE 7 OF THIS PROSPECTUS FOR A DISCUSSION OF CERTAIN RISKS THAT YOU SHOULD CONSIDER IN CONNECTION WITH AN INVESTMENT IN THE SECURITIES.

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

The date of this prospectus is                , 2017

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PROSPECTUS SUMMARY			1
RISK FACTORS			6
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			38
USE OF PROCEEDS			40
DETERMINATION OF OFFERING PRICE			41
PRICE RANGE OF SECURITIES AND DIVIDENDS			42
RATIO OF EARNINGS TO FIXED CHARGES AND TO FIXED CHARGES AND PREFERENCE DIVIDENDS			43
SELECTED HISTORICAL FINANCIAL INFORMATION OF THE COMPANY			44
UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION			47
DESCRIPTION OF BUSINESS			59
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			84
MANAGEMENT			107
EXECUTIVE AND DIRECTOR COMPENSATION			114
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS			120
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT			128
SELLING SECURITYHOLDERS			130
PLAN OF DISTRIBUTION			132
DESCRIPTION OF SECURITIES			135
CERTAIN ERISA CONSIDERATIONS			144
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS			146
LEGAL MATTERS			154
EXPERTS			154
WHERE YOU CAN FIND MORE INFORMATION			154
INDEX TO FINANCIAL STATEMENTS			F-1

You should rely only on the information contained in this prospectus, any prospectus supplement or in any free writing prospectus we may authorize to be delivered or made available to you. We have not, and the selling securityholders have not, authorized anyone to provide you with different information. We and the selling securityholders are not offering to sell, or seeking offers to buy, the Securities in jurisdictions where offers and sales are not permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the Securities.

 

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RISK FACTORS

An investment in the Securities involves a high degree of risk. In addition to the other information included in this prospectus, you should carefully consider each of the risk factors set forth in any applicable prospectus supplement. Any of these risks and uncertainties could have a material adverse effect on our business, financial condition, cash flows and results of operations. If that occurs, the trading price of the Securities could decline materially and you could lose all or part of your investment.

The risks included in this prospectus are not the only risks we face. We may experience additional risks and uncertainties not currently known to us, or as a result of developments occurring in the future. Conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

Unless the context otherwise requires, (i) prior to the completion of the Business Combination, references to “Rosehill Operating” refer to the assets, liabilities and operations of Tema Oil and Gas Company that were contributed to Rosehill Operating Company, LLC in connection with the Business Combination and (ii) following the completion of the Business Combination, references to “Rosehill Operating” refer to Rosehill Operating Company, LLC, the entity through which we currently conduct all of our operations. Due to the fact that Rosehill Operating is our sole operating subsidiary, the risks set forth below that pertain to Rosehill Operating and that may have a material and adverse effect on its financial condition, results of operations and cash flows of Rosehill Operating, would also have a material and adverse effect on our financial condition, results of operations and cash flows.

Risks Related to Rosehill Operating’s Operations

Oil, natural gas and natural gas liquid (“NGL”) prices are volatile. A sustained decline in oil, natural gas and NGL prices could adversely affect Rosehill Operating’s business, financial condition and results of operations and its ability to meet its capital expenditure obligations and financial commitments.

Rosehill Operating’s revenues, profitability, cash flows and future growth, as well as liquidity and ability to access additional sources of capital, depends substantially on prevailing prices for oil, natural gas, and NGLs. Sustained lower prices will reduce the amount of oil, natural gas, and NGLs that Rosehill Operating can economically produce and may result in impairments of its proved reserves or reduction of its proved undeveloped reserves. Oil, natural gas, and NGL prices also affect the amount of cash flow available for capital expenditures and ability to borrow and raise additional capital.

The markets for oil, natural gas, and NGLs have historically been volatile. For example, since January 1, 2014, the WTI spot price for oil declined from a high of $107.95 per barrel on June 20, 2014 to $26.19 per barrel on February 11, 2016, and the Henry Hub spot price for natural gas declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices.

The market prices for oil, natural gas, and NGLs depend on factors beyond Rosehill Operating’s control. Some, but not all, of the factors that can cause fluctuation include:

 

•

worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas, and NGLs;

 

•

the price and quantity of foreign imports of oil, natural gas, and NGLs;

 

•

political and economic conditions in, or affecting, other producing regions or countries, including the Middle East, Africa, South America, and Russia;

 

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•

actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and other state—controlled oil companies, including the ability of members of OPEC to agree to and maintain price and production controls;

 

•

the level of global exploration, development and production;

 

•

the level of global inventories;

 

•

the extent to which U.S. shale producers become “swing producers” adding or subtracting to the world supply;

 

•

prevailing prices on local price indexes in the area in which Rosehill Operating operates;

 

•

the proximity, capacity, cost and availability of gathering and transportation facilities;

 

•

localized and global supply and demand fundamentals and transportation availability;

 

•

the cost of exploring for, developing, producing and transporting reserves;

 

•

weather conditions, other natural disasters, and climate change;

 

•

technological advances affecting energy consumption;

 

•

the price and availability of alternative fuels;

 

•

worldwide conservation measures;

 

•

domestic and foreign governmental relations, regulation, and taxes;

 

•

worldwide governmental regulation and taxes;

 

•

U.S. and foreign trade restrictions, regulations, tariffs, agreements, and treaties;

 

•

the level and effect of trading in commodity futures markets, including commodity price speculators and others; and

 

•

political conditions or hostilities and unrest in oil producing regions.

In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and 2016, global oil supply outpaced demand, resulting in a sustained decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices will likely remain under pressure. The U.S. dollar has also strengthened relative to other leading currencies, which has caused oil prices to weaken, as they are U.S. dollar-denominated. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting the price for NGLs is the supply of NGLs in the United States, which has continued to grow due to an increase in industry participants targeting projects that produce NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and remained weak throughout 2015 and 2016. The declines in natural gas prices are primarily due to an imbalance between supply and demand across North America.

The continued duration and magnitude of these commodity price declines cannot be accurately predicted. Compared to 2014, Rosehill Operating’s average realized oil price before the effects of commodity derivative settlements for 2015 fell 44% to $43.62 per barrel, and its average realized oil price for the year ended December 31, 2016, further decreased to $40.52 per barrel. Similarly, Rosehill Operating’s average realized natural gas price for 2015 dropped 42% to $2.37 per Mcf and its average realized price for NGLs declined 53% to $12.75 per barrel. For the year ended December 31, 2016, Rosehill Operating’s average realized price for natural gas was $2.23 per Mcf and its average realized price for NGLs was $12.68 per barrel.

 

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Lower commodity prices may reduce Rosehill Operating’s cash flows and borrowing ability. If Rosehill Operating is unable to obtain needed capital or financing on satisfactory terms, its ability to develop future reserves could be adversely affected. Furthermore, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current WTI or Henry Hub strip prices and the effect such prices may have on Rosehill Operating’s drilling economics and ability to raise capital may require Rosehill Operating to re-evaluate and postpone or eliminate development drilling, which could result in the reduction of some of Rosehill Operating’s proved undeveloped reserves and related standardized measure. If Rosehill Operating is required to curtail its drilling program, it may be unable to continue to hold leases that are scheduled to expire, which may further reduce Rosehill Operating’s reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect Rosehill Operating’s future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.

Rosehill Operating’s development and acquisition projects require substantial capital expenditures. We and Rosehill Operating may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in its ability to access or grow production and reserves.

The oil and natural gas industry is capital-intensive. Rosehill Operating makes substantial capital expenditures related to development and acquisition projects. Rosehill Operating expects to fund its capital expenditures with cash generated by operations and borrowings under the credit agreement, dated April 27, 2017 (the “Credit Agreement”), by and among the Rosehill Operating and PNC Bank, National Association, as administrative agent and issuing bank, and each of the lenders from time to time party thereto; however, financing needs may require an alteration or increase in our or Rosehill Operating’s capitalization substantially through the issuance of debt or equity or the sale of assets. The issuance of additional indebtedness would require that a portion of the cash flow from Rosehill Operating’s operations be used for the payment of interest and principal on its indebtedness, thereby reducing Rosehill Operating’s ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities by us would be dilutive to stockholders. The actual amount and timing of Rosehill Operating’s future capital expenditures may differ materially from its estimates as a result of, among other things: oil, natural gas and NGL prices; actual drilling results; the availability and cost of drilling rigs and other services and equipment; and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in Rosehill Operating’s actual capital expenditures, which would negatively impact its ability to grow production.

Rosehill Operating’s cash flow from operations and access to capital are subject to a number of variables, including:

 

•

the prices at which its production is sold;

 

•

its proved reserves;

 

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the volume of hydrocarbons it is able to produce from existing wells;

 

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its ability to acquire, locate and produce new reserves;

 

•

the levels of its operating expenses;

 

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its ability to borrow under its Credit Agreement (or any replacement credit facility); and

 

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its ability to access the capital markets.

If cash flow from operations or available borrowings under its Credit Agreement decrease as a result of lower oil, natural gas and NGL prices, operational difficulties, declines in reserves or for any other reason, Rosehill Operating may have limited ability to obtain the capital necessary to sustain operations at current levels. If additional capital is needed, Rosehill Operating may not be able to obtain debt or equity financing on acceptable terms, if at all. If cash flow from operations or available under existing or anticipated credit facilities are insufficient to meet its capital requirements, the failure to obtain additional financing could result in a curtailment of the development of Rosehill Operating’s properties, which in turn could lead to a decline in its reserves and production and could materially and adversely affect its business, financial condition and results of operations.

 

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Rosehill Operating may incur substantial additional debt, which could decrease its ability to maintain operations or service existing debt obligations.

Subject to the restrictions in the instruments governing its debt, Rosehill Operating may incur substantial additional debt in the future. Rosehill Operating’s Credit Agreement contains restrictions on its ability to incur additional indebtedness. Rosehill Operating may also consider investments in joint ventures or acquisitions that may increase its indebtedness. Adding new debt to then existing debt levels could intensify the operational risks that Rosehill Operating now faces.

Drilling for oil and gas involves numerous and significant risks and uncertainties.

Risks that Rosehill Operating faces while drilling wells include:

 

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weather effects, floods, snowstorms, ice storms, and similar natural conditions, on the drilling location and delivery of materials to the wellsite;

 

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unforeseen water flows;

 

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lost circulation of drilling fluids;

 

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unexpected oil and gas flows into the well bore;

 

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drill pipe, casing and equipment failure, or loss of equipment in the well;

 

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failure or inaccuracies of directional drilling measurement devices;

 

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excessive hole washouts in the Salt/Anhydrite zones resulting in poor surface cement jobs;

 

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inability to reach the desired drilling zone with conventional bits and drilling techniques;

 

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failure to land a wellbore in the desired drilling zone;

 

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inability to stay in the desired drilling zone or being able to run tools and other equipment consistently while drilling horizontally through the formation;

 

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difficulties in running casing the entire length of the wellbore;

Risks that Rosehill Operating faces while completing wells include:

 

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the ability to fracture stimulate the planned number of stages;

 

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the ability to run tools the entire length of the wellbore during completion operations; and

 

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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

In addition, certain of the new techniques Rosehill Operating is adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of Rosehill Operating’s drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, Rosehill Operating is more limited in assessing future drilling results in these areas. If Rosehill Operating’s drilling results are less than anticipated, the return on its investment for a particular project may not be as attractive as anticipated, and it could incur material writedowns of unevaluated properties and a decline in the value of Rosehill Operating’s undeveloped acreage.

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect Rosehill Operating’s business, financial condition or results of operations.

Rosehill Operating’s future financial condition and results of operations will depend on the success of its development, acquisition and production activities, which are subject to numerous risks beyond its control, including the risk that drilling will not result in commercially viable oil and natural gas production.

 

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Rosehill Operating’s decisions to develop or purchase prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of Rosehill Operating’s reserves” below. In addition, Rosehill Operating’s cost of drilling, completing and operating wells is often uncertain.

Many factors may curtail, delay or cancel Rosehill Operating’s scheduled drilling projects, including the following:

 

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delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal, emission of greenhouse gases (“GHGs”) and limitations on hydraulic fracturing;

 

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pressure or irregularities in geological formations;

 

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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for hydraulic fracturing activities;

 

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equipment failures, accidents or other unexpected operational events;

 

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lack of available gathering facilities or delays in construction of gathering facilities;

 

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lack of available capacity on interconnecting transmission pipelines;

 

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adverse weather conditions, including such conditions which are possibly connected to climate change;

 

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drought conditions limiting the availability of water for hydraulic fracturing, including such conditions as possibly connected to climate change;

 

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issues related to compliance with environmental regulations;

 

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environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

 

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declines in oil and natural gas prices;

 

•

limited availability of financing at acceptable terms;

 

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title problems; and

 

•

limitations in the market for oil and natural gas.

Rosehill Operating may not be able to generate sufficient cash to service all of its indebtedness and may be forced to take other actions to satisfy its obligations under applicable debt instruments, which may not be successful.

Rosehill Operating’s ability to make scheduled payments on, or to refinance, its indebtedness obligations, including Rosehill Operating’s Credit Agreement or line of credit, depends on its financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond its control. Rosehill Operating may not be able to maintain a level of cash flows from operating activities sufficient to permit it to pay the principal, premium, if any, and interest on its current and future indebtedness.

If Rosehill Operating’s cash flows and capital resources are insufficient to fund debt service obligations, it may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Rosehill Operating’s ability to restructure or refinance its indebtedness will

 

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depend on the condition of the capital markets and its financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require Rosehill Operating to comply with more onerous covenants, which could further restrict business operations. The terms of future debt instruments may restrict Rosehill Operating from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of Rosehill Operating’s credit rating, which could harm Rosehill Operating’s ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, Rosehill Operating could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Rosehill Operating’s Credit Agreement restricts its ability to dispose of assets and its use of the proceeds from such disposition. Rosehill Operating may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit Rosehill Operating to meet scheduled debt service obligations.

Restrictions in Rosehill Operating’s Credit Agreement limit, and its future debt agreements could limit, its ability to engage in certain activities.

Rosehill Operating’s Credit Agreement contains, and its future debt agreements may contain, a number of significant covenants, including restrictive covenants that limit its ability to, among other things:

 

•

incur additional indebtedness;

 

•

be liable in respect of any third party guaranty;

 

•

incur liens;

 

•

make loans to others;

 

•

make investments;

 

•

pay dividends or make distributions to third parties;

 

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liquidate, merge or consolidate with another entity;

 

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enter into commodity hedges exceeding a specified percentage of Rosehill Operating’s expected production;

 

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enter into interest rate hedges exceeding a specified percentage of the Rosehill Operating’s outstanding indebtedness;

 

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sell properties or assets;

 

•

issue additional shares of capital stock; and

 

•

engage in certain other transactions without the prior consent of PNC Bank, National Association and/or the lenders.

In addition, Rosehill Operating’s Credit Agreement requires it to maintain the following financial ratios: (1) a working capital ratio, which is the ratio of consolidated current assets (including unused commitments under the Credit Agreement, but excluding non-cash assets) to consolidated current liabilities (excluding non-cash obligations, reclamation obligations to the extent classified as current liabilities and current maturities under the Credit Agreement), of not less than 1.0 to 1.0, and (2) a leverage ratio, which is the ratio of the sum of all of Rosehill Operating’s Total Funded Debt to EBITDAX (as such terms are defined in the Credit Agreement) for the four fiscal quarters then ended, of not greater than 4.00 to 1.00. Failure to do so could result in mandatory or full repayment of the indebtedness. The senior secured revolving credit facility also does not permit Rosehill Operating to borrow funds if at the time of such borrowing, Rosehill Operating is not in pro forma compliance with the financial covenants.

The restrictions in Rosehill Operating’s Credit Agreement limit its ability to obtain future financings to withstand a future downturn in its business or the economy in general, or to otherwise conduct necessary

 

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corporate activities. Rosehill Operating may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under its Credit Agreement impose on it.

A breach of any covenant in Rosehill Operating’s Credit Agreement likely would result in a default under the Credit Agreement after any applicable grace periods. A default, if not waived, could result in acceleration of the indebtedness outstanding under Rosehill Operating’s Credit Agreement and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness may become immediately due and payable. If that occurs, Rosehill Operating may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to Rosehill Operating or us. If an event of default occurs under the Credit Agreement, PNC Bank, National Association will have the right to proceed against the pledged capital stock and take control of substantially all of Rosehill Operating and Rosehill Operating’s material operating subsidiaries that are guarantors’ assets.

Any significant reduction in the borrowing base under Rosehill Operating’s Credit Agreement as a result of the periodic borrowing base redeterminations or otherwise may negatively impact its ability to fund its operations.

Rosehill Operating’s Credit Agreement limits the amounts Rosehill Operating can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine at certain periods throughout the year. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing Rosehill Operating’s loan. If Rosehill Operating does not furnish the information required for the redetermination by the specified date, the lender may nonetheless redetermine the borrowing base in their sole discretion until the relevant information is received.

In the future, Rosehill Operating may not be able to access adequate funding under its Credit Agreement (or a replacement facility) as a result of a decrease in its borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such a case, Rosehill Operating could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, Rosehill Operating may be unable to implement its respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on its financial condition and results of operations and impair its ability to service its indebtedness.

Rosehill Operating’s derivative activities could result in financial losses or could reduce its earnings.

A portion of Rosehill Operating’s oil and natural gas production has historically been hedged in order to protect cash flow from falling prices. The use of these arrangements limits its ability to benefit from increases in the prices of natural gas and oil. As of December 31, 2016, Rosehill Operating had entered into derivative commodity contracts through December 2017 covering a total of 679 MBbls of oil and 4,030 MMcf of natural gas projected oil and natural gas production. At the closing of the Business Combination, all crude oil options and natural gas options were settled, and all crude oil swaps and all natural gas swaps were transferred to Rosehill Operating. Accordingly, Rosehill Operating’s earnings may fluctuate significantly as a result of changes in fair value of its commodity derivatives.

Commodity derivatives may also expose Rosehill Operating to the risk of financial loss in some circumstances, including when:

 

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production and sales are insufficient to offset losses under the commodity derivatives;

 

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the counterparty to the commodity derivatives defaults on its contractual obligations;

 

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•

there is an increase in the differential between the underlying price in the commodity derivatives and actual prices received;

 

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issues arise with regard to legal enforceability of such instruments; or

 

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applicable laws or regulations regarding such instruments are changed.

The use of commodity derivatives may, in some cases, require the posting of cash collateral with counterparties. If Rosehill Operating enters into commodity derivatives that require cash collateral, particularly if commodity prices or interest rates change in a manner averse to Rosehill Operating, Rosehill Operating’s cash otherwise available for use in its operations would be reduced, which could limit its ability to make future capital expenditures and make payments on its indebtedness, and which could also limit the size of its borrowing base. Future collateral requirements will depend on arrangements with counterparties, highly volatile oil and natural gas prices and interest rates. In addition, commodity derivatives could limit the benefit Rosehill Operating would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on Rosehill Operating’s financial condition.

Rosehill Operating’s commodity derivative contracts expose it to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and Rosehill Operating may not be able to realize the benefit of the contract. Rosehill Operating is unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if Rosehill Operating accurately predicts sudden changes, its ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices, Rosehill Operating’s commodity derivative contract receivable positions have generally increased, which has increased Rosehill Operating’s counterparty credit exposure. If the creditworthiness of Rosehill Operating’s counterparties deteriorates and results in their nonperformance, Rosehill Operating could incur a significant loss with respect to its commodity derivative contracts.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of Rosehill Operating’s reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of Rosehill Operating’s reserves. In order to prepare reserve estimates, Rosehill Operating must project production rates and timing of development expenditures. Rosehill Operating must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from Rosehill Operating’s estimates. For instance, initial production rates reported by Rosehill Operating or other operators may not be indicative of future or long-term production rates, Rosehill Operating’s recovery efficiencies may be worse than expected, and production declines may be greater than Rosehill Operating estimates and may be more rapid and irregular when compared to initial production rates. In addition, Rosehill Operating may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of Rosehill Operating’s reserves.

 

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You should not assume that the present value of future net revenues from Rosehill Operating’s reserves is the current market value of its estimated reserves. Rosehill Operating generally bases the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, Rosehill Operating’s estimated proved reserves as of December 31, 2016 and related standardized measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $42.75 per barrel of oil (WTI), $11.73 per barrel of NGL (27.5% of WTI), and $2.49 per MMBtu of natural gas (Henry Hub spot) which, for certain periods in 2016, were substantially higher than the available spot prices. If spot prices are below such calculated amounts, using more recent prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits.

Rosehill Operating will not be the operator on all of its acreage or drilling locations, and, therefore, it will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

Rosehill Operating has leased or acquired approximately 4,789 net acres in the Delaware Basin, approximately 95% of which it operates, as of December 31, 2016. As of December 31, 2016, Rosehill Operating was the operator on 193 of its 202 identified gross horizontal drilling locations. Rosehill Operating will have limited ability to exercise influence over the operations of the drilling locations it does not operate, and the operators of those locations may at any time have economic, business or legal interests or goals that are inconsistent with Rosehill Operating’s. Furthermore, the success and timing of development activities by such operators will depend on a number of factors that will be largely outside of Rosehill Operating’s control, including:

 

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the timing and amount of capital expenditures;

 

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the operator’s expertise and financial resources;

 

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the approval of other participants in drilling wells;

 

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the selection of technology; and

 

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the rate of production of reserves, if any.

This limited ability to exercise control over the operations and associated costs of some of Rosehill Operating’s non-operated drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities.

Rosehill Operating participates in oil and gas leases with third parties who may not be able to fulfill their commitments to its projects.

Rosehill Operating owns less than 100% of the working interest on approximately 5% of the oil and gas leases on which it conducts operations, and other parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. Rosehill Operating could potentially be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. Other working interest owners may be unable or unwilling to pay their share of project costs, and, in some cases, may declare bankruptcy. In the event any other working interest owners do not pay their share of such costs, Rosehill Operating would likely have to pay those costs, and may be unsuccessful in any efforts to recover these costs from other working interest owners, which could materially adversely affect its financial position.

 

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Rosehill Operating’s identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, Rosehill Operating may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Rosehill Operating has specifically identified and scheduled certain drilling locations as an estimation of its future multi-year drilling activities on its existing acreage. These drilling locations represent a significant part of Rosehill Operating’s growth strategy. Rosehill Operating’s ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, Rosehill Operating does not know if the potential drilling locations its management has identified will ever be drilled or if it will be able to produce oil or natural gas in commercial qualities from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, Rosehill Operating’s actual drilling activities may materially differ from those presently identified.

As of December 31, 2016, 202 gross potential horizontal drilling locations, which includes 13 locations associated with proved undeveloped reserves as of December 31, 2016, have been identified on Rosehill Operating’s acreage based on approximately 1,320-foot spacing with 40 wells per 640-acre section in the ten formations from the Brushy Canyon through Wolfcamp B formations. As of December 31, 2016, 146 of Rosehill Operating’s gross potential horizontal drilling locations were economic using SEC pricing assumptions. Horizontal lateral effective lengths range from 4,300 feet up to 4,700 feet. As a result of the limitations described above, Rosehill Operating may be unable to drill many of the identified locations. Based on future operations or regulatory changes, Rosehill Operating may determine that certain formations cannot be physically or economically exploited or that spacing of wells may have to be changed. In addition, Rosehill Operating will require significant additional capital over a prolonged period in order to pursue the development of these locations, and it may not be able to raise or generate the capital required to do so. See “Rosehill Operating’s development and acquisition projects require substantial capital expenditures. We and Rosehill Operating may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in its ability to access or grow production and reserves” above. Any drilling activities Rosehill Operating is able to conduct on these locations may not be successful or result in Rosehill Operating’s ability to add additional proved reserves to its overall proved reserves or may result in a downward revision of its estimated proved reserves, which could have a material adverse effect on its future business and results of operations. Additionally, if Rosehill Operating curtails its drilling program, it may lose a portion of its acreage through lease expirations.

Certain of Rosehill Operating’s undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.

As of December 31, 2016, approximately 89% of Rosehill Operating’s total net acreage was either held by production or under continuous drilling provisions. The leases for Rosehill Operating’s net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. If Rosehill Operating’s leases expire and it is unable to renew the leases, Rosehill Operating will lose the right to develop the related properties. Rosehill Operating’s ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.

 

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Adverse weather conditions may negatively affect Rosehill Operating’s operating results and its ability to conduct drilling activities.

Adverse weather conditions may cause, among other things, increases in the costs of, and delays in, drilling or completing new wells, power failures, temporary shut-in of production and difficulties in the transportation of Rosehill Operating’s oil, natural gas and NGLs. Any decreases in production due to poor weather conditions will have an adverse effect on Rosehill Operating’s revenues, which will in turn negatively affect its cash flow from operations.

Rosehill Operating’s operations are substantially dependent on the availability of water. Restrictions on Rosehill Operating’s ability to obtain water may have an adverse effect on its financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas drilling and hydraulic fracturing processes. Drought conditions have persisted in Texas in past years. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If Rosehill Operating is unable to obtain water to use in its operations, it may be unable to economically produce oil and natural gas, which could have a material and adverse effect on its financial condition, results of operations and cash flows.

The core of Rosehill Operating’s producing properties are located in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas and New Mexico, making Rosehill Operating vulnerable to risks associated with operating in a single geographic area.

The core of Rosehill Operating’s producing properties are geographically concentrated in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas. At December 31, 2016, 92% of Rosehill Operating’s total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, Rosehill Operating may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

The marketability of Rosehill Operating’s production will be dependent upon transportation and other facilities, certain of which Rosehill Operating will not control. If these facilities are unavailable, Rosehill Operating’s operations could be interrupted and its revenues reduced.

The marketability of Rosehill Operating’s oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Rosehill Operating’s oil production is purchased at the wellhead by Gateway Gathering and Marketing (“Gateway”), an affiliate of Tema, and transported through Gateway’s Raven Gathering System (“Raven”) pipeline to the interconnection between Raven pipeline and Plains Marketing, LP pipeline. The oil is then transported on a third party pipeline to Midland, Texas where it is sold. Rosehill Operating’s natural gas production is transported by Gateway on Gateway’s Loving County Gathering System (“LCGS”) pipeline from the wellhead to the interconnection between LCGS pipeline and ETC Field Services pipeline. The gas is sold by Rosehill Operating to the third party (ETC Field Services) at the interconnection between LCGS and ETC Field Services. ETC Field Services transports the gas to its processing facility. In connection with the Business Combination, Rosehill Operating and Gateway have agreed to enter into crude oil gathering and natural gas gathering agreements with ten-year terms.

Rosehill Operating does not control Gateway’s or the third-party’s transportation facilities and its access to the facilities may be limited or denied. Insufficient production from Rosehill Operating’s wells to support the construction of pipeline facilities by Rosehill Operating’s purchasers or a significant disruption in the availability

 

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of third-party transportation facilities or other production facilities could adversely impact Rosehill Operating’s ability to deliver to market or produce its oil and natural gas and thereby cause a significant interruption in its operations. If, in the future, Rosehill Operating is unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, it may be required to shut in or curtail production or flare natural gas. Any such shut-in, curtailment, or flaring or an inability to obtain favorable terms for delivery of the oil and natural gas produced from its fields, would materially and adversely affect Rosehill Operating’s financial condition and results of operations.

Rosehill Operating may incur losses as a result of title defects in the properties in which it invests.

The existence of a material title deficiency can render a lease worthless and can adversely affect Rosehill Operating’s results of operations and financial condition. While Rosehill Operating has historically obtained title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case Rosehill Operating may lose the lease and the right to produce all or a portion of the minerals under the property and may be required to pay damages to the actual owner of the lease.

The development of Rosehill Operating’s estimated proved undeveloped reserves (“PUDs”) may take longer and may require higher levels of capital expenditures than currently anticipated. Therefore, Rosehill Operating’s estimated PUDs may not be ultimately developed or produced.

As of December 31, 2016, 50% of Rosehill Operating’s total estimated proved reserves were classified as PUDs. Development of these PUDS may take longer and require higher levels of capital expenditures than currently anticipated. For example, primarily as a result of factors outside Rosehill Operating’s control, including a downturn in commodity prices, Rosehill Operating adjusted its development plan to temporarily defer the drilling of certain PUD locations. As a result, no PUDs were converted from undeveloped to developed during 2015 and 2016. As a result of Rosehill Operating’s failure to convert any PUDs during 2015 and 2016, Rosehill Operating will have a shorter period of time available to convert such PUDs (due to the requirement to convert PUDs from undeveloped to developed within five years of initial booking). Further delays in the development of Rosehill Operating’s PUDs, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of Rosehill Operating’s estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause Rosehill Operating to have to reclassify its PUDs as unproved reserves if Rosehill Operating no longer believes with reasonable certainty that it will develop the PUDs within five years after their initial booking. If Rosehill Operating does not drill its PUD wells within five years after their respective dates of booking, Rosehill Operating may be required to write-down its PUDs.

If commodity prices decrease to a level such that Rosehill Operating’s future undiscounted cash flows from its properties are less than their carrying value, Rosehill Operating may be required to take impairments or write-downs of the carrying values of Rosehill Operating’s properties.

Accounting rules require periodic review of the carrying value of Rosehill Operating’s properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, Rosehill Operating may be required to write-down the carrying value of its properties. A write-down constitutes a non-cash charge to earnings. Commodity prices have declined significantly in recent year. Since January 1, 2014, the WTI spot price for oil declined from a high of $107.95 per barrel on June 20, 2014 to $26.19 per barrel on February 11, 2016, and the Henry Hub spot price for natural gas declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs have suffered significant recent declines in realized prices. The price of propane (Mont Belvieu) ranged from a high of $1.73 per gallon in February 2014 to a low of $0.30 per gallon in January 2016 and the price of ethane (Mont Belvieu) ranged from a high of $0.45 per gallon in January 2014 to a low of $0.13 per gallon in December 2015. Rosehill Operating recognized impairment charges of $8.1 million and $27.6 million

 

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in the years ended December 31, 2015 and 2014, respectively. No impairment was recognized in the year ended December 31, 2016. Lower commodity prices in the future could result in impairments of Rosehill Operating’s properties, which could have a material adverse effect on its results of operations for the periods in which such charges are taken.

Unless Rosehill Operating replaces its reserves with new reserves and develops those reserves, Rosehill Operating’s reserves and production will decline, which would adversely affect its future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless Rosehill Operating conducts successful ongoing exploration and development activities or continually acquires properties containing proved reserves, Rosehill Operating’s proved reserves will decline as those reserves are produced. Rosehill Operating’s future reserves and production, and therefore its future cash flow and results of operations, are highly dependent on its success in efficiently developing its current reserves and economically finding or acquiring additional recoverable reserves. Rosehill Operating may not be able to develop, find or acquire sufficient additional reserves to replace the current and future production. If Rosehill Operating is unable to replace its current and future production, the value of its reserves will decrease, and its business, financial condition and results of operations would be materially and adversely affected.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on Rosehill Operating’s business, financial condition, results of operations and cash flows.

Rosehill Operating depends upon significant purchasers for the sale of most of its oil, natural gas and NGL production.

Rosehill Operating has historically sold its production to a relatively small number of customers, as is customary in its business. For the years ended December 31, 2016 and 2015, three and four customers accounted for approximately 97% and 89%, respectively, of Rosehill Operating’s total revenue. During such years, no other purchaser accounted for 10% or more of Rosehill Operating’s revenue. The loss of any one or all of its significant customers as a purchaser could materially and adversely affect Rosehill Operating’s revenues in the short-term.

Rosehill Operating’s operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to its business activities.

Rosehill Operating’s operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of Rosehill Operating’s operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to Rosehill Operating’s operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; the imposition of substantial liabilities for pollution resulting from Rosehill Operating’s operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency (“EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of

 

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sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of Rosehill Operating’s operations; and plugging and abandonment responsibilities for wells which have ceased producing. In addition, Rosehill Operating may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt its operations and limit its growth and revenue.

Certain environmental laws impose strict as well as joint and several liabilities for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. Rosehill Operating may be required to remediate contaminated properties currently or formerly operated by Rosehill Operating or its predecessors in interest or facilities of third parties that received waste generated by Rosehill Operating’s operations regardless of whether such contamination resulted from the conduct of others or from consequences of Rosehill Operating’s own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, Rosehill Operating could acquire, or be required to provide indemnification against, environmental liabilities that could expose it to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of Rosehill Operating’s operations. Rosehill Operating’s insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against it. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. For example, in June 2016, the EPA finalized a rule regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, Rosehill Operating’s business, prospects, financial condition or results of operations could be materially adversely affected.

Rosehill Operating may incur substantial losses and be subject to substantial liability claims as a result of its operations. Additionally, Rosehill Operating may not be insured for, or the insurance may be inadequate to protect it against, these risks.

Rosehill Operating is not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect Rosehill Operating’s business, financial condition or results of operations.

Rosehill Operating’s exploration and development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

 

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environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and air contamination;

 

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abnormally pressured formations;

 

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mechanical difficulties, such as stuck oilfield drilling and service tools and drill pipe or casing failures or collapse;

 

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fire, explosions and ruptures of pipelines;

 

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personal injuries and death;

 

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natural disasters, which may include severe weather as possibly connected to climate change and seismic events as possibly connected to injection of produced water and flowback into disposal wells; and

 

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terrorist attacks targeting oil and natural gas related facilities and infrastructure.

 

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Any of these risks could adversely affect Rosehill Operating’s ability to conduct operations or result in substantial loss to us as a result of claims for:

 

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injury or loss of life;

 

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damage to and destruction of property, natural resources and equipment;

 

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pollution and other environmental damage;

 

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statutory or regulatory investigations and penalties; and

 

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repair and remediation costs.

Rosehill Operating may elect not to obtain insurance for any or all of these risks if it believes that the cost of available insurance is excessive relative to the risks presented. In addition, statutory and regulatory penalties, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on Rosehill Operating’s business, financial condition and results of operations.

Properties that Rosehill Operating decides to drill may not yield oil or natural gas in commercially viable quantities.

Properties that Rosehill Operating decides to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect its results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields and data from other wells in the same area, or more fully explored prospects, will not enable Rosehill Operating to know conclusively prior to drilling whether oil or natural gas will be present or, if present, in commercial quantities. Further, drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

 

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unexpected or adverse drilling conditions;

 

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title problems;

 

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elevated pressure or lost circulation in formations;

 

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equipment failures or accidents;

 

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adverse weather conditions;

 

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compliance with environmental and other governmental or contractual requirements; and

 

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increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We and Rosehill Operating may be unable to make attractive acquisitions or successfully integrate acquired assets or businesses, and any inability to do so may disrupt its business and hinder its ability to grow.

In the future, we and Rosehill Operating may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we and Rosehill Operating will be able to identify attractive acquisition opportunities. In the event we and Rosehill Operating are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause Rosehill Operating to refrain from, completing acquisitions.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired assets or business. The process of integrating acquired assets or businesses may involve unforeseen difficulties and may require a disproportionate amount of managerial and financial resources. In addition, possible future

 

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acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we or Rosehill Operating will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our and Rosehill Operating’s failure to achieve consolidation savings, to integrate the acquired businesses and assets into its existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on its financial condition and results of operations.

In addition, Rosehill Operating’s Credit Agreement imposes, and future debt agreements may impose, limitations on its ability to enter into mergers or combination transactions. Such limitations may also restrict Rosehill Operating’s ability to incur certain indebtedness, which could indirectly limit our and Rosehill Operating’s ability to engage in acquisitions of assets or businesses.

Certain of Rosehill Operating’s properties are subject to land use restrictions, which could limit the manner in which it conducts its business.

In order to bring equipment, supplies, water, personnel and produced products to and from certain of its properties, Rosehill Operating and/or its contractors must obtain permissions or rights-of-way from other parties, including private property owners and governmental agencies. There is no guarantee that Rosehill Operating or its contractors will be able to obtain or continue to obtain those permissions or rights or to obtain them at a reasonable cost. In addition, certain of Rosehill Operating’s properties are subject to land use restrictions, including ordinances, which could limit the manner in which it conducts its business. Although none of Rosehill Operating’s proposed drilling locations associated with proved undeveloped reserves as of December 31, 2016 are on properties currently subject to such land use restrictions, such restrictions may become effective in the future. All of the permissions, rights-of-way, and restrictions discussed above could affect, among other things, Rosehill Operating’s access to and the permissible uses of Rosehill Operating’s facilities as well as the manner in which it produces oil and natural gas and may restrict or prohibit drilling in general. The costs incurred to comply with such restrictions may be significant in nature, and Rosehill Operating may experience delays or curtailment in the pursuit of development activities and may even be precluded from the drilling of wells.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect Rosehill Operating’s ability to execute its development plans within its budget and on a timely basis.

Rosehill Operating does not own any drilling rigs, nor does it own other equipment and supplies that are critical to its continuing ability to drill for and produce oil, gas, and NGLs. It is dependent on access to qualified and competent contractors for such equipment and supplies, as well as the personnel to engage in Rosehill Operating’s drilling and production program. The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Rosehill Operating’s operations are concentrated in areas in which industry had increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, had increased, as did the costs for those items. However, beginning in the second half of 2014, commodity prices began to decline and the demand for goods and services has subsided due to reduced activity. To the extent that commodity prices improve in the future, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for Rosehill Operating to resume or increase its development activities could result in production volumes being below Rosehill Operating’s forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on Rosehill Operating’s cash flow and profitability. Furthermore, if Rosehill Operating is unable to secure a sufficient number of drilling rigs at reasonable costs, it may not be able to drill all of its acreage before its leases expire.

 

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Rosehill Operating could experience periods of higher costs if commodity prices rise. These increases could reduce Rosehill Operating’s profitability, cash flow and ability to complete development activities as planned.

Historically, Rosehill Operating’s capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond Rosehill Operating’s control, such as increases in the cost of electricity, steel and other raw materials that Rosehill Operating and its vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in Rosehill Operating’s revenue if commodity prices rise, thereby negatively impacting Rosehill Operating’s profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that Rosehill Operating’s ability to participate in the commodity price increases is limited by its prior or future commodity derivative activities.

Should Rosehill Operating fail to comply with all applicable Federal Energy Regulatory Commission (“FERC”) administered statutes, rules, regulations and orders, Rosehill Operating could be subject to substantial penalties and fines.

Under the Domenici-Barton Energy Policy Act of 2005 (“EP Act of 2005”), FERC has civil penalty authority under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act (“NGPA”) to impose penalties of up to $1 million per day for each violation for current violations and disgorgement of profits associated with any violation. While Rosehill Operating’s operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of Rosehill Operating’s otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. Rosehill Operating also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject Rosehill Operating to civil penalty liability.

Climate change laws and regulations restricting emissions of greenhouse gasses (“GHGs”) could result in increased operating costs and reduced demand for the oil and natural gas that Rosehill Operating produces, while potential physical effects of climate change could disrupt Rosehill Operating’s production and cause it to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that otherwise require such permits for non-GHG emissions. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect Rosehill Operating’s operations and restrict or delay Rosehill Operating’s ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of Rosehill Operating’s operations. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, and increased frequency of maintenance and repair activities to address emissions

 

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leakage. The rules will also likely require additional personnel time to support these activities or the engagement of third party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on Rosehill Operating’s operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently in April 2016, the United States was one of 175 countries to ratify the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact Rosehill Operating’s business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, Rosehill Operating’s equipment and operations could require Rosehill Operating to incur costs to reduce emissions of GHGs associated with its operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas Rosehill Operating produces and lower the value of its reserves. Finally, it should be noted that some scientists, reportedly a majority who have studied the issue, have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other climatic events. Rosehill Operating’s operations are onshore and not located in coastal or flood-prone regions of the United States, but if any such effects were to occur, they have the potential to cause physical damage to its assets or affect the availability of water for its operations and thus could have a material adverse effect on Rosehill Operating’s operations.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect Rosehill Operating’s production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Rosehill Operating regularly uses hydraulic fracturing as part of its operations and expects to continue that practice. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing, and also finalized rules in July 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming set aside the rules as beyond BLM’s jurisdiction to promulgate. The district court’s decision is on appeal to the Tenth Circuit, with oral argument scheduled for March 2017. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect Rosehill Operating’s operations.

 

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In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. As described elsewhere in this prospectus, these risks are regulated under various state, federal, and local laws. The EPA’s study report did not find a direct link between the action of hydraulically fracturing the well itself and contamination of groundwater resources. The study report does not, therefore, appear to provide a reasonable basis to expect Congress to repeal the exemption for hydraulic fracturing under the federal Safe Drinking Water Act at the federal level.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where Rosehill Operating operates, it could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.

Legislation or regulatory initiatives intended to address seismic activity could restrict Rosehill Operating’s drilling and production activities, as well as its ability to dispose of produced water, including saltwater, gathered from such activities, which could have a material adverse effect on Rosehill Operating’s business.

State and federal regulatory agencies recently have focused on a possible connection between hydraulic fracturing related activities and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Survey identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In addition, a number of lawsuits have been filed in other states, for example recent lawsuits in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well.

Rosehill Operating disposes of large volumes of produced water, including saltwater, gathered from its drilling and production operations pursuant to permits issued to Tema, which permits will be transferred to Rosehill Operating at the closing of the Business Combination, by governmental authorities overseeing such

 

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disposal activities and pursuant to permissions granted by the owners of properties where the disposal wells are located. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change. The permissions granted by property owners are subject to change. Any changes could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities or property owners regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations or changes in permissions that restrict Rosehill Operating’s expected ability to use hydraulic fracturing or dispose of produced water gathered from its drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring Rosehill Operating to shut down disposal wells, could have a material adverse effect on its business, financial condition and results of operations.

Competition in the oil and natural gas industry is intense, making it more difficult for Rosehill Operating to acquire properties, market oil or natural gas and secure trained personnel.

Rosehill Operating’s ability to acquire additional prospects and to find and develop reserves in the future will depend on Rosehill Operating’s ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of Rosehill Operating’s competitors possess and employ financial, technical and personnel resources substantially greater than Rosehill Operating’s. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than Rosehill Operating’s financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than Rosehill Operating is able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. Rosehill Operating may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on its business.

The loss of senior management or technical personnel could adversely affect Rosehill Operating’s operations.

Rosehill Operating depends on the services of its senior management and technical personnel. Rosehill Operating does not maintain, nor does it plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of such senior management or technical personnel could have a material adverse effect on Rosehill Operating’s business, financial condition and results of operations.

Rosehill Operating’s business is difficult to evaluate because it may be susceptible to the potential difficulties associated with rapid growth and expansion.

Rosehill Operating’s assets have grown rapidly over the last several years. Rosehill Operating believes that its future success depends on its ability to manage the rapid growth that it has experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

 

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increased responsibilities for Rosehill Operating’s executive level personnel;

 

•

increased administrative burden;

 

•

increased capital requirements; and

 

•

increased organizational challenges common to large, expansive operations.

Rosehill Operating’s operating results could be adversely affected if it does not successfully manage these potential difficulties. The historical financial information contained in this prospectus is not necessarily indicative of the results that may be realized in the future.

 

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Increases in interest rates could adversely affect Rosehill Operating’s business.

Rosehill Operating’s business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause Rosehill Operating’s cost of doing business to increase, limit its ability to pursue acquisition opportunities, reduce cash flow used for drilling and place it at a competitive disadvantage. For example, as of December 31, 2016, outstanding borrowings of Rosehill Operating subject to variable interest rates were approximately $55.0 million, and a 1.0% increase in interest rates would result in an increase in annual interest expense of approximately $0.6 million, assuming the $55.0 million of debt was outstanding for the full year. Rosehill Operating’s Credit Agreement is subject to similar or greater interest rate expenses. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting Rosehill Operating’s ability to finance operations. Rosehill Operating requires continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect its ability to achieve planned growth and operating results.

Rosehill Operating may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing properties requires an assessment of several factors, including:

 

•

recoverable reserves;

 

•

future oil and natural gas prices and their applicable differentials;

 

•

operating costs; and

 

•

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, Rosehill Operating performs a review of the subject properties that it believes to be generally consistent with industry practices. However, these reviews will not reveal all existing or potential problems, nor will it permit Rosehill Operating to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Often Rosehill Operating may be entitled to contractual indemnification for environmental liabilities and has acquired properties on an “as is” basis.

Rosehill Operating’s disposition activities may be subject to factors beyond its control, and in certain cases it may retain unforeseen liabilities for certain matters.

Rosehill Operating has regularly sold non-core assets in order to increase capital resources available for other core assets and to create organizational and operational efficiencies. It has also occasionally sold interests in core assets for the purpose of accelerating the development and increasing efficiencies in such core assets. Various factors could materially affect Rosehill Operating’s ability to dispose of such assets in the future, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets with terms Rosehill Operating deems acceptable.

Sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release Rosehill Operating from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, Rosehill Operating may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

 

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As a result of future legislation, certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated and Rosehill Operating’s production may be subject to the imposition of new state or local taxes.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including to certain key U.S. federal income tax provisions currently available to oil and gas exploration and production companies. Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities, (iv) an extension of the amortization period for certain geological and geophysical expenditures. Congress could consider, and could include, some or all of these proposals as part of tax reform legislation, to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such changes, as well as any changes to or the imposition of new state or local taxes (including the imposition of, or increase in production, severance or similar taxes), could increase the cost of exploration and development of oil and gas resources, which would negatively affect Rosehill Operating’s financial condition, results of operations and cash flows.

Risks Related to The Securities and Our Capital Structure

The market price of the Company’s Securities may decline.

Fluctuations in the price of the Company’s Securities could contribute to the loss of all or part of your investment. Prior to the closing of the Business Combination, trading in our Class A Common Stock and Warrants had been limited. Even if an active market for the Securities develops and continues, the trading price of the Securities could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of the factors listed below could have a material adverse effect on your investment and the Securities may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of the Securities may not recover and may experience a further decline.

Factors affecting the trading price of the Securities may include:

 

•

actual or anticipated fluctuations in our quarterly financial results or the quarterly financial results of companies perceived to be similar to us;

 

•

changes in the market’s expectations about our operating results;

 

•

success of competitors;

 

•

our operating results failing to meet the expectation of securities analysts or investors in a particular period;

 

•

changes in financial estimates and recommendations by securities analysts concerning us or its markets in general;

 

•

operating and stock price performance of other companies that investors deem comparable to us;

 

•

our ability to market new and enhanced products on a timely basis;

 

•

changes in laws and regulations affecting our business;

 

•

commencement of, or involvement in, litigation involving us;

 

•

changes in our capital structure, such as future issuances of securities or the incurrence of additional debt;

 

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•

the volume of securities available for public sale;

 

•

any major change in our board or management;

 

•

sales of substantial amounts of the Securities by our directors, executive officers or significant stockholders or the perception that such sales could occur; and

 

•

general economic and political conditions such as recession; interest rate, fuel price, and international currency fluctuations; and acts of war or terrorism.

Many of the factors listed above are beyond our control. In addition, broad market and industry factors may materially harm the market price of the Securities irrespective of our operating performance. The stock market in general, and NASDAQ have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of our Class A Common Stock and Warrants, which trade on The NASDAQ Capital Market, may not be predictable. A loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to us could depress the price of the Securities regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of the Securities also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.

If securities or industry analysts do not publish or cease publishing research or reports about us, our business, or our market, the price and trading volume of the Securities could decline.

The trading market for the Securities relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control these analysts. Furthermore, if one or more of the analysts who do cover us downgrade or provide negative outlook on our stock or our industry, or the stock of any of our competitors, or publish inaccurate or unfavorable research about our business, the price of the Securities could decline. If one or more of these analysts cease coverage of our business or fail to publish reports on us regularly, we could lose visibility in the market, which in turn could cause the price or trading volume of the Securities to decline.

Tema and our Sponsor own a significant percentage of our outstanding voting common stock.

Tema and our Sponsor beneficially own approximately 92% of our voting common stock and, upon the conversion of our Series A Preferred Stock, will beneficially own approximately 75% of our voting common stock. As long as Tema and our Sponsor own or control a significant percentage of outstanding voting power, they will have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our charter or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets.

The interests of Tema and our Sponsor may not align with the interests of our other stockholders. Tema and our Sponsor may acquire and hold interests in businesses that compete directly or indirectly with us. Tema and our Sponsor may also pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, our second amended and restated certificate of incorporation, amended and restated bylaws and the Shareholders’ and Registration Rights Agreement, dated as of December 20, 2016, by and among the Company, Tema, our Sponsor, Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P. (the “SHRRA”), provide that, subject to certain limitations, we renounce any interest or expectancy in the business opportunities of our officers and directors and their respective affiliates and each such party shall not have any obligation to offer us those opportunities unless presented to one of our directors or officers in his or her capacity as a director or officer.

 

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We are a holding company. Our sole material asset is our equity interest in Rosehill Operating and therefore we are accordingly dependent upon distributions from Rosehill Operating to pay taxes, make payments under the Tax Receivable Agreement and cover our corporate and other overhead expenses.

We are a holding company and have no material assets other than our equity interest in Rosehill Operating. We have no independent means of generating revenue. To the extent Rosehill Operating has available cash, we intend to cause Rosehill Operating to make (i) generally pro rata distributions to its unitholders, including us, in an amount at least sufficient to allow us to pay dividends with respect to the Series A Preferred Stock, our taxes and to make payments under the Tax Receivable Agreement with Tema and (ii) non-pro rata payments to us to reimburse us for our corporate and other overhead expenses. To the extent that we need funds and Rosehill Operating or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any financing arrangements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.

We are a “controlled company” within the meaning of the NASDAQ Listing Rules following the Transactions and, as a result, we qualify for, and rely on, exemptions from certain corporate governance requirements.

Tema and our Sponsor control a majority of the combined voting power of all classes of our outstanding voting stock. We are a controlled company within the meaning of the NASDAQ corporate governance standards. Under the NASDAQ rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NASDAQ corporate governance requirements, including the requirements that:

 

•

a majority of the board of directors consist of independent directors;

 

•

the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

 

•

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

These requirements do not apply to us as long as we remain a controlled company. We intend to continue utilizing some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NASDAQ.

The unaudited pro forma condensed consolidated financial information included in this document may not be indicative of what our actual financial position or results of operations would have been.

The unaudited pro forma condensed consolidated financial information in this prospectus is presented for illustrative purposes only and is not necessarily indicative of what our actual financial position or results of operations would have been had the Business Combination been completed on the dates indicated. See the section entitled “Unaudited Pro Forma Condensed Consolidated Financial Information” for more information.

Future sales of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of Class A Common Stock or securities convertible into Class A Common Stock in subsequent public or private offerings. On April 28, 2017, 5,856,579 shares of our Class A Common Stock were outstanding. Our outstanding shares of Class A Common Stock do not include shares of Class A Common Stock issuable upon conversion of the Class B Common Stock and Series A Preferred Stock and exercise of the warrants, which may be resold in the public market.

Downward pressure on the market price of our Class A Common Stock that likely will result from sales of our Class A Common Stock issued in connection with the exercise of warrants or the conversion of the Class B

 

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Common Stock or Series A Preferred Stock could encourage short sales of our Class A Common Stock by market participants. Generally, short selling means selling a security, contract or commodity not owned by the seller. The seller is committed to eventually purchase the financial instrument previously sold. Short sales are used to capitalize on an expected decline in the security’s price. Such sales of our Class A Common Stock could have a tendency to depress the price of the stock, which could increase the potential for short sales.

We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

The Securities are equity interests and are therefore subordinated to our indebtedness.

In the event of our liquidation, dissolution or winding up, the Securities would rank below all secured debt claims against us. As a result, holders of the Securities will not be entitled to receive any payment or other distribution of assets upon our liquidation, dissolution or winding up until after all of our obligations to our secured debt holders have been satisfied.

None of the proceeds from the sale of the Securities by the selling securityholders will be available to fund our operations or to pay dividends.

We will not receive any proceeds from the sale of the Securities by the selling securityholders. The selling securityholders will receive all proceeds from the sale of such shares. Consequently, none of the proceeds from such sale will be available to fund our operations, capital expenditures or acquisition opportunities or to pay dividends. See “Use of Proceeds.”

There can be no assurance that our Class A Common Stock that may be issued upon the conversion of Series A Preferred Stock will be approved for listing on NASDAQ, or that we will be able to continue to comply with the continued listing standards of NASDAQ.

Our Class A Common Stock, units and warrants are currently listed on NASDAQ. If NASDAQ delists our Class A Common Stock from trading on its exchange for failure to meet the listing standards, including failure to meet minimum holder requirements we and our stockholders could face significant material adverse consequences including:

 

•

a limited availability of market quotations for our securities;

 

•

reduced liquidity for our securities;

 

•

a determination that our Class A Common Stock is a “penny stock” which will require brokers trading in our Class A Common Stock to adhere to more stringent rules, possibly resulting in a reduced level of trading activity in the secondary trading market for our securities;

 

•

a limited amount of analyst coverage; and

 

•

a decreased ability to issue additional securities or obtain additional financing in the future.

Some of our total outstanding shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our Class A Common Stock to drop significantly, even if our business is doing well.

Our Sponsor and Tema hold approximately 92% of our issued and outstanding shares of Class A Common Stock, including Class A Common Stock issuable upon exchange of Class B Common Stock. While the SHRRA restricts, except in certain circumstances, our Sponsor and Tema from transferring any of their common stock

 

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until one year following the date of the consummation of the Business Combination, these shares may be sold after the expiration of the lock-up period. As restrictions on resale end, the market price of our Class A Common Stock could decline if the holders of currently restricted shares sell them or are perceived by the market as intending to sell them. Additionally, the Tax Receivable Agreement grants Tema the right to prevent certain dispositions of the assets we acquired in the Business Combination for a period of up to three years following the closing of the Business Combination.

Additionally, in connection with the Business Combination, we issued a total of 95,000 shares of Series A Preferred Stock (convertible into Class A common stock) and 9,000,000 warrants (exercisable for Class A Common Stock). To the extent the Class A Common Stock that is issuable upon conversion or exercise of these securities is sold, the market price of our Class A Common Stock could decline.

Anti-takeover provisions contained in our amended and restated charter, as well as provisions of Delaware law, could impair a takeover attempt.

Our amended and restated certificate of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that stockholders may consider to be in their best interests. We are also subject to anti-takeover provisions under Delaware law, which could delay or prevent a change of control. Together these provisions may make more difficult the removal of management and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our securities. These provisions include:

 

•

a staggered board providing for three classes of directors, which limits the ability of a stockholder or group to gain control of our board;

 

•

no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;

 

•

the right of our board of directors to elect a director to fill a vacancy created by the expansion of the board of directors or the resignation, death, or removal of a director in certain circumstances, which prevents stockholders from being able to fill vacancies on our board of directors;

 

•

the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;

 

•

the ability of each of Tema or our Sponsor to call a special meeting of stockholders, provided that such person owns 15% or more of the outstanding shares of common stock until the Trigger Date, and thereafter prohibit such ability;

 

•

a prohibition on stockholders calling a special meeting upon and following the Trigger Date, which forces stockholder action to be taken at an annual or special meeting of our stockholders called by the Board;

 

•

the requirement that a meeting of stockholders may be called only by the board of directors after the Trigger Date, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;

 

•

providing that after the Trigger Date directors may be removed prior to the expiration of their terms by stockholders only for cause or upon the affirmative vote of 75% of the voting power of all outstanding shares of the combined company;

 

•

a requirement that changes or amendments to the certificate of incorporation or the bylaws must be approved (i) before the Trigger Date, by a majority of the voting power of outstanding common stock of the combined company, which such majority shall include at least 80% of the shares then held by our Sponsor and Tema, and (ii) thereafter, certain changes or amendments must be approved by at least 75% of the voting power of outstanding common stock of the combined company; and

 

•

advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders’ meeting, which may discourage or

 

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deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to obtain control of the Company.

Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect our business, investments and results of operations.

We are subject to laws, regulations and rules enacted by national, regional and local governments and NASDAQ. In particular, we are required to comply with certain SEC, NASDAQ and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on our business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.

The Series A Preferred Stock ranks junior to all of our indebtedness and other liabilities.

In the event of our bankruptcy, liquidation, reorganization or other winding-up, our assets will be available to pay obligations on the Series A Preferred Stock only after all of our indebtedness and other liabilities have been paid. In addition, we are a holding company and the Series A Preferred Stock will effectively rank junior to all existing and future indebtedness and other liabilities (including trade payables) of our subsidiaries and any capital stock of our subsidiaries not held by us. The rights of holders of the Series A Preferred Stock to participate in the distribution of assets of our subsidiaries will rank junior to the prior claims of that subsidiary’s creditors and any other equity holders. Consequently, if we are forced to liquidate our assets to pay our creditors, we may not have sufficient assets remaining to pay amounts due on any or all of the Series A Preferred Stock then outstanding. We and our subsidiaries may incur substantial amounts of additional debt and other obligations that will rank senior to the Series A Preferred Stock.

We are not obligated to pay dividends on the Series A Preferred Stock if prohibited by law and will not be able to pay cash dividends if we have insufficient cash to do so.

Under Delaware law, dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay dividends on the Series A Preferred Stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of our net assets (total assets less total liabilities) over our capital.

Further, even if adequate surplus is available to pay dividends on the Series A Preferred Stock, we may not have sufficient cash to pay cash dividends on the Series A Preferred Stock. We may elect to pay dividends on the Series A Preferred Stock in shares of additional Series A Preferred Stock; however, our ability to pay dividends in shares of our Series A Preferred Stock may be limited by the number of shares of Series A Preferred Stock we are authorized to issue under our second amended and restated certificate of incorporation (the “certificate of incorporation”). As of April 27, 2017, we had issued 95,000 shares of our Series A Preferred Stock out of 1,000,000 authorized shares of preferred stock of which 150,000 were designated as Series A Preferred Stock.

The terms of our financing agreements may limit our ability to pay dividends on the Series A Preferred Stock.

Financing agreements, whether ours or those of our subsidiaries and whether in place now or in the future, may contain restrictions on our ability to pay cash dividends on our capital stock, including the Series A Preferred Stock. These limitations may cause us to be unable to pay cash dividends on the Series A Preferred Stock. For example, the Credit Agreement will restrict our ability to pay cash dividends unless certain criteria are met. Since we are not obligated to declare or pay cash dividends, we do not intend to do so to the extent we are restricted by any of our financing agreements.

 

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The Series A Preferred Stock is a recent issuance that does not have an established trading market, which may negatively affect its market value and the ability to transfer or sell such shares.

The shares of Series A Preferred Stock is a recent issue of securities with no established trading market. Since the Series A Preferred Stock has no stated maturity date, investors seeking liquidity will be limited to selling their shares in the secondary market or converting their shares and selling in the secondary market. We do not intend to list the Series A Preferred Stock on any securities exchange. We cannot assure you that an active trading market in the Series A Preferred Stock will develop or, even if it develops, we cannot assure you that it will last. In either case, the trading price of the Series A Preferred Stock could be adversely affected and your ability to transfer your shares of Series A Preferred Stock will be limited. We are not aware of any entity making a market in the shares of our Series A Preferred Stock which we anticipate may further limit liquidity.

Upon conversion of the Series A Preferred Stock, holders may receive less valuable consideration than expected because the value of our Class A Common Stock may decline after such holders exercise their conversion right but before we settle our conversion obligation.

Under the Series A Preferred Stock, a converting holder will be exposed to fluctuations in the value of our Class A Common Stock during the period from the date such holder surrenders shares of Series A Preferred Stock for conversion until the date we settle our conversion obligation. Upon conversion, we will be required to deliver the shares of our Class A Common Stock, together with a cash payment for any fractional share, on the third business day following the relevant conversion date. Accordingly, if the price of our Class A Common Stock decreases during this period, the value of the shares of Class A Common Stock that you receive will be adversely affected and would be less than the conversion value of the Series A Preferred Stock on the conversion date.

The conversion rate of the Series A Preferred Stock may not be adjusted for all dilutive events.

The number of shares of our Class A Common Stock that you are entitled to receive upon conversion of the Series A Preferred Stock is subject to adjustment for certain specified events, including, but not limited to, the issuance of certain stock dividends on our Class A Common Stock, the issuance of certain rights or warrants, subdivisions, combinations, distributions of capital stock, indebtedness, or assets, cash dividends and certain issuer tender or exchange offers, as set forth in the Certificate of Designations. However, the conversion rate may not be adjusted for other events, such as the exercise of stock options held by our employees or offerings of our Class A Common Stock or securities convertible into Class A Common Stock (other than those set forth in the Certificate of Designations) for cash or in connection with acquisitions, which may adversely affect the market price of our Class A Common Stock. Further, if any of these other events adversely affects the market price of our Class A Common Stock, we expect it to also adversely affect the market price of our Series A Preferred Stock. In addition, the terms of our Series A Preferred Stock do not restrict our ability to offer Class A Common Stock or securities convertible into Class A Common Stock in the future or to engage in other transactions that could dilute our Class A Common Stock. We have no obligation to consider the interests of the holders of our Series A Preferred Stock in engaging in any such offering or transaction. If we issue additional shares of Class A Common Stock, those issuances may materially and adversely affect the market price of our Class A Common Stock and, in turn, those issuances may adversely affect the trading price of the Series A Preferred Stock.

The additional shares of our Class A Common Stock deliverable for shares of Series A Preferred Stock converted in connection with a fundamental change may not adequately compensate holders of our Series A Preferred Stock.

If a “fundamental change” (as defined in the Certificate of Designations) occurs, we will under certain circumstances increase the conversion rate by a number of additional shares of our Class A Common Stock for shares of Series A Preferred Stock converted in connection with such fundamental change as described in the Certificate of Designations. While this feature is designed to, among other things, compensate you for lost option

 

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time value of your shares of Series A Preferred Stock as a result of the fundamental change, it may not adequately compensate you for your loss as a result of such transaction.

In addition, you will have no additional rights upon a fundamental change, and will have no right not to convert the Series A Preferred Stock into shares of our Class A Common Stock. Any shares of Class A Common Stock you receive upon a fundamental change may be worth less than the liquidation preference per share of Series A Preferred Stock.

Our obligation to satisfy the additional shares requirement could be considered a penalty, in which case the enforceability thereof would be subject to general principles of reasonableness and equitable remedies.

In some limited circumstances, we may not have reserved a sufficient number of shares of our Class A Common Stock to issue the full amount of shares of Class A Common Stock issuable upon conversion following a fundamental change.

Some significant restructuring transactions may not constitute a fundamental change but may nevertheless result in holders of the Series A Preferred Stock being adversely affected.

Upon the occurrence of a “fundamental change” (as defined in the Certificate of Designations), there may be an increase in the conversion rate as described in the Certificate of Designations. However, these provisions will not afford protection to holders of Series A Preferred Stock in the event of other transactions that could adversely affect the value of the Series A Preferred Stock. For example, transactions such as leveraged recapitalizations, refinancings, restructurings, or acquisitions initiated by us may not constitute a fundamental change. In the event of any such transaction, holders would not have the protection afforded by the provisions applicable to a fundamental change even though each of these transactions could increase the amount of our indebtedness, or otherwise adversely affect our capital structure or any credit ratings, thereby adversely affecting the holders of Series A Preferred Stock.

Upon a conversion in connection with a fundamental change, holders of our Series A Preferred Stock may receive consideration worth less than the $1,000 liquidation preference per share of Series A Preferred Stock, plus any accumulated and unpaid dividends thereon.

If a “fundamental change” (as defined in the Certificate of Designations) occurs, and regardless of the price paid (or deemed paid) per share of our Class A Common Stock in such fundamental change, then the conversion rate may be adjusted to increase the number of the shares of our Class A Common Stock deliverable upon conversion of each share of Series A Preferred Stock to the $1,000 liquidation preference per share of Series A Preferred Stock, plus any accumulated and unpaid dividends thereon. However, under certain circumstances, holders may receive a number of shares of Class A Common Stock worth less than the $1,000 liquidation preference per share of Series A Preferred Stock, plus any accumulated and unpaid dividends thereon. You will have no claim against us for the difference between the value of the consideration you receive upon a conversion in connection with a fundamental change and the $1,000 liquidation preference per share of Series A Preferred Stock, plus any accumulated and unpaid dividends thereon.

We may issue additional series of preferred stock that rank equally to the Series A Preferred Stock as to dividend payments and liquidation preference.

Neither our certificate of incorporation nor the Certificate of Designations for the Series A Preferred Stock prohibits us from issuing additional series of preferred stock that would rank equally to the Series A Preferred Stock as to dividend payments and liquidation preference. Our certificate of incorporation and the Certificate of Designations provide that we have the authority to issue up to 1,000,000 shares of preferred stock, including up to 150,000 shares of Series A Preferred Stock. The issuances of other series of preferred stock could have the effect of reducing the amounts available to the Series A Preferred Stock in the event of our liquidation, winding-up or dissolution. It may also reduce cash dividend payments on the Series A Preferred Stock if we do not have

 

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sufficient funds to pay dividends on all Series A Preferred Stock outstanding and outstanding parity preferred stock.

Holders of our Series A Preferred Stock will have no rights with respect to the shares of our Class A Common Stock underlying the Series A Preferred Stock until you convert your Series A Preferred Stock, but you may be adversely affected by certain changes made with respect to our Class A Common Stock.

You will have no rights with respect to the shares of our Class A Common Stock underlying your Series A Preferred Stock, including voting rights, rights to respond to Class A Common Stock tender offers, if any, and rights to receive dividends or other distributions on our Class A Common Stock, if any (in each case, other than through a conversion rate adjustment), prior to the conversion date with respect to a conversion of your Series A Preferred Stock, but your investment in our Series A Preferred Stock may be negatively affected by these events. Upon conversion, you will be entitled to exercise the rights of a holder of Class A Common Stock only as to matters for which the relevant record date occurs on or after the conversion date. For example, in the event that an amendment is proposed to our certificate of incorporation or bylaws requiring stockholder approval and the record date for determining the stockholders of record entitled to vote on the amendment occurs prior to the conversion date, you will not be entitled to vote on the amendment, although you will nevertheless be subject to any changes in the powers, preferences or special rights of our Class A Common Stock.

Holders of our Series A Preferred Stock will have no voting rights except under limited circumstances.

Except with respect to certain material and adverse changes to the Series A Preferred Stock as described in the Certificate of Designations, you do not have voting rights and will have no right to vote for any members of our board of directors, except as may be required by Delaware law.

Future issuances of preferred stock may adversely affect the market price for our Class A Common Stock.

Additional issuances and sales of preferred stock, or the perception that such issuances and sales could occur, may cause prevailing market prices for our Class A Common Stock to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

The increased conversion rate triggered by a fundamental change could discourage a potential acquiror.

The increased conversion rate triggered by a “fundamental change” (as defined in the Certificate of Designations) could discourage a potential acquiror, including potential acquirors that otherwise seek a transaction with us that would be attractive to you.

We may not have sufficient earnings and profits in order for distributions on the Series A Preferred Stock to be treated as dividends for U.S. federal income tax purposes.

Distributions payable by us on the Series A Preferred Stock may exceed our current and accumulated earnings and profits, as calculated for U.S. federal income tax purposes. To the extent that the amount of a distribution with respect to our Series A Preferred Stock exceeds our current and accumulated earnings and profits, such distribution will be treated for U.S. federal income tax purposes as a return of capital and first be applied against and reduce the beneficial owner’s adjusted tax basis in the Series A Preferred Stock, but not below zero. Any excess over such adjusted tax basis will be treated as capital gain. Such treatment will generally be unfavorable for corporate beneficial owners and may also be unfavorable to certain other beneficial owners.

Holders of our Series A Preferred Stock may be subject to tax if we make or fail to make certain adjustments to the conversion rate of the Series A Preferred Stock even though you do not receive a corresponding cash distribution.

The conversion rate of the Series A Preferred Stock is subject to adjustment in certain circumstances, including the payment of cash dividends. If the conversion rate is adjusted as a result of a distribution that is

 

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taxable to our common stockholders, such as a cash dividend, you may be deemed to have received a dividend subject to U.S. federal income tax without the receipt of any cash. In addition, a failure to adjust (or to adjust adequately) the conversion rate after an event that increases your proportionate interest in us could be treated as a deemed taxable dividend to you. If a “fundamental change” (as defined in the Certificate of Designations) occurs, under some circumstances, we will increase the conversion rate for shares of Series A Preferred Stock converted in connection with such fundamental change. If you are a non-U.S. holder (as defined in “Material U.S. Federal Income Tax Considerations”), any deemed dividend may be subject to U.S. federal withholding tax at a 30% rate, or such lower rate as may be specified by an applicable treaty, which may be set off against subsequent payments on the Series A Preferred Stock.

If you are a non-U.S. holder, dividends on our Series A Preferred Stock that are paid in shares may be subject to U.S. federal withholding tax in the same manner as a cash dividend, which the withholding agent might satisfy through a sale of a portion of the shares you receive as a dividend or through withholding of other amounts payable to you.

We may elect to pay dividends on our Series A Preferred Stock in shares of Series A Preferred Stock rather than in cash. Any such stock dividends paid to you will be taxable in the same manner as cash dividends and, if you are a non-U.S. holder (as defined in “Material U.S. Federal Income Tax Considerations”), may be subject to U.S. federal withholding tax (at a 30% rate, or lower treaty rate, if applicable). Any required withholding tax might be satisfied by the withholding agent through a sale of a portion of the shares you receive as a dividend or might be withheld from cash dividends or sales proceeds subsequently paid or credited to you.

Non-U.S. holders of our Series A Preferred Stock or our Class A Common Stock received in respect thereof could, in certain situations, be subject to U.S. federal income tax upon a sale, exchange, conversion or other disposition of such stock.

We believe that we are a “United States real property holding corporation” and likely will remain one in the foreseeable future. As a result, non-U.S. holders (as defined in “Material U.S. Federal Income Tax Considerations”) that own (or are treated as owning under constructive ownership rules) more than a specified amount of our Series A Preferred Stock or our Class A Common Stock received in respect thereof during a specified time period may be subject to U.S. federal income tax on a sale, exchange, conversion or other disposition of such stock and may be required to file a U.S. federal income tax return.

We may be required to make payments under the Tax Receivable Agreement for certain tax benefits that we may claim, and the amounts of such payments could be significant.

In connection with the closing of the Business Combination, we entered into a Tax Receivable Agreement with Tema. This agreement generally provides for the payment by the Company to Tema of 90% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax that the Company actually realizes or is deemed to realize in certain circumstances as a result of certain increases in the tax basis in the assets of Rosehill Operating and certain benefits attributable to imputed interest. The Company will retain the benefit of the remaining 10% of these cash savings.

The term of the Tax Receivable Agreement will continue until all tax benefits that are subject to the Tax Receivable Agreement have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control (or the Tax Receivable Agreement is terminated early due to our breach of a material obligation thereunder), and we make the termination payment specified in the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return.

The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of Rosehill Operating, and we expect that the payments we will be required to make under the Tax Receivable

 

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Agreement will be substantial. Estimating the amount and timing of payments that may become due under the Tax Receivable Agreement is by its nature imprecise. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability (determined by using the actual applicable U.S. federal income tax rate and an assumed combined state and local income tax rate) to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, will vary depending upon a number of factors, including whether a gain is recognized by Tema with respect to the distribution to Tema of the Cash Consideration, shares of Class B Common Stock and Tema warrants and the assumption of the Tema Liabilities in connection with the Business Combination, the timing of redemptions by Rosehill Operating or the exchange by the Company, as applicable, of Rosehill Operating Common Units, the price of our Class A Common Stock at the time of each redemption or exchange, the extent to which such redemptions or exchanges are taxable transactions, the amount and timing of the taxable income we generate in the future, the U.S. federal income tax rates then applicable, and the portion of our payments under the Tax Receivable Agreement that constitute imputed interest or give rise to depreciable or amortizable tax basis. The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in us.

In certain cases, payments under the Tax Receivable Agreement may be accelerated and/or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

If we elect to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control or it is terminated early due our breach of a material obligation thereunder, our obligations under the Tax Receivable Agreement would accelerate and we would be required to make an immediate payment equal to the present value of the anticipated future payments to be made by us under the Tax Receivable Agreement (determined by applying a discount rate of one-year LIBOR plus 150 basis points ). The calculation of anticipated future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including (i) the assumption that we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement and (ii) the assumption that any units (other than those held by us) outstanding on the termination date are deemed to be exchanged on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of the future tax benefits to which the termination payment relates.

As a result of an early termination, we could be required to make payments under the Tax Receivable Agreement that exceed our actual cash tax savings under the Tax Receivable Agreement. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. For example, if the Tax Receivable Agreement were terminated immediately after the closing of the Business Combination, the estimated termination payments would, in the aggregate, be approximately $88.9 million (calculated using a discount rate equal to one-year LIBOR plus 150 basis points, applied against an undiscounted liability of $111.1 million). The foregoing number is merely an estimate and the actual payment could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. Tema will not reimburse us for any payments previously made under the Tax Receivable Agreement if any tax benefits that have given rise to payments under the Tax Receivable Agreement are subsequently disallowed, except that excess payments made to Tema will be netted against payments that would otherwise be made to Tema, if any, after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

 

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

We make forward-looking statements in this prospectus. These forward-looking statements relate to, among other things, expectations for future financial performance, business strategies and expectations for our business. Specifically, forward-looking statements may include statements relating to:

 

•

the benefits of the Business Combination;

 

•

the future financial performance of the company;

 

•

changes in Rosehill Operating’s reserves and future operating results;

 

•

expansion plans and opportunities; and

 

•

other statements preceded by, followed by or that include the words “estimate,” “plan,” “project,” “forecast,” “intend,” “expect,” “anticipate,” “believe,” “seek,” “target” or similar expressions.

These forward-looking statements are based on information available as of the date of this prospectus, and current expectations, forecasts and assumptions, and involve a number of judgments, risks and uncertainties. Accordingly, forward-looking statements should not be relied upon as representing our views as of any subsequent date, and we do not undertake any obligation to update forward-looking statements to reflect events or circumstances after the date they were made, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws.

You should not place undue reliance on these forward-looking statements in deciding whether to invest in the Securities. As a result of a number of known and unknown risks and uncertainties, our actual results or performance may be materially different from those expressed or implied by these forward-looking statements. Some factors that could cause actual results to differ include:

 

•

declines in oil, natural gas, and NGL prices;

 

•

volatility in the commodity-future markets;

 

•

the occurrence of drilling failures, lower than expected production, and delays;

 

•

the inability to access capital to expand production;

 

•

the outcome of any legal proceedings that may be instituted against us or Tema in connection with the Business Combination and transactions contemplated thereby;

 

•

the risk that the Business Combination disrupts current plans and operations as a result of the announcement and consummation of the transactions described herein;

 

•

legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic- fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign laws and local environmental laws and regulations;

 

•

the possibility that we or Tema may be adversely affected by other economic, business, and/or competitive factors; and

 

•

the creditworthiness of our financial counterparties and operation partners;

 

•

other risks and uncertainties indicated in this prospectus, including those set forth under the section entitled “Risk Factors.”

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

 

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All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

 

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USE OF PROCEEDS

We will not receive any proceeds from the sale of Series A Preferred Stock by the selling securityholders named herein.

The selling securityholders will bear all commissions and discounts and transfer taxes, if any, attributable to their sale of the Securities. We will bear all costs, expenses and fees in connection with the registration of the shares of the Securities, including with regard to compliance with state securities or “blue sky” laws.

 

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DETERMINATION OF OFFERING PRICE

There is currently no established market for our Series A Preferred Stock. The actual offering price by the selling securityholders of the Securities covered by this prospectus will be determined by prevailing market prices at the time of sale, by private transactions negotiated by the selling securityholders or as otherwise described in the section entitled “Plan of Distribution.”

 

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PRICE RANGE OF SECURITIES AND DIVIDENDS

Our units, each of which consists of one share of our Class A Common Stock, par value $0.0001 per share, and one Warrant to purchase one share of our Class A Common Stock at $11.50 per share, began trading on The NASDAQ Capital Market under the symbol “KLREU” on March 11, 2016. On March 28, 2016, we announced that holders of our units could elect to separately trade the shares of Class A Common Stock and the Warrants included in the units. Those units not separated continue to trade on The NASDAQ Capital Market under the symbol “ROSEU,” and each of the shares of our Class A Common Stock and Warrants trade separately on The NASDAQ Capital Market under the symbols “ROSE” and “ROSEW,” respectively. Through April 27, 2017, our Class A Common Stock, units and Warrants were listed on The NASDAQ Capital Market under the symbols “KLRE,” “KLREU” and “KLREW,” respectively. Warrants may be exercised only for a whole number of shares of Class A Common Stock. No fractional shares will be issued upon exercise of the Warrants. If, upon exercise of the Warrants, a holder would be entitled to receive a fractional interest in a share, we will, upon exercise, round down to the nearest whole number the number of shares of Class A Common Stock to be issued to the Warrant holder.

The following table sets forth, for the calendar quarter indicated, the high and low sales prices per unit, Class A Common Stock and warrants as reported on NASDAQ for the periods presented.

 

		Units (ROSEU)								Class A Common Stock (ROSE)								Warrants (ROSEW)
		High				Low				High				Low				High				Low
Fiscal 2016:
Quarter ended 3/31/2016(1)		$	10.10			$	9.96			$	9.95			$	9.95			$	0.30			$	0.17
Quarter ended 6/30/2016		$	10.32			$	9.99			$	10.15			$	9.90			$	0.25			$	0.14
Quarter ended 9/30/2016		$	10.50			$	10.10			$	10.15			$	9.91			$	0.59			$	0.17
Quarter ended 12/31/2016		$	12.55			$	10.41			$	10.50			$	10.10			$	1.75			$	0.36
Fiscal 2017:
Quarter ended 3/31/2017		$	13.20			$	11.35			$	10.65			$	10.20			$	1.75			$	1.15
Quarter ended 6/30/2017(2)		$	12.75			$	11.46			$	11.69			$	9.98			$	2.00			$	1.11

 

(1)	Beginning on March 11, 2016 with respect to ROSEU and March 31, 2016 with respect to ROSE and ROSEW.

(2)	Through April 28, 2017.

On May 3, 2017, the closing prices of our Units, Class A Common Stock and Warrants were $10.98, $10.06 and $1.57, respectively. As of May 3, 2017, we had 5,856,579 shares of Class A Common Stock and 25,594,158 Warrants issued and outstanding.

Dividend Policy

We have not paid any cash dividends on our common stock to date. The payment of cash dividends in the future will be dependent upon our revenues and earnings, if any, capital requirements and general financial condition. The payment of any future cash dividends will be within the discretion of our board of directors at such time.

 

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RATIO OF EARNINGS TO FIXED CHARGES AND TO FIXED CHARGES AND

PREFERENCE DIVIDENDS

The following table shows our unaudited ratios of earnings to (a) fixed charges and (b) fixed charges and preference dividends for the periods presented:

 

		Year Ended December 31,
		2016				2015				2014
Ratio of earnings to fixed charges(1)			—				—				—
Ratio of earnings to fixed charges and preference dividends(1)			—				—				—

 

(1)

Due to Rosehill Operating’s loss before income taxes for the year ended December 31, 2016, 2015 and 2014, the ratio coverage was less than 1:1. To achieve ratio coverage of 1:1, the Company would have needed additional earnings of approximately $15.0 million, $14.7 million and $19.3 million for the year ended December 31, 2016, 2015 and 2014, respectively.

For purposes of calculating the ratios of consolidated earnings to fixed charges and to fixed charges and preference dividends:

 

•

“earnings” consist of income (loss) before income taxes and equity income (loss) of investees, plus fixed charges and distributed income of equity investees;

 

•

“fixed charges” represent interest expensed and capitalized, and amortization of deferred financing costs and accretion of debt discount; and

 

•

“preference dividends” refers to the amount of pre-tax earnings that is required to pay the cash dividends on outstanding preference securities and is computed as the amount of (a) the dividend divided by (b) the result of 1 minus the effective income tax rate applicable to continuing operations.

The ratios of earnings to fixed charges and to fixed charges and preference dividends are ratios that we are required to present in this prospectus and have been calculated in accordance with Commission rules and regulations. These ratios have no application to our credit and lease facilities and preferred shares and we believe they are not ratios used by investors to evaluate our overall operating performance.

 

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SELECTED HISTORICAL FINANCIAL INFORMATION OF THE COMPANY

We have no direct operations and no significant assets other than the ownership of an approximate 32% membership interest in Rosehill Operating. Rosehill Operating is considered our accounting predecessor. Unless the context otherwise requires, (i) prior to the completion of the Business Combination, references to “Rosehill Operating” refer to the assets, liabilities and operations of the business that were contributed to Rosehill Operating Company, LLC in connection with the Business Combination and (ii) following the completion of the Business Combination, references to “Rosehill Operating” refer to Rosehill Operating Company, LLC.

The following table shows selected historical financial information of Rosehill Operating for the periods and as of the dates indicated. The selected historical financial information of Rosehill Operating as of and for the years ended December 31, 2016, 2015 and 2014 was derived from the audited carve-out historical financial statements of the Assets and Liabilities of the Business to be Contributed to Rosehill Operating included elsewhere in this prospectus.

Rosehill Operating’s historical results are not necessarily indicative of future operating results. The selected consolidated and combined financial information should be read in conjunction with “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the historical financial statements of Rosehill Operating and accompanying notes included elsewhere in this prospectus.

 

		Year Ended December 31,
		2016				2015				2014
Statements of Operations Data (in thousands):
Revenues:
Oil sales		$	24,807			$	20,601			$	28,444
Natural gas sales			5,304				4,909				7,445
Natural gas liquids sales			4,534				3,977				7,674
Gain (loss) on commodity derivatives, net			(4,169	)			3,735				2,404
Total revenues			30,476				33,222				45,967
Operating expenses:
Lease operating expenses			4,800				4,582				6,103
Production taxes			1,541				1,311				1,861
Gathering and transportation expenses			2,398				2,094				2,462
Depreciation, depletion and amortization			24,789				23,244				15,842
Accretion expense			176				120				125
Impairment of oil and natural gas properties			—				8,131				27,595
Exploration costs			794				960				960
General and administrative expenses			9,000				4,234				5,151
Gain on sale of oil and natural gas properties			—				—				(6	)
(Gain) loss on sale of other assets			(50	)			18				(26	)
Total operating expenses			43,448				44,694				60,067
Total operating loss			(12,972	)			(11,472	)			(14,100	)
Other income (expense)
Interest expense, net			(1,822	)			(3,247	)			(5,469	)
Other income (expense), net			(247	)			7				316
Total other expense			(2,069	)			(3,240	)			(5,153	)
Loss before income taxes (1)			(15,041	)			(14,712	)			(19,253	)
Income tax expense			148				108				—
Net loss		$	(15,189	)		$	(14,820	)		$	(19,253	)
Cash Flow Data:
Net cash provided by operating activities		$	11,461			$	18,244			$	25,525
Net cash used in investing activities			(22,164	)			(16,993	)			(53,392	)
Net cash provided by (used in) financing activities			(8,597	)			17,519				23,457
Other Financial Data:
Adjusted EBITDAX (unaudited) (2)		$	15,041			$	20,783			$	27,388

 

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		As of December 31,
		2016				2015				2014
Balance Sheet Data (in thousands):
Cash and cash equivalents		$	8,434			$	27,734			$	8,964
Other current assets			7,909				5,962				8,828
Total current assets			16,343				33,696				17,792
Total property and equipment, net			123,373				122,873				137,848
Other long—term assets, net			110				334				251
Total assets		$	139,826			$	156,903			$	155,891
Current liabilities, other		$	14,361			$	9,165			$	11,549
Current portion, long term debt			—				20,000				—
Long term debt, net of current portion			55,000				45,000				75,000
Note payable, related party			—				—				10,000
Other long—term liabilities			5,245				3,761				3,164
Total liabilities			74,606				77,926				99,713
Parent net investment			65,220				78,977				56,178
Total liabilities and parent net investment		$	139,826			$	156,903			$	155,891

 

(1)	Rosehill Operating is treated as a partnership for U.S. federal income tax purposes and for purposes of certain state and local income taxes. Rosehill Operating is subject to the Texas margins tax at a rate of 0.75%.

(2)	Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income, see “Non-GAAP Financial Measure” below.

Non-GAAP Financial Measure

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by Rosehill Operating’s management and external users of its financial statements, such as industry analysts, investors, lenders and rating agencies. Rosehill Operating defines Adjusted EBITDAX as net income (loss) before interest expense, income taxes, DD&A, accretion and impairment of oil and natural gas properties, (gains) losses on commodity derivatives excluding net cash receipts (payments) on settled commodity derivatives, gains and losses from the sale of assets and other non-cash operating items. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles (“U.S. GAAP”).

Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate the operating performance of Rosehill Operating and compare the results of its operations from period to period and against its peers without regard to Rosehill Operating financing methods or capital structure. Rosehill Operating excludes the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within Rosehill Operating’s industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with U.S. GAAP or as an indicator of Rosehill Operating’s operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Rosehill Operating’s presentation of Adjusted EBITDAX should not be construed as an inference that its results will be unaffected by unusual or non-recurring items. Rosehill Operating’s computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.

 

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The following table presents a reconciliation of Adjusted EBITDAX to net income, Rosehill Operating’s most directly comparable financial measure calculated and presented in accordance with U.S. GAAP.

 

		Year Ended December 31,
		2016				2015				2014
						(Unaudited)
Reconciliation of net (loss) income to Adjusted EBITDAX (in thousands):
Net loss		$	(15,189	)		$	(14,820	)		$	(19,253	)
Interest expense, net			1,822				3,247				5,469
Income tax expense			148				108				—
Depreciation, depletion and amortization			24,789				23,244				15,842
Accretion expense			176				120				125
Impairment of oil and natural gas properties			—				8,131				27,595
Loss (gain) on commodity derivatives, net			4,169				(3,735	)			(2,404	)
Net cash received (paid) in settlement of commodity derivatives			(824	)			4,470				46
Gain on sale of oil and natural gas properties			—				—				(6	)
Loss (gain) on sale of other assets			(50	)			18				(26	)
Adjusted EBITDAX		$	15,041			$	20,783			$	27,388

 

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UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION

On April 27, 2017, KLR Energy Acquisition Corp. (“KLRE” or the “Company”) and Tema Oil and Gas Company (“Tema”) consummated the previously announced business combination (the “Business Combination”) pursuant to the Business Combination Agreement (the “Business Combination Agreement”) for the acquisition of membership interests in Rosehill Operating Company LLC (“Rosehill Operating”), a newly formed company. Pursuant to the terms of the Business Combination Agreement, KLRE (as Managing Member) controls Rosehill Operating. Rosehill Operating is a newly formed entity that was created to receive and operate oil and gas properties contributed by Tema.

In connection with the completion of the Business Combination, KLRE acquired a portion of the equity of Rosehill Operating, a wholly-owned subsidiary of Tema, through (i) the contribution to Rosehill Operating by KLRE of $35.0 million in cash (the “Cash Consideration”) and the issuance to Rosehill Operating by KLRE of 29,807,692 shares of newly created Class B common stock (which cash and shares of Class B common stock were immediately distributed by Rosehill Operating to Tema) (subject to certain adjustments as set out in the Business Combination Agreement), (ii) the assumption by Rosehill Operating of $55.0 million in Tema indebtedness and (iii) the contribution to Rosehill Operating by KLRE of the remaining cash proceeds of KLRE’s initial public offering. Immediately following the Business Combination, Tema owned approximately 83.6% of the equity of Rosehill Operating (without giving effect to the conversion of any shares of Series A Preferred Stock).

In connection with the closing of the Business Combination, (i) KLRE issued to Rosehill Operating 4,000,000 warrants exercisable for shares of Class A common stock (the “Tema warrants”) in exchange for 4,000,000 warrants exercisable for Rosehill Operating Common Units (such class of warrants, the “Rosehill warrants”). The Tema warrants and Cash Consideration were immediately distributed to Tema. In addition, KLRE contributed proceeds from its issuance of 75,000 shares of 8.0% Series A Cumulative Perpetual Preferred Stock (the “Series A Preferred Stock”) and 5,000,000 warrants (the “PIPE Warrants”), exercisable for shares of Class A common stock, for net proceeds of $70.9 million (collectively, the “PIPE Investment”) to Rosehill Operating in exchange for Rosehill Operating Series A Preferred Units (the “Series A Preferred Units”) and additional Rosehill warrants. In addition, our Sponsor agreed to transfer (i) 476,540 shares of Class A common stock to certain investors in the PIPE Investment and 37,212 shares of Class A common stock to a stockholder in exchange for its commitment not to redeem shares of Class A common stock (in each case, in lieu of the transfer by KLR Sponsor of such shares to KLRE for cancellation and the reissuance of such shares to such investors) and (ii) 750,000 warrants to purchase Class A common stock of KLRE to Rosemore Inc. (“Rosemore”), Tema’s parent (in lieu of the transfer by our Sponsor of such warrants to KLRE for cancellation and the reissuance of such warrants to Rosemore). Conversion of the Series A Preferred Stock into shares of KLRE Class A common stock will result in a reduction in Tema’s ownership in KLRE to approximately 67.9% and will cause the Series A Preferred Units also to convert into common units of Rosehill Operating. After giving effect to the conversion of the Series A Preferred Units into Common Units, KLRE will own approximately 32.1% of Rosehill Operating’s common equity and Tema will own the remaining 67.9%. The Business Combination has been unanimously approved by the board of directors of KLRE and the board of directors of Tema.

The Business Combination Agreement resulted in Tema obtaining control of KLRE through the 29,807,692 shares of Class B common stock, representing 83.6% of the voting interest in KLRE (without giving effect to the conversion of any shares of Series A Preferred Stock issued in the PIPE Investment or purchased pursuant to the Side Letter). KLRE will own a direct 100% voting interest in Rosehill Operating as a result of the Business Combination. The Business Combination will be accounted for as a reverse acquisition, pursuant to the guidance in ASC 805-10-55-12. Additionally, since Tema will control Rosehill Operating both before (directly) and after (indirectly, through its control of KLRE) closing the transaction, the consolidation of Rosehill Operating by KLRE results in an initial measurement of the Rosehill Operating assets and liabilities transferred to KLRE equal to the historical carrying amounts of those assets and liabilities on the accounts of Tema on the transfer date. The pro forma adjustments have been prepared as if the Business Combination had taken place on December 31,

 

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2016 in the case of the unaudited pro forma condensed consolidated balance sheet and on January 1, 2016 in the case of the unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2016.

Under KLRE’s amended and restated certificate of incorporation, existing public stockholders have the right to redeem, upon the closing of a business combination, shares of Class A common stock then held by them for cash equal to their pro rata share of the aggregate amount of the deposit in the Trust Account. Based on the fair value of the marketable securities held in the Trust Account as of the closing date of $85.3 million, the per share redemption price is $10.44. Rosemore and our Sponsor backstopped redemptions by the public stockholders of KLRE once 30% of the outstanding shares of Class A common stock were redeemed by purchasing 20,000 shares of Series A Preferred Stock for $20.0 million pursuant to a side letter entered into between Rosemore, our Sponsor and KLRE (the “Side Letter”).

The following unaudited pro forma condensed consolidated financial information reflects the combination of the historical results of both KLRE and Rosehill Operating on a pro forma basis to give effect to the following transactions, which are described in further detail below as if they had occurred on December 31, 2016 for pro forma condensed consolidated balance sheet purposes and on January 1, 2016 for pro forma condensed consolidated statements of operations purposes:

 

•

Pro Forma Adjustments. Although KLRE (the public company) is the legal acquirer, Tema will control KLRE and Rosehill Operating following the Business Combination. Accordingly, the assets and liabilities of Rosehill Operating will be recorded at the historical values recorded by Tema. The Pro Forma Adjustments reflect the following transactions necessary to execute the Business Combination Agreement:

 

•

the contribution of a portion of its assets by Tema to Rosehill Operating in exchange for 100% of the issued and outstanding common units of Rosehill Operating;

 

•

the acquisition by KLRE of approximately 16.4% of the outstanding common membership units in Rosehill Operating from Tema, in exchange for (i) the contribution to Rosehill Operating by KLRE of the Cash Consideration and 29,807,692 shares of newly created Class B common stock (which cash and Class B common stock will immediately be distributed by Rosehill Operating to Tema), (ii) the assumption by Rosehill Operating of $55.0 million in indebtedness and (iii) the contribution to Rosehill Operating by KLRE of the remaining cash proceeds of KLRE’s initial public offering;

 

•

the issuance of the 4,000,000 Warrants to Rosehill Operating in exchange for Warrants to acquire Rosehill common units, who will then distribute such warrants to Tema;

 

•

the transfer, in lieu of cancellation and reissuance by our Sponsor of 750,000 warrants to purchase Class A common stock of KLRE to Rosemore pursuant to the Side Letter;

 

•

the conversion of 2,046,330 shares of Class F common stock (the “Founder Shares”) into 4,250,000, shares of Class A common stock prior to redemptions. After redemptions, the conversion of the Founder Shares into 3,475,663 shares of Class A common stock;

 

•

the issuance by KLRE of 75,000 shares of Series A Preferred Stock and the PIPE Warrants, for net proceeds of $70.9 million ($75.0 million gross proceeds, net of $4.1 million in equity issuance costs) which KLRE will contribute to Rosehill Operating in exchange for Series A Preferred Units and additional Rosehill warrants as well as the transfer, in lieu of cancellation and reissuance of 476,540 shares of KLRE Class A common stock from our Sponsor to certain investors in the PIPE Investment;

 

•

the redemption of 5,804,404 shares of Class A Common Stock held by public stockholders in connection with the Business Combination as allowed pursuant to KLRE’s amended and restated certificate of incorporation (see Redemption Adjustments below); and

 

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•

the effect of a Tax Receivable Agreement with Tema, which will provide for the payment by KLRE to Tema of 90% of the net cash savings, if any, in U.S. federal, state and local income tax that KLRE actually realizes (or is deemed to realize in certain circumstances) in periods after the closing of the Business Combination as a result of (i) any tax basis increases in the assets of Rosehill Operating resulting from the distribution to Tema of the Cash Consideration, the shares of Class B common stock and the Tema Warrants and the assumption of the Tema Liabilities in connection with the Business Combination, (ii) the tax basis increases in the assets of Rosehill Operating resulting from the redemption by Rosehill Operating or the exchange by KLRE, as applicable, of Rosehill Operating Common Units for Class A common stock or cash, as applicable, and (iii) imputed interest deemed to be paid by KLRE as a result of, and additional tax basis arising from, payments it makes under the Tax Receivable Agreement. An increase in the tax basis of assets contributed to Rosehill Operating would occur at the closing of the Business Combination if Tema were to recognize any taxable gain at that time as a result of the distribution (or deemed distribution for U.S. federal income tax purposes) to it of cash, shares of class B common stock and Tema warrants. Based on preliminary calculations prepared by Tema, no gain is expected to be recognized in connection with the closing and, therefore, no liability under the Tax Receivable Agreement has been recognized in the accompanying pro forma balance sheet. In the future, if and when Tema exercises its right to cause Rosehill Operating to redeem all or a portion of its Rosehill Operating Common Units, it is expected that a liability under the Tax Receivable Agreement will be created based on 90% of the estimated future cash tax savings that KLRE will realize as a result of certain increases in the basis of the assets of Rosehill Operating as a result of such redemption; the amount of the increase in asset basis and the related estimated cash tax savings will depend on the price of our Class A common stock at the time of the relevant redemption. Due to the uncertainty surrounding the amount and timing of future redemptions of Rosehill Operating Common Units by Tema, we do not believe it is appropriate to record a Tax Receivable Agreement liability until such time that Tema exercises its right to cause Rosehill Operating to redeem its Rosehill Operating Common Units.

If all of Tema’s Rosehill Operating Common Units were redeemed immediately after the closing of the Business Combination, the estimated deferred tax asset, noncurrent tax receivable agreement liability, and adjustment to additional paid in capital in stockholders’ equity would be approximately $98.7 million, $88.8 million, and $9.9 million, respectively (calculated assuming a market price at the date of conversion of $11.50 per share and using a discount rate equal to one-year LIBOR plus 150 basis points, applied against an estimated TRA undiscounted liability of $111.1 million generally to be realized over the tax recoverable life of proved reserves). The recognition of any future liabilities associated with the Tax Receivable Agreement will reduce the amount of additional paid in capital recognized due to the transaction being among shareholders under common control.

The foregoing amounts are merely estimates based on the assumptions set forth above. The actual amount and timing of any payments under the Tax Receivable Agreement will vary depending upon a number of factors, including the timing of the exchanges of Rosehill Operating Common Units, the price of Class A common stock at the time of each exchange, the extent to which such exchanges are taxable, the amount and timing of the taxable income we generate in the future and the tax rate then applicable, and the portion of our payments under the Tax Receivable Agreement constituting imputed interest or depletable, depreciable or amortizable basis. Thus, it is likely that future transactions or events could increase or decrease the actual tax benefits realized and the corresponding Tax Receivable Agreement payments as compared to the estimates set forth above.

Redemption Adjustments. Our Sponsor and Rosemore, Inc. agreed to backstop redemptions by public stockholders in excess of 30% of the outstanding shares of Class A common stock by committing to purchase shares of Class A common stock or Series A Preferred Stock in an amount up to $20.0 million received pursuant to the Side Letter. The public shareholders redeemed 5,804,404 shares of Class A common stock for cash consideration of $60.6 million, utilizing the entire $20.0 million pursuant to the side letter. Our Sponsor and Rosemore elected to purchase 20,000 shares of Series A Preferred Stock. Accordingly, the pro forma condensed consolidated financial statements are reflected prior to and after redemptions.

 

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KLR ENERGY ACQUISITION CORP.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

For the Year Ended December 31, 2016

(in thousands, except for share amounts)

 

		KLRE				Rosehill LLC				Pro forma Adjustments				Pro forma (Prior to Redemptions)				Redemption Adjustment				Pro Forma (After Redemptions)
		(a)				(b)
Revenues		$	—			$	30,476			$	—			$	30,476			$	—			$	30,476
Total revenues			—				30,476				—				30,476				—				30,476
OPERATING EXPENSES:
Lease operating expenses			—				4,800				—				4,800				—				4,800
Production taxes			—				1,541				—				1,541				—				1,541
Gathering and transportation			—				2,398				—				2,398				—				2,398
Depreciation, depletion and amortization expense			—				24,789				—				24,789				—				24,789
Accretion			—				176				—				176				—				176
Impairment of oil and gas properties			—				—				—				—				—				—
Exploration costs			—				794				—				794				—				794
General and administrative expenses			1,637				9,000				(3,408	)(c)			7,229				—				7,229
Gain on sale of oil and gas properties			—				—				—				—				—				—
Loss (gain) on sale of other assets			—				(50	)			—				(50	)			—				(50	)
Total operating expenses			1,637				43,448				(3,408	)			41,677				—				41,677
INCOME (LOSS) FROM OPERATIONS			(1,637	)			(12,972	)			3,408				(11,201	)			—				(11,201	)
OTHER INCOME (EXPENSE):
Interest income (expense)			197				(1,822	)			—				(1,625	)			—				(1,625	)
Other income (expense), net							(247	)			—				(247	)			—				(247	)
Total other income (expense), net			197				(2,069	)			—				(1,872	)			—				(1,872	)
NET INCOME (LOSS) BEFORE INCOME TAXES			(1,440	)			(15,041	)			3,408				(13,073	)			—				(13,073	)
INCOME TAX (EXPENSE) BENEFIT			—				(148	)			—	(d)			(148	)			—				(148	)
NET INCOME (LOSS)			(1,440	)			(15,189	)			3,408				(13,221	)			—				(13,221	)
NET INCOME (LOSS) ATTRIBUTABLE TO NONCONTROLLING INTEREST IN SUBSIDIARY			—				—				8,931	(e)			8,931				1,648	(f)			10,579
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS		$	(1,440	)		$	(15,189	)		$	12,339			$	(4,290	)		$	1,648			$	(2,642	)
LOSS PER COMMON SHARE (g):
Basic and diluted		$	(0.55	)			—							$	(0.83	)						$	(1.75	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (IN THOUSANDS) (h):
Basic and diluted			2,628				—								12,435								5,857

 

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KLR ENERGY ACQUISITION CORP.

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED BALANCE SHEET

as of December 31, 2016

(in thousands)

 

		KLRE				Rosehill LLC				Pro forma Adjustments				Pro Forma (Prior to Redemptions)				Redemption Adjustment				Pro Forma (After Redemptions)
		(a)				(b)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	228			$	8,434			$	85,324	(c)		$	115,259			$	(40,599	)(k)		$	74,660
											70,875	(d)
											(35,000	)(e)
											(7,406	)(f)
											(6,921	)(g)
											(275	)(h)
Accounts receivable, net			—				1,928				—				1,928				—				1,928
Accounts receivable, related party			—				4,837				—				4,837				—				4,837
Inventory			—				280				—				280				—				280
Derivative instruments			—				247				—				247				—				247
Prepaid expenses and other current assets			24				617				—				641				—				641
Total current assets			252				16,343				106,597				123,192				(40,599	)			82,593
PROPERTY AND EQUIPMENT, NET (SUCCESSFUL EFFORTS METHOD):
Oil and gas properties (successful efforts method of accounting), net			—				122,267				—				122,267				—				122,267
Other property and equipment, net			—				1,106				—				1,106				—				1,106
Net property and equipment			—				123,373				—				123,373				—				123,373
OTHER NON-CURRENT ASSETS:
Noncurrent assets, net			—				110				—				110				—				110
Cash and marketable securities held in Trust Account			85,324				—				(85,324	)(c)			—				—				—
TOTAL ASSETS		$	85,576			$	139,826			$	21,273			$	246,675			$	(40,599	)		$	206,076
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses		$	1,094			$	4,658			$	—			$	5,752			$	—			$	5,752
Accounts payable, related parties			—				612				—				612				—				612
Accrued liabilities and other			—				7,205				—				7,205				—				7,205
Derivative instruments			—				1,856				—				1,856				—				1,856
Current portion, capital lease obligation			—				30				—				30				—				30
Current portion, long-term debt			—				—				—				—				—				—
TOTAL CURRENT LIABILITIES			1,094				14,361				—				15,455				—				15,455

 

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KLR ENERGY ACQUISITION CORP.

 

		KLRE				Rosehill LLC				Pro forma Adjustments				Pro Forma (Prior to Redemptions)				Redemption Adjustment				Pro Forma (After Redemptions)
		(a)				(b)
NONCURRENT LIABILITIES
Long term debt			—				55,000				—				55,000				—				55,000
Notes payable—related party			275				—				(275	)(h)			—				—				—
Deferred underwriting commission			46				—				(46	)(g)			0				—				0
Deferred rent			—				—				—				—				—				—
Capital lease obligation			—				65				—				65				—				65
Asset retirement obligations			—				5,180				—				5,180				—				5,180
TOTAL LIABILITIES			1,415				74,606				(321	)			75,700				—				75,700
Commitments
Class A common stock			79,161								(79,161	)(i)			—
Redeemable noncontrolling interest			—				—				76,433	(e)			76,433				(36,549	)(k)			39,884
EQUITY (l):
Members equity			—				65,220				(65,220	)(e)			—				—				—
Preferred Stock, $0.0001 par value											52,944	(d)			52,944				20,000	(k)			72,944
Class A common stock, $0.0001 par value			1				—				1	(j)			2				(1	)(k)			1
Class F common stock, $0.0001 par value			1				—				(1	)(j)			—				—				—
Class B common Stock, $0.0001 par value			—								3	(e)			3								3
Additional paid-in capital			6,447				—				(53,622	)(e),(f)			49,917				(24,049	)(k)			25,868
											17,931	(d)											—
											79,161	(i)											—
Accumulated deficit			(1,449	)			—				(6,875	)(g)			(8,324	)			—				(8,324	)
Total equity			5,000				65,220				24,322				94,542				(4,050	)			90,492
TOTAL LIABILITIES AND EQUITY		$	85,576			$	139,826			$	21,273			$	246,675			$	(40,599	)		$	206,076

 

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KLR ENERGY ACQUISITION CORP.

NOTES

 

1.	Basis of Pro Forma Presentation

Overview

The Business Combination Agreement resulted in Tema obtaining control of KLRE through its 29,807,692 shares of Class B common stock, representing 83.6% of the voting interest in KLRE (without giving effect to the conversion of any shares of Series A Preferred Stock issued in the PIPE Investment or purchased pursuant to the Side Letter). KLRE owns a direct 100% voting interest in Rosehill Operating as a result of the Business Combination. It is expected the Business Combination will be accounted for as a reverse acquisition pursuant to ASC 805-10-55-12 due to Tema having control of Rosehill Operating both before and (through control of KLRE) after the Business Combination. As such, the consolidation of Rosehill Operating by KLRE results in an initial measurement of the Rosehill Operating assets and liabilities transferred to KLRE equal to the historical carrying amounts of those assets and liabilities on the accounts of Tema on the transfer date. The pro forma adjustments have been prepared as if the Business Combination had taken place on December 31, 2016 in the case of the unaudited pro forma condensed consolidated balance sheet and on January 1, 2016 in the case of the unaudited pro forma condensed consolidated statements of operations for the year ended December 31, 2016.

The unaudited pro forma information presented herein reflects events directly attributable to the described transactions, are factually supportable, and, with respect to the statement of operations, are expected to have a continuing impact on KLRE’s results following the completion of the Business Combination. Such pro forma information is not necessarily indicative of financial results that would have been attained had the described transactions occurred on the dates indicated above, or the results of the combined company that may be achieved in the future. The adjustments are based on currently available information and certain estimates and assumptions. Therefore, the actual results may differ from the pro forma results indicated herein. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the Business Combination as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma condensed consolidated financial information.

The unaudited pro forma condensed consolidated financial information should be read in conjunction with:

 

•

The carve out financial statements of the Assets and Liabilities of the Business to be Contributed to Rosehill Operating and related notes for the year ended December 31, 2016, contained elsewhere in this prospectus, as well as the information presented under the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations”;

 

•

KLRE’s historical financial statements and related notes for the year ended December 31, 2016, as well as the information presented under the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations of KLRE” contained in our Definitive Proxy Statement filed on April 12, 2017; and

 

•

other information related to KLRE and Rosehill Operating included in this prospectus.

The pro forma adjustments represent management’s estimates based on information available as of the date of this filing and are subject to change as additional information becomes available and additional analyses are performed. The unaudited pro forma condensed consolidated financial information does not reflect possible adjustments related to restructuring or integration activities that have yet to be determined or other costs following the Business Combination that are not expected to have a continuing impact. Further, one-time transaction-related expenses anticipated to be incurred related to the Business Combination are not included in the unaudited pro forma condensed consolidated statements of operations. However, the impact of such transaction-related expenses is reflected in the unaudited pro forma condensed consolidated balance sheet as an adjustment to accumulated deficit and cash.

 

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No current or deferred income tax liability is recorded as a result of the Business Combination since its legal form (an investment in a newly created entity taxed as a pass-through partnership for U.S. federal income tax purposes) does not result in a taxable event to KLRE. KLRE will be taxed on its share of future earnings not attributed to Tema’s interest (depicted as non-controlling interest), whereas Tema will continue to bear its share of income tax on its share of future earnings. The income tax burden on the earnings taxed to Tema is not reported by KLRE in the consolidated financial statements under GAAP.

The Company does not anticipate an increase in the tax basis of Rosehill Operating assets in connection with the distribution to Tema of Cash Consideration, shares of Class B common stock and Tema warrants and the assumption of Tema liabilities in connection with the Business Combination; therefore, no Tax Receivable Agreement liability is reflected in the unaudited pro forma condensed consolidated financial information. Liabilities under the Tax Receivable Agreement will be recognized upon the future redemption by Tema or the exchange by the Company, as applicable, of Rosehill Operating Common Units for Class A common stock or cash, as applicable.

 

2.	Pro Forma Adjustments and Assumptions

Pro Forma Adjustments to the Statement of Operations:

 

(a)

Represents the KLRE historical statement of operations for the year ended December 31, 2016.

 

(b)

Represents the historical statement of operations of the assets and liabilities of the business to be contributed to Rosehill Operating for the year ended December 31, 2016.

 

(c)

Represents $3.4 million non-recurring transaction costs incurred through December 31, 2016 related to the Business Combination which have been excluded from the unaudited pro forma statement of operations.

 

(d)

No pro forma adjustment for income tax benefit was reflected in the pro forma statement of operations. The Company is a newly formed Subchapter C corporation with no income tax refund potential. Accordingly, no deferred tax asset created by the loss was judged to be, more likely than not, collectible.

 

(e)

Represents net income (loss) attributable to the redeemable noncontrolling interest in the total pro forma consolidated net income (loss) based on Tema’s ownership of Rosehill Operating as a result of the Business Combination.

 

(f)

Represents net income (loss) attributable to the redeemable noncontrolling interest in Rosehill Operating by Tema on the total pro forma consolidated net income (loss) after redemptions.

 

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(g)

Reflects basic and diluted earnings per common share after the impact of the Business Combination and the PIPE Investment. Earnings per share includes adjustments for 8% Series A Preferred Stock dividends not available to common shareholders. Outstanding KLRE warrants (as disclosed in footnote (k) below) were excluded in the calculation of diluted net earnings per share as inclusion would have been anti-dilutive. The following table sets forth the computation of pro forma basic and diluted loss per common share for the year ended December 31, 2016, assuming scenarios, in which (i) prior to redemptions, and (ii) 5,804,404 shares of Class A common stock are redeemed and 20,000 shares of Series A Preferred Stock are purchased pursuant to the Side Letter (in thousands except per share data):

 

		For the Year Ended December 31, 2016
		Prior to Redemptions				After Redemptions and where Side Letter purchasers buy Series A Preferred
Net loss attributable to common shareholders		$	(4,290	)		$	(2,642	)
Pro forma adjustment to reflect Series A Preferred Stock dividend			(6,000	)		$	(7,600	)
Net loss used to compute pro forma net loss per share		$	(10,290	)		$	(10,242	)
Pro Forma Weighted Average Common Shares Outstanding
Basic and Diluted			12,435				5,857
Pro Forma Net Loss Per Common Share
Basic and Diluted		$	(0.83	)		$	(1.75	)

 

(h)

The following table represents Pro forma weighted average shares outstanding prior to and following the redemptions (in thousands):

 

		Prior to Redemptions				Reflective of Redemptions where Side Letter purchasers buy Series A Preferred
Shares of Class A Common Stock before the Business Combination			8,185				8,185
Founder Shares converted to Class A Common Stock(i)			4,250				3,476
Shares of Class A Common Stock redeemed			—				(5,804	)
Weighted-average shares of Class A Common Stock outstanding			12,435				5,857

 

(i)

Conversion of the Founder Shares into shares of Class A common stock is limited to 4,250,000 shares prior to the redemptions. After redemptions, the conversion of the Founder Shares into shares of Class A common stock is limited to 3,475,663. Following the conversion, the Founder Shares were canceled.

Pro Forma Adjustments to the Balance Sheet:

 

(a)

Represents the KLRE historical balance sheet as of December 31, 2016.

 

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KLR ENERGY ACQUISITION CORP.

 

(b)

Represents the balance sheet of the assets and liabilities of the business to be contributed to Rosehill Operating as of December 31, 2016.

 

(c)

Represents the adjustment of $85.3 million related to the reclassification of $85.3 million of cash equivalents held in the Trust Account to cash and cash equivalents to reflect the fact that these investments are available for use in connection with the Business Combination.

 

(d)

Reflects the issuance by KLRE of 75,000 Series A Preferred Stock at $1,000 per share and 5,000,000 PIPE Warrants to the PIPE Investors in connection with the closing of the Business Combination for net proceeds of $70.9 million, in addition to the 476,540 shares of Class A common stock transferred, in lieu of cancellation and reissuance, by our Sponsor to the PIPE Investors in connection with the closing of the Business Combination. The transfer of Class A common shares to the PIPE Investors by our Sponsor is considered an in-substance capital contribution to KLRE. The net proceeds of the PIPE Investment have been allocated among the Preferred, PIPE Warrants and 476,540 shares of Class A common shares based on the relative fair value of the instruments. The fair value allocated to the Preferred Stock is reflected as Preferred Stock whereas the remaining value is reflected as additional paid-in capital. The following table illustrates the relative fair value allocated to each instrument (in thousands):

 

Net proceeds of PIPE Investment		$	70,875
Proceeds allocated to:
Preferred stock			52,944
Warrants			14,436
Class A common stock			3,495

 

(e)

Represents the acquisition by KLRE of approximately 16.4% of the outstanding common membership units in Rosehill Operating from Tema, in exchange for (i) the contribution to Rosehill Operating by KLRE of the Cash Consideration and related distribution to Tema, (ii) 29,807,692 shares of Class B common stock and the Tema Warrants (which Cash Consideration, Class B common stock, and warrants will immediately be distributed by Rosehill Operating to Tema), (iii) the assumption by Rosehill Operating of $55.0 million in indebtedness, (iv) the contribution to Rosehill Operating by KLRE of the remaining cash proceeds of KLRE’s IPO and the PIPE Investment and (v) the transfer, in lieu of cancellation and reissuance, by our Sponsor of 750,000 warrants to purchase Class A common stock of KLRE to Rosemore pursuant to the Side Letter. The interest in the net assets of Rosehill Operating not attributable, directly or indirectly, to KLRE are represented as redeemable noncontrolling interest. The Company has classified the noncontrolling interest as temporary equity as Tema has the election to cause redemption of the common membership units in Rosehill Operating it retained in connection with the Business Combination Agreement through the issuance of Class A common shares or cash, at Rosehill Operating’s election.

 

(f)

Represents $7.4 million of working capital adjustment paid to Tema at closing pursuant to the Business Combination Agreement.

 

(g)

Represents $6.9 million of banking, legal and accounting fees that were expensed (not capitalized within equity) in connection with the Business Combination as well as $46,330 of deferred underwriting commissions which were accrued as of December 31, 2016. $3.4 million of the cost was incurred by Tema, and will be reimbursed upon closing.

 

(h)

Reflects the repayment of $275,000 of related party notes due our Sponsor and its affiliates upon consummation of the Business Combination.

 

(i)

Represents an adjustment of $79.2 million related to shares of Class A common stock that were subject to possible redemption from redeemable equity in KLRE’s historical consolidated balance sheet as of

 

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December 31, 2016 to permanent equity in connection with the Business Combination. These shares are no longer redeemable and have been reclassified from redeemable equity to additional paid in capital and Class A common stock, $0.0001 par value.

 

(j)

Represents the conversion of 2,046,330 Class F Founders Shares into 3,475,663 shares of Class A common stock upon the closing of the Business Combination and the redemptions of the Class A common stock.

 

(k)

Reflects the redemption of 5,804,404 shares of Class A common stock (approximately 76.4% of total shares available for redemption), for approximately $60.6 million using proceeds from the Trust Account and $20.0 million received pursuant to the Side Letter. Pursuant to the Side Letter, Rosemore and our Sponsor purchased 20,000 shares of Series A Preferred Stock for $20.0 million. Pro forma cash after the redemptions is $74.6 million. As a result of this redemption, Tema’s interest in KLRE will be approximately 83.6%.

 

(l)

The following tables reflects the authorized, issued and outstanding shares of common and preferred stock:

 

		KLRE				Rosehill LLC				Pro forma Adjustments				Pro forma (Prior to Redemptions)				Redemption Adj.				Pro forma (After Redemptions)
Temporary Equity
Class A common stock
Issued			7,597,044				—				(7,597,044	)(i)			—				—				—
Stockholders’ equity
Preferred Stock
Authorized			—				—				1,000,000				1,000,000				—				1,000,000
Issued and outstanding			—				—				75,000	(ii)			75,000				20,000	(v)			95,000
Class A common stock, $0.0001 par value
Authorized			35,000,000				—				60,000,000				95,000,000								95,000,000
Issued and outstanding			588,276				—				7,597,044	(i)			12,435,320				(5,804,404	)(vi)			5,856,579
											4,250,000	(iii)							(774,337	)(iii)
Class F common stock, $0.0001 par value
Authorized			6,000,000				—				(6,000,000	)(iii)			—				—				—
Issued and outstanding			2,046,330				—				(2,046,330	)(iii)			—				—				—
Class B common stock, $0.0001 par value
Authorized			—				—				30,000,000				30,000,000				—				30,000,000
Issued and outstanding			—				—				29,807,692	(iv)			29,807,692				—				29,807,692
Warrants			16,594,158				—				4,000,000	(iv)			25,594,158				—				25,594,158
											5,000,000	(ii)

 

(i)	Reclassification of redeemable equity as described in note (i) above

(ii)	Issuance of Series A Preferred Stock and warrants to the PIPE Investors

(iii)

Conversion of the Founder Shares to Class A common shares is limited to 4,250,000 shares, including 476,540 shares provided to PIPE Investors by the founders prior to the redemptions. Upon the redemptions,

 

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the conversion of the Founder Shares to Class A common shares is limited to 3,475,663. Following the conversion, the Founder Shares were canceled

(iv)	Issuance of Class B common stock and Tema warrants to Rosehill Operating

(v)	Issuance of Series A Preferred stock pursuant to the Side Letter, as the proceeds received from the backstop were used to purchase Series A Preferred stock

(vi)	Shares of Class A common stock redeemed

 

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DESCRIPTION OF BUSINESS

General

We were originally formed on September 21, 2015 as a Delaware special purpose acquisition company for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination involving us and one or more businesses. On April 27, 2017, we consummated a business combination (the “Business Combination”) pursuant to that certain Business Combination Agreement (the “Business Combination Agreement”), dated as of December 20, 2016, by and between the KLR Energy Acquisition Corp. and Tema Oil and Gas Company (“Tema”). Pursuant to the Business Combination Agreement, we acquired a portion of the equity of Rosehill Operating Company LLC (“Rosehill Operating”), a wholly-owned subsidiary of Tema, to which Tema contributed and transferred a portion of its assets and liabilities, for (i) the contribution to Rosehill Operating by us of $35.0 million in cash (the “Cash Consideration”) and for the issuance to Rosehill Operating by us of 29,807,692 shares of our Class B Common Stock, subject to certain adjustments as set forth in the Business Combination Agreement (which cash and shares of Class B Common Stock were immediately distributed by Rosehill Operating to Tema), (ii) the assumption by Rosehill Operating of $55.0 million in Tema indebtedness and (iii) the contribution to Rosehill Operating by us of the remaining cash proceeds of our initial public offering. In connection with the closing of the Business Combination, (i) we issued to Rosehill Operating 4,000,000 Warrants exercisable for shares of Class A Common Stock (the “Tema warrants”) in exchange for 4,000,000 warrants exercisable for Rosehill Operating Common Units (the “Rosehill warrants”) and (ii) the Tema warrants and the Cash Consideration were immediately distributed to Tema.

In connection with the Business Combination, we issued and sold 75,000 shares of Series A Preferred Stock and 5,000,000 Warrants in a private placement to certain qualified institutional buyers and accredited investors for gross proceeds of $75 million (the “PIPE Investment”). The investors in the PIPE Investment are entitled to certain customary registration rights, including the filing of a resale shelf registration statement. We contributed the net proceeds from the PIPE Investment to Rosehill Operating in exchange for Rosehill Operating Series A preferred units and additional Rosehill warrants. We also issued 20,000 shares of Series A Preferred Stock to Rosehill Holdings, Inc. and our Sponsor in connection with the closing of the Business Combination.

Immediately following the Business Combination, we owned approximately 16% of Rosehill Operating’s common equity and Tema owned the remaining 84%. After giving effect to the conversion of the Rosehill Operating Series A preferred units into Rosehill Common Units, we will own approximately 32% of Rosehill Operating’s common equity and Tema will own the remaining 68%.

Following the Business Combination, we changed our name from “KLR Energy Acquisition Corp.” to “Rosehill Resources Inc.” and continued the listing of our Class A Common Stock, units and Warrants on The NASDAQ Capital Market under the symbols “ROSE,” “ROSEU” and “ROSEW,” respectively. Until the consummation of the Business Combination, our Class A Common Stock, units and Warrants were listed on The NASDAQ Capital Market under the symbols “KLRE”, “KLREU” and “KLREW”, respectively.

Business Overview

We are an independent oil and natural gas company focused on the exploration, development, acquisition and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and the Fort Worth Basin.

As of December 31, 2016, our portfolio included 20 gross operated producing horizontal wells and one operated producing vertical well. We also operate 18 vertical and 21 horizontal wells in the Barnett Shale in the Fort Worth Basin that are intended to be used to support our Delaware Basin drilling program. As of December 31, 2016, our properties included working interests in approximately 4,789 net acres in the Delaware Basin, plus an additional 4,468 net acres in the Barnett Shale. As of December 31, 2016, we had identified 202

 

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gross potential horizontal drilling locations, including 13 locations associated with proved undeveloped reserves as of December 31, 2016, in up to ten formations from Brushy Canyon down through the Wolfcamp B. As of December 31, 2016, 146 of our gross potential horizontal drilling locations were economic using Securities and Exchange Commission (“SEC”) pricing assumptions. Our goal is to increase production and reserves through strategic acquisitions and maximizing value of existing assets by optimizing completions, reducing horizontal drilling costs, efficient facility buildout, and reducing operating costs.

Our primary goal is to develop a best-in-class exploration and production company primarily focused on horizontal drilling in the Delaware Basin. As of December 31, 2016, our Delaware Basin portfolio included 20 operated producing horizontal wells, four non-operated producing horizontal wells, and one operated producing vertical well. The horizontal wells span a geographic area approximately four miles long by five miles wide, where we and nearby operators have established commercial production in ten distinct formations, including Brushy Canyon, Upper Avalon Shale, Lower Avalon/1^st Bone Spring, 2^nd Bone Spring Shale, 2^nd Bone Spring Sand, 3^rd Bone Spring Shale, 3^rd Bone Spring Sand, Wolfcamp A (XY Sand), Lower Wolfcamp A Shale and Wolfcamp B. As of December 31, 2016, we hold 4,789 net acres in the Delaware Basin, approximately 95% of which is operated by us. Our acreage is predominantly located in Loving County, Texas. We began drilling in Loving County in 2013 with the drilling of nine horizontal Avalon Shale wells. In 2014, we drilled seven additional operated horizontal wells, including four horizontal Avalon Shale wells and three horizontal Worfcamp A wells, and also participated in the drilling of one non-operated horizontal Bone Spring well before suspending our drilling program to conserve capital in response to a precipitous decline in commodity prices. In order to manage cash flow, in 2015 and 2016, we limited our drilling activity to four operated horizontal Lower Wolfcamp A Shale wells that were drilled in order to avoid lease expiration and also participated in the drilling of three non-operated horizontal Wolfcamp A wells. During 2017, we expect to continuously operate one drilling rig focused on the 3rd Bone Spring, Wolfcamp A (XY Sand), Lower Wolfcamp A Shale and Wolfcamp B formations. We plan to add one additional drilling rig in March 2017 to optimize our development program. The development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on reducing drilling times, optimizing completions and reducing costs.

As of December 31, 2016, we also operated 18 vertical and 21 horizontal wells on 4,468 acres in the Barnett Shale in the Fort Worth Basin. We drilled these wells over a nine-year period from 2002 through 2011. We believe our Barnett Shale acreage is fully developed and have no plans to drill any additional wells. We expect to use cash flow from our Barnett Shale production to support our Delaware Basin drilling program.

We believe the Permian Basin is an attractive operating area due to its immense original oil-in-place, favorable operating environment, multiple proven horizontal reservoirs, high oil and liquids-rich natural gas content, well-developed network of oilfield service providers, long-lived reserves with relatively consistent reservoir quality and historically high drilling success rates.

 

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As of December 31, 2016, we had identified 202 gross potential horizontal drilling locations, which includes 13 locations associated with proved undeveloped reserves as of December 31, 2016, in up to ten formations from Brushy Canyon down through the Wolfcamp B. The inventory is based on four wells per 640-acre section with 5,000-foot laterals. As of December 31, 2016, 146 of our gross potential horizontal drilling locations were economic using SEC pricing assumptions. In 2017, we expect to focus on drilling the 3rd Bone Spring Sand, Wolfcamp A (XY Sand), Lower Wolfcamp A and Wolfcamp B, which we believe to be the most productive and deepest horizons in its portfolio. The following table provides a summary of our identified gross potential horizontal drilling locations by formation as of December 31, 2016:

 

		Location Count
Location Inventory(1)(2)
Formations:
Brushy Canyon			27
Upper Avalon			13
Lower Avalon / 1st Bone Spring			13
2nd Bone Spring Shale			19
2nd Bone Spring Sand			23
3rd Bone Spring Shale			25
3rd Bone Spring Sand			23
Wolfcamp AX, Y			16
Lower Wolfcamp A			24
Wolfcamp B			19
Total Horizontal Locations(3)(4)			202

 

(1)

Our total identified gross potential horizontal drilling locations include 13 locations associated with proved undeveloped reserves as of December 31, 2016. We have estimated our drilling locations based on well spacing assumptions and upon the evaluation of its horizontal drilling results and those of other operators in its area, combined with its interpretation of available geologic and engineering data. In particular, we have analyzed and interpreted well results and other data acquired through our participation in the drilling of a vertical well that penetrated all of our targeted horizontal formations. In addition, to evaluate the prospects of its horizontal acreage, we have performed open-hole and mud log evaluations, core analysis, drill cuttings analysis, and have acquired and interpreted modern 3-D seismic data. The drilling locations that we actually drill will depend on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Any drilling activities we are able to conduct on these identified potential horizontal drilling locations may not be successful and may not result in our ability to add additional proved reserves to our existing proved reserves. Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. The identified gross potential drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the capital that would be necessary to drill such locations.

(2)	Our inventory of gross potential horizontal drilling locations assumes 1,320 foot well spacing with 40 wells per 640-acre section across up to ten formations with the number of prospective formations varying from tract to tract depending on the geology of the specific area.

(3)

Our identified gross potential horizontal drilling locations are located on operated and non-operated acreage. We operate 95% of the 202 identified gross potential drilling locations. Of the 13 identified gross potential horizontal drilling locations associated with proved undeveloped reserves, 12 are operated and one is non- operated. As of December 31, 2016, we had an approximate 94% average working interest in our operated acreage.

(4)	Includes proved undeveloped (“PUD”) locations on our leasehold in Loving, Lea, and Eddy Counties, Texas.

We believe that development drilling of our 202 identified gross potential horizontal drilling locations, together with an increased focus on completion optimization and drilling efficiencies, as well as potential down

 

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spacing, will allow us to grow our production and reserves. We also intend to grow our production and reserves through acquisitions that meet certain strategic and financial objectives. We further believe operational efficiencies are enhanced with an operated saltwater disposal system and pipeline access to a third-party water disposal site. In addition, a third-party crude oil and natural gas gathering system is already in-place and operational, which will transport the majority of our products to market. In connection with the Business Combination, we and Gateway, an affiliate of Tema, entered into crude oil gathering and natural gas gathering agreements for a ten-year term. Please read the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Related Party Transactions”.

We experienced a significant decrease in our drilling and completion costs during 2015, which continued into 2016. This trend was driven by efficiency improvements in the field, including reduced drilling days, the modification of well designs and the reduction or elimination of unnecessary costs, such as eliminating the use of snubbing units to install tubing into a live well, reduction in number of trips in and out of the well bore during drilling by switching to a more engineered drill bit selection, and utilizing a third party mud consultant to monitor the mud program and properties thereby reducing the chemical usage and improving the rate of penetration. Additionally, overall service costs have declined as a result of reduced industry demand. For 2015 and 2016, the spud-to-rig release for our horizontal wells averaged 38 days (all Wolfcamp targets) compared to wells drilled in 2013 and 2014, which averaged 35 days and 44 days respectively (primarily Avalon targets). We expect that further field optimization will improve our well economics.

Our 2016 capital budget for drilling, completion and recompletion activities and facilities costs was approximately $25.5 million, excluding leasing and other acquisitions. We allocated approximately $24.8 million to drill and complete operated wells and $0.7 million to participate in the drilling and completion of non-operated wells. For 2016, we budgeted $1.6 million for leasing. In the year ended December 31, 2016, we incurred capital costs of approximately $22.9 million, excluding leasing and acquisition costs and inclusive of changes in accruals of capital expenditures.

Our 2017 capital budget for drilling, completion and recompletion activities and facilities costs is approximately $89.9 million, excluding leasing and other acquisitions. For 2017, we allocated approximately $88.7 million to drill and complete operated wells and $1.2 million to participate in the drilling and completion of non-operated wells. For 2017, we have budgeted $4.0 million for leasing of oil and gas acreage.

Because we operate approximately 95% of our net acreage, the amount and timing of these capital expenditures are largely subject to our discretion. Our operated acreage provides us with flexibility to manage our drilling program and optimize our returns and profitability. Our decision to defer a portion of our planned capital expenditures would depend on a variety of factors, including the success of our drilling activities; prevailing and anticipated prices for oil, natural gas, and natural gas liquids (“NGLs”); the availability of necessary equipment, infrastructure, and capital; the receipt and timing of required regulatory permits and approvals; drilling, completion and acquisition costs; and the level of participation by other working interest owners.

As of December 31, 2016, our properties include working interests in approximately 4,789 net acres in the Delaware Basin, plus an additional 4,468 net acres in the Barnett Shale. The following table summarizes our acreage by county as of December 31, 2016:

 

		Gross				Net
County:
Loving (Delaware)			4,321				2,939
Lea (Delaware)			1,567				1,131
Eddy (Delaware)			797				92
Reeves (Delaware)			627				627
Wise (Barnett)			4,470				4,468
Total			11,782				9,257

 

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Permian Basin. The Permian Basin consists of mature, legacy onshore oil and liquids-rich natural gas reservoirs that span approximately 86,000 square miles in West Texas and New Mexico. The Permian Basin is composed of five sub regions: the Delaware Basin, the Central Basin Platform, the Midland Basin, the Northwest Shelf and the Eastern Shelf. The Permian Basin is an attractive operating area due to its multiple horizontal and vertical target formations, favorable operating environment, high oil and liquids-rich natural gas content, mature infrastructure, well-developed network of oilfield service providers, long-lived reserves with consistent reservoir quality and historically high drilling success rates. According to the U.S. Energy Information Administration, the Permian Basin is the most prolific unconventional oil producing area in the U.S. and accounts for nearly half of the active drilling rigs in the U.S. as of December 31, 2016.

Delaware Basin. The present structural form of the Delaware Basin, a sub-basin of the Permian Basin, began to take shape in the early Pennsylvanian period at which time the area slowly downwarped relative to the adjacent Central Basin Platform and Northwest Shelf. This period was characterized by relatively stable marine shale and limestone deposition with periodic influxes of siliciclastics during sea-level lowstands. Stratigraphic records indicate a rapid deepening of the Delaware Basin during early Permian time. Organic rich marine shales, carbonate debris flows, and turbidite sandstones were the predominant deposits in the Delaware Basin during this period. Subsequent burial and thermal maturation of this thick Permian succession of highly organic source and reservoir rock resulted in what Rosehill Operating believes is evolving into a prolific oil field.

The Delaware Basin encompasses an estimated 15,000 square miles and contained over 25,000 producing wells at the end of 2015, with production from certain wells dating back to 1924. Over the past decade, horizontal drilling activity has been more prevalent within the Delaware Basin relative to other areas of the Permian Basin. As of December 31, 2016, three of the top four Permian Basin counties by horizontal rig count are located in the Delaware Basin.

Oil and natural gas production was first established in the 1940s and 1950s from vertical wells in the Delaware Basin in the area of Rosehill Operating’s leasehold. Unconventional, horizontal production was first established in 2010 in the Avalon Shale member of the Bone Spring formation. Horizontal Wolfcamp production was established in 2014. The Wolfcamp has become the most common horizontal drilling target in Rosehill Operating’s core, with new wells targeting both the XY Sand interval near the top of the Wolfcamp A and the Lower Wolfcamp A Shale.

Advanced petrophysical logs from the vertical portions of our wells, sidewall cores, and seismic data are being utilized to guide our horizontal development of the area. The use of seismic data has resulted in a better understanding of our leasehold’s geology relative to other parts of the basin. The depth to the top of the Wolfcamp from a representative well central to our leasehold is approximately 11,500 feet true vertical depth. The gross thickness of the potential pay section from the top of the Brushy Canyon formation through the base of the Wolfcamp B is approximately 4,500 feet, an attractive thickness for development with multiple horizontal landing formations. We believe that the combination of these conditions will allow us to achieve superior results during the development of its leasehold.

Historically, our horizontal drilling, including 20 gross operated wells, has been widespread across the majority of its lease acreage. We have established commercial production in four distinct formations: the Upper Avalon, Lower Avalon, Wolfcamp A (XY Sand) and Lower Wolfcamp A Shale. In addition, offset operators have drilled and are producing in all ten formations—from Brushy Canyon down through the Wolfcamp B—within a 12 mile radius of our leasehold, enabling us to evaluate our acreage across various geographic areas and stratigraphic formations. As of December 31, 2016, approximately 89% of our total net operated acreage was either held by production or under continuous drilling provisions. Offset operator activity within the 3rd Bone Spring Sand and the Wolfcamp formations as well as our recent successful Wolfcamp drilling program has been a catalyst for Rosehill Operating to generate a development program focused on the 3rd Bone Spring Sand, Wolfcamp A (XY Sands), Lower Wolfcamp A Shale and Wolfcamp B formations. We will closely monitor this offset activity and adjust our future development plans with information and best practices learned from other operators.

 

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Completion design and our effective execution are the predominant factors that dictate relative well performance in an area or zone. We have an evolving completion strategy that includes methodical adjustments of parameters, testing of different well designs on adjacent locations with similar rock characteristics, constant monitoring and re-evaluation of results and ultimately tailoring completions to the conditions specific to an area or formation. Our current base completion design is a hybrid fracture stimulation—a combination of slickwater and cross-linked gel. The field-level rate of return is most influenced by incremental improvements in well performance and cost savings; our philosophy is to focus on both parameters, with an emphasis on performance enhancement.

We believe all ten formations represent opportunities across our core acreage and we plan to target those formations in our future drilling program. Our inventory of identified gross potential drilling locations for the Wolfcamp is based on locations spaced approximately 1,320 feet from each other within a zone and staggered vertically in adjacent formations (as illustrated in the figure below).

 

 

 

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If future down spacing pilots are successful, we may be able to add additional locations to our multi-year inventory. Future development and location count may be improved as per the following diagram:

 

 

Production Status. During 2015, our Delaware Basin average net daily production was 3,096 Boe/d (approximately 28% liquids). For the year ended December 31, 2016, our average net daily production was 3,734 Boe/d (approximately 26% liquids). As of December 31, 2016, we produced from 20 horizontal and one vertical operated wells and four horizontal non-operated wells in the Delaware Basin.

Facilities. Our development plan includes the development of necessary infrastructure to lower our costs and support our drilling schedule and production growth. We expect to accomplish this goal primarily through contractual arrangements with third-party service providers. Our facilities are generally in close proximity to our well locations and include storage tank batteries, oil/natural gas/water separation equipment, and artificial lift equipment. A crude oil gathering system and a natural gas gathering system are already in place and functioning. We have sufficient gathering systems and pipeline takeaway capacity to continue ongoing and planned operations into mid-2017. Throughout 2017, as we continue to drill and develop the Delaware Basin assets, we expect that additional tank battery, water disposal and intra-field gathering lines will be required. We have agreements in place with third-party natural gas and crude oil purchasers and processors to benefit from existing downstream infrastructure. We expect to continue to evaluate the marketplace to obtain additional transportation and gathering options and capacity in the form of new pipeline tie-ins. We and Gateway entered into crude oil gathering and natural gas gathering agreements for a ten-year term. Please read the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Related Party Transactions”.

Recent and Future Activity. During 2015 and 2016, while in a reduced capital expenditure mode, four new operated Wolfcamp wells were drilled and placed on production on our acreage. All four wells were horizontal and met or exceeded 800 Bbl/d gross initial production rates. We completed drilling and fracking of the Weber 26 G001 on December 30, 2016 and started flow back on December 31, 2016. We also participated in the drilling of three non-operated horizontal Wolfcamp A wells during 2015 and 2016.

 

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In this prospectus, identified gross potential drilling locations are defined as locations on operated and non-operated leaseholds specifically identified by geologic, engineering and economic assessment. We have estimated our drilling locations based on well spacing assumptions and the evaluation of our operated horizontal drilling results as well as results of other operators in our area. Well performances are combined with interpretation of available geologic and engineering data to generate a development model for the assets. In addition, to evaluate the prospects of our horizontal acreage, we have performed open-hole and mud log evaluations, core analysis, and drill cuttings analysis. We have also acquired 48 square miles of 3-D seismic data that has been used to aid in the interpretation of the prospective formations. The availability of local infrastructure, well performance results, subsurface data and other factors that management may deem relevant, such as easement restrictions and state and local regulations, are considered in determining such locations. The locations that we will actually drill will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs and actual drilling results, among other factors.

Oil and Natural Gas Data

Proved Reserves

Evaluation and Review of Proved Reserves. The reserve estimates provided herein are “carve-out” reserves for assets that were contributed by Tema to us in connection with the Business Combination. As such, the carve-out reserves are a subset of the full reserve estimates generated at year-end of each respective year covered in this document. Proved reserve estimates as of December 31, 2016 were prepared by Ryder Scott, our independent petroleum engineer. Proved reserve estimates as of December 31, 2015 and 2014 were prepared internally by management. The technical persons responsible for preparing our proved reserve estimates meet the requirements with regard to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Ryder Scott does not own an interest in any of our properties, nor is it employed by us on a contingent basis. Copies of our independent petroleum engineer’s proved reserve reports as of December 31, 2016 are attached as exhibits this prospectus.

We maintain an internal staff of petroleum engineers and geoscience professionals to work closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of the data used to calculate the proved reserves relating to our assets. Our internal technical team members meet with our independent petroleum engineer periodically during the period covered by the proved reserve report to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to Ryder Scott for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices, subsurface geologic data and operating and development costs. Paul Larson, our Reservoir Engineering Manager, is primarily responsible for overseeing the preparations of all of our reserve estimates. Mr. Larson is a petroleum engineer with 25 years of petroleum engineering experience, including experience with both offshore conventional and onshore unconventional field developments. The preparation of our proved reserve estimates was completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:

 

•

review and verification of producing formations, well targets and the development plan by our Vice President of Geology and Reservoir Engineering Manager;

 

•

review and verification of historical production data, which data is based on actual production as reported by us;

•

review of well by well reserve estimates by independent reserve engineers;

 

•

review by our Reservoir Engineering Manager of all of our reported proved reserves, including the review of all significant reserve changes and all new PUD additions;

 

•

direct reporting responsibilities by our Reservoir Engineering Manager to our Chief Executive Officer; and

 

•

verification of property ownership interests by our land department.

 

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Estimation of Proved Reserves. Under the rules promulgated by the SEC, proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations, prior to the time at which contracts providing the right to operate expire (unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation). If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves as of December 31, 2016, 2015 and 2014 were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for PDP wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates for developed and undeveloped properties were forecasted using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing and PUD locations for our properties, due to the abundance of analog data.

To estimate economically recoverable proved reserves and related future net cash flows, Ryder Scott and management considered with respect to the carve-out figures many factors and assumptions, including the use of reservoir parameters derived from geological and engineering data, which cannot be measured directly, economic criteria based on current costs, SEC pricing requirements, and forecasts of future production rates. Under SEC rules, reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to our estimated proved reserves, the technologies and economic data used in the estimation of our proved reserves have been demonstrated to yield results with consistency and repeatability and include production and well test data, downhole completion information, geologic data, electrical logs, radioactivity logs, core analyses, available seismic data, historical well costs and operating expense data.

 

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Summary of Oil and Natural Gas Reserves. The following table presents our carve-out estimated net proved oil and natural gas reserves as of December 31, 2016, 2015 and 2014 based on our proved reserve reports and those of Ryder Scott for 2016 and of Tema from each of 2015 and 2014. The reserve estimates attributable to our properties presented in the table were prepared internally by management.

 

		As of December 31,
		2016(1)				2015(2)				2014(3)
Proved developed reserves:
Oil (MBbls)			3,068				2,698				3,200
Natural gas (MMcf)			10,574				10,116				18,753
NGL (MBbls)			1,802				1,481				2,798
Total (MBoe)			6,632				5,865				9,124
Proved undeveloped reserves:
Oil (MBbls)			4,288				2,954				3,089
Natural gas (MMcf)			6,781				3,783				8,869
NGL (MBbls)			1,183				513				1,501
Total (MBoe)			6,601				4,098				6,068
Total proved reserves:
Oil (MBbls)			7,356				5,652				6,289
Natural gas (MMcf)			17,355				13,899				27,622
NGL (MBbls)			2,985				1,994				4,299
Total (MBoe)			13,234				9,963				15,192
Oil and Natural Gas Prices:
Oil—WTI posted price per Bbl		$	42.75			$	50.28			$	91.61
Natural gas—Henry Hub spot price per MMBtu		$	2.49			$	2.58			$	4.43
NGL—per Bbl		$	11.73			$	13.83			$	30.67

 

(1)

Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil, the average West Texas Intermediate posted price of $42.75 per barrel as of December 31, 2016 was adjusted for quality, transportation fees, and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.49 per MMBtu as of December 31, 2016 was adjusted for energy content and a regional price differential. For NGL volumes, 27.5% of the average West Texas Intermediate posted price of $42.75 per barrel, or $11.73, as of December 31, 2016 was adjusted for quality, transportation fees and a regional price differential. All prices are held constant throughout the producing life of the properties.

(2)

Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil, the average West Texas Intermediate posted price of $50.28 per barrel as of December 31, 2015 was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.58 per MMBtu as of December 31, 2015 was adjusted for energy content and a regional price differential. For NGL volumes, 27.5% of the average West Texas Intermediate posted price of $50.28 per barrel, or $13.83, as of December 31, 2015 was adjusted for quality, transportation fees and a regional price differential. All prices are held constant throughout the producing life of the properties.

(3)

Our estimated net proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil, the average West Texas Intermediate posted price of $91.61 per barrel as of December 31, 2014 was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $4.43 per MMBtu as of December 31, 2014 was adjusted for energy content and a regional price differential. For NGL volumes, the twelve month average of actual NGL prices received in 2014, or $30.67, as adjusted for quality, transportation fees and a regional price differential. All prices are held constant throughout the producing life of the properties.

 

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The changes from December 31, 2015 estimated proved reserves to December 31, 2016 estimated proved reserves reflect the addition of 5.479 MMBoe of proved reserves through discoveries and extensions, offset by net negative revisions of 0.841 MMBoe primarily due to the decline in commodity prices and production of 1.367 MMBoe throughout the year.

The changes from December 31, 2014 estimated proved reserves to December 31, 2015 estimated proved reserves reflect the addition of 4.687 MMBoe of proved reserves through discoveries and extensions, offset by net negative revisions of 8.786 MMBoe primarily due to the decline in commodity prices and production of 1.130 MMBoe throughout the year.

Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read the section entitled “Risk Factors—Risks Related to Operations.”

Additional information regarding our proved reserves can be found in the carve-out financial statements of the Assets and Liabilities of the Business to be Contributed to Rosehill Operating included elsewhere in this prospectus.

Proved Undeveloped Reserves

Year Ended December 31, 2016

As of December 31, 2016, our PUDs totaled 4.288 MMBbls of oil, 6.781 Bcf of natural gas and 1.183 MMBbls of NGLs for a total of 6.601 MMBoe. PUDs are converted from undeveloped to developed as the applicable wells are drilled, completed and begin production.

Changes in PUDs that occurred during 2016 were due to (i) negative revisions of 1.780 MMBoe primarily related to pricing and revisions and (ii) additions of approximately 4.283 MMBoe in wells attributable to discovery and extensions resulting from strategic drilling of wells by us and offset operators to our acreage positions. No capital was spent during 2016 to convert PUDs and no PUDs were converted from undeveloped to developed during 2016 as a result of our decreasing its capital spending during the year. We do not believe our decision to reduce 2016 capital expenditures in response to decreases in commodity prices will impact our ability to develop our PUDs in a timely manner.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.

Year Ended December 31, 2015

As of December 31, 2015, our PUDs totaled 2.954 MMBbls of oil, 3.783 Bcf of natural gas and 0.513 MMbls of NGLs for a total of 4.098 MMBoe. PUDs are converted from undeveloped to developed as the applicable wells are drilled, completed and begin production.

Changes in PUDs that occurred during 2015 were primarily due to (i) negative revisions of 5.426 MMBoe primarily related to pricing and type curve revisions and (ii) an increase of approximately 3.456 MMBoe attributable to extensions and promotions resulting from strategic drilling of wells by us to delineate our acreage position. No capital was spent during 2015 to convert PUDs and no PUDs were converted from undeveloped to

 

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developed during 2015 as a result of our decreasing our capital spending during the year. We do not believe our decision to reduce 2015 capital expenditures in response to decreases in commodity prices will impact our ability to develop our PUDs in a timely manner.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.

Year Ended December 31, 2014

As of December 31, 2014, our PUDs totaled 3.089 MMBbls of oil, 8.869 Bcf of natural gas and 1.501 MMBls of NGLs for a total of 6.068 MMBoe. PUDs are converted from undeveloped to developed as the applicable wells are drilled, completed and begin production.

Changes in PUDs that occurred during 2014 were primarily due to (i) a decrease of approximately 1.032 MMBoe due to revisions; (ii) additions of approximately 4.266 MMBoe in wells attributable to extensions, discoveries and promotions resulting from strategic drilling of wells by us to delineate our acreage position; and (iii) the conversion of approximately 1.170 MMBoe into proved developed reserves.

All of our PUD drilling locations are scheduled to be drilled within five years of their initial booking.

Current Development Program

At the time of initial booking, our PUDs were a part of an approved plan to develop those reserves. However, after a development plan has been adopted, we periodically makes adjustments to the approved development plan due to events or circumstances that have occurred subsequent to the time the plan was approved. Primarily as a result of factors outside our control, including a downturn in commodity prices, we adjusted our development plan to temporarily defer the drilling of certain PUD locations. As a result, no PUDs were converted from undeveloped to developed during 2015 and 2016. However, we continue to believe with reasonable certainty that these PUDs will be developed within five years of their initial booking.

As of December 31, 2016, we had 13 PUD locations booked. Of these 13 PUD locations, one location was originally booked at December 31, 2014, six locations were originally booked at December 31, 2015 and six locations were originally booked at December 31, 2016. Our development plan provides for the drilling of four wells associated with the PUD locations in 2017, two of which are currently being drilled, while drilling is planned to commence on the other two wells in the third and fourth quarters of 2017, respectively. We believe that our progress to date in 2017 demonstrates our ability to execute on our development plan. Our development plan sets forth the remaining nine wells associated with the PUD locations to be brought to proved producing status within five years of initial booking, with eight of these nine wells planned to be drilled over the next three years.

As of December 31, 2016, we estimated that the cost to bring these wells to a status of economic productivity would be approximately $6.25 million per location for a total cost of $81.3 million to execute our development program. Based on costs incurred in connection with the drilling of two wells associated with PUD locations in 2017, we believe these cost estimates remain accurate. We are the operator of 12 of the identified 13 PUD locations and directly control the timing of development of such locations. The one non-operated location is currently being drilled. Our ability to fund our development plan is supported by the cash flow generated by its producing properties. In addition, as we convert reserves from undeveloped status to producing status, the borrowing base under our reserve-based revolving credit facility will increase, providing additional liquidity with which to finance further development. At the time the PUDs were booked, we also considered the fact that our ultimate parent company, Rosemore, Inc., had from time to time in the past provided supplemental capital support to fund the capital program and had the ability to do so in the future, although it was under no obligation to do so. Following the completion of the Business Combination, we became a subsidiary of the Company, and we expect to be able to fund our development going forward through cash flows from operations, borrowings under our revolving credit facility, and our ability to access the capital markets.

 

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We believe all of the foregoing demonstrates reasonable certainty with regard to the development of our PUDs within five years of their initial booking.

Oil and Natural Gas Production Prices and Costs

Production and Price History

The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:

 

		Year Ended December 31,
		2016				2015				2014
Production data:
Oil (MBbls)			612				472				365
Natural gas (MMcf)			2,381				2,074				1,834
NGLs (MBbls)			358				312				285
Total (MBoe)(1)			1,367				1,130				956
Average realized prices before effects of derivative settlements:
Oil (per Bbl)		$	40.52			$	43.62			$	77.93
Natural gas (per Mcf)			2.23				2.37				4.06
NGLs (per Bbl)			12.68				12.75				26.93
Total (per Boe)		$	25.35			$	26.09			$	45.58
Total, including effects of derivative settlements (per Boe)		$	22.30			$	29.40			$	48.10
Average costs (per Boe):
Lease operating expenses		$	3.51			$	4.06			$	6.39
Production taxes			1.13				1.16				1.95
Gathering and transportation			1.75				1.85				2.58
Depreciation, depletion and amortization			18.14				20.57				16.58
Accretion of asset retirement obligations			0.13				0.11				0.13
Impairment of oil and natural gas properties			—				7.20				28.87
Exploration costs			0.58				0.85				1.00
General and administrative expenses			6.58				3.75				5.39
Gain on sale of oil and natural gas properties			—				—				(0.01	)
(Gain) loss on sale of other assets			(0.04	)			0.02				(0.03	)
Total(1)		$	31.78			$	39.57			$	62.85

 

(1)	May not sum or recalculate due to rounding.

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2016 relating to our Delaware Basin leasehold acreage. All of our Barnett Shale leasehold acreage in Wise County, Texas is developed. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.

 

Delaware Basin Leasehold

Developed Acreage

Undeveloped Acreage

Total Acreage

Gross(1)

Net(2)

Gross(1)

Net(2)

Gross(1)

Net(2)

4,577

2,464

2,735

2,325

7,312

4,789

 

(1)	A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

 

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(2)	A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. Substantially all of the leases governing our acreage have continuous development clauses that permit us to continue to hold the acreage under such leases after the expiration of the primary term if we initiate additional development within 120 to 180 days after the completion of the last well drilled on such lease, without the requirement of a lease extension payment. Thereafter, the lease is held with additional development every 120 to 180 days until the entire lease is held by production. None of our horizontal drilling locations associated with proved undeveloped reserves are scheduled for drilling outside of a lease term that is not accounted for with a continuous development schedule. The following table sets forth the gross and net undeveloped acreage as of December 31, 2016 that will expire over the next five years, unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates.

 

2017						2018								2019								2020								2021
Gross		Net				Gross				Net				Gross				Net				Gross				Net				Gross				Net
221			221				1,297				1,091				—				—				—				—				—				—

Drilling Results

The following table sets forth our results, as defined by wells having been placed on production, for the periods indicated for operated and non-operated wells. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, quantities of reserves found, or economic value. Productive wells are those that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are those that prove to be incapable of producing hydrocarbons in sufficient quantities to justify completion.

 

		For the Year Ended December 31,
		2016				2015				2014
Exploratory Wells:
Productive(1)			3				2				5
Dry			—				—				—
Total Exploratory			3				2				5
Development Wells:
Productive(1)			2				1				4
Dry			—				—				—
Total Exploratory			2				1				4
Total Wells
Productive(1)			5				3				9
Dry			—				—				—

 

(1)	Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells where there is no production history.

 

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Operations

General

We design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. Independent contractors engaged by us provide all the equipment and personnel associated with these activities. We employ petroleum engineers, geologists and land professionals who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties.

Marketing and Customers

With respect to core properties we operate in Loving County, Texas, we maintain contracts with Gateway to gather the majority of our production. We deliver crude oil, natural gas, and NGL production to Gateway and Gateway transports and redelivers the oil, natural gas, and NGLs to certain delivery points. We sell all of our natural gas and NGLs under contracts with terms generally greater than twelve months and all of our oil under contracts with terms generally less than twelve months.

On the Weber 26 Lease in Loving County, Texas, we sell our crude oil to Rio Energy International with an initial three-month contract, month-to-month thereafter, and our natural gas to Outrigger Delaware Operating LLC, a midstream gas gathering and transportation company, with a five-year gas purchase contract. Gateway does not provide gathering services on the Weber 26 Lease.

With respect to the properties we operate in Wise County, Texas, we sell our crude oil production to Targa Midstream Services and sells our natural gas to Enlink Midstream Services. Gateway does not provide gathering services with respect to the Barnett Shale properties.

We sell our production to a relatively small number of customers, as is customary in the industry. For the year ended December 31, 2016, Gateway, ETC Field Services, LLC and Enlink Midstream Services, LLC accounted for 70%, 17% and 10%, respectively, of total revenues related to us. For the year ended December 31, 2015, Gateway, Sunoco Inc., Enlink Midstream Services, LLC and Regency Energy Partners LP accounted for 54%, 13%, 11% and 11%, respectively, of total revenues related to us. For the year ended December 31, 2014, Enterprise Crude Pipeline, LLC, Sunoco Inc., Devon Gas Services, LP, and Regency Energy Partners LP accounted for 33%, 32%, 18% and 11%, respectively, of total revenues related to us. The loss of any one or all of our significant customers as a purchaser could materially and adversely affect our revenues in the short-term. However, based on the current demand for oil and natural gas and the availability of other purchasers, we believe that the loss of any of our significant customers as a purchaser would not have a material adverse effect on our financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Transportation

Production from our core properties in Loving County, Texas is delivered to our production facilities and then transported through Gateway’s Raven Pipeline to the interconnection between Raven Pipeline and Plains Pipeline. In connection with the Business Combination, we and Gateway entered into a Crude Oil Gathering Agreement for a period of ten years.

Our natural gas production is delivered to our production facilities and then transported through Gateway’s LCGS to the interconnection between LCGS Pipeline and ETC Field Services Pipeline. The gas is sold by us to ETC Field Services at the interconnection between LCGS pipeline and ETC Field Services. Gateway provides transportation on the LCGS pipeline. ETC Field services transports the gas to their processing facility. We do not control Gateway’s or any other third party’s transportation facilities. In connection with the Business Combination, we and Gateway have entered into a Gas Gathering Agreement for a period of ten years.

 

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During the further development of our properties, we expect to consider all gathering and delivery infrastructure options in the areas of our production. However, Gateway will have a right of first refusal to build gathering and delivery infrastructure for our properties in Loving County, Texas.

For descriptions of the Crude Oil Gathering Agreement and Gas Gathering Agreement, please read the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Related Party Transactions”.

Competition

The oil and natural gas industry is intensely competitive and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

There is also competition between oil and natural gas producers and other industries producing energy and fuel. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation and/or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation, which may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing and future federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Demand for oil and natural gas is typically higher in the fourth and first quarters, resulting in higher prices. Due to these seasonal fluctuations, results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties in connection with acquisition of leasehold acreage. At such time as we determines to conduct drilling operations on those properties, we conduct a thorough title examination and performs curative work with respect to significant defects prior to commencement of drilling operations. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry.

 

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Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we have satisfactory title to all of our material assets, including those being contributed to us. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects as described in this prospectus.

Oil and Natural Gas Leases

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.5% to 25%, resulting in a net revenue interest to us generally ranging from 75% to 87.5%.

Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state, and local laws and regulations. In particular, natural gas production and related operations are, or have been, subject to price controls, taxes, and numerous other laws and regulations. All of the jurisdictions in which we own or operate producing oil and natural gas properties have statutory provisions regulating the development and production of oil and natural gas, including provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.

Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. We are therefore unable to predict the future costs or impact of compliance. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, FERC, other Federal agencies and the courts. We cannot predict when or whether any such proposals may become effective.

We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur and past non-compliance with environmental laws or regulations may be discovered.

 

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The disclosures below as to the regulation of the oil and natural gas industry are applicable to us.

Regulation of Production of Oil and Natural Gas

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in Texas and New Mexico, which regulate drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density and the plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, states impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within our jurisdiction.

The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect its operations.

Regulation of Sales and Transportation of Oil

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.

Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost-based, although settlement rates agreed to by all shippers are permitted and market-based rates may be permitted in certain circumstances.

Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect its operations in any way that is of material difference from those of our competitors who are similarly situated.

Regulation of Transportation and Sales of Natural Gas

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”) and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.

 

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The EP Act of 2005 amends the NGA to add an anti-market manipulation provision that makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC Pursuant to the EP Act of 2005, FERC promulgated regulations that make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, use, or employ any device, scheme, or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements described below.

The EP Act of 2005 also provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increases FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1,000,000 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. Under FERC’s regulations, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices, and whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC as a natural gas company under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, and, depending on the scope of that decision, our costs of transporting gas to point of sale locations may increase. we believe that the third-party natural gas pipelines on which our gas is gathered meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of those gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

With regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”) and regulations promulgated thereunder by the U.S. Commodity Futures Trading Commission. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures or derivative contracts on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity, as well as any manipulative or deceptive device or contrivance in connection with any contract of sale of any commodity in interstate commerce or futures or derivative contract on such commodity. Should we violate the anti-market manipulation laws and regulations, they could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

 

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Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ships our natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenue we receive for sales of its our natural gas.

Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect it in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.

Regulation of Environmental and Occupational Safety and Health Matters

Our oil and natural gas development operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health, the discharge of materials into the environment or otherwise relating to environmental protection, some of which carry substantial administrative, civil and criminal penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or other regulated activity commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production and transporting through pipelines; govern the sourcing and disposal of water used in the drilling and completion process; limit or prohibit drilling activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas; require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits; establish specific safety and health criteria addressing worker protection; and impose substantial liabilities for pollution resulting from operations or failure to comply with regulatory filings. In addition, these laws and regulations may restrict the rate of production.

The following is a summary of the more significant existing environmental and occupational health and safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.

Hazardous Substances and Waste Handling

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Although petroleum substances such as crude oil and natural gas are excluded from the definition of hazardous substances under CERCLA, various substances used in drilling and production operations are not covered by this exclusion and releases of these non-excluded substances or petroleum substances could give rise to CERCLA liability. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances or petroleum released into the environment. We are only able to directly

 

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control the operation of those wells for which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the liability of an operator other than us for releases may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances, but we are unaware of any liabilities for which it may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, in the course of their operations, we may generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics or are listed hazardous wastes. In addition, even wastes excluded from the definition of hazardous waste may be regulated by the EPA or state agencies under, state laws or other federal laws. Moreover, it is possible that those particular oil and natural gas development and production wastes now excluded from the definition of hazardous wastes could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA’s exclusion of certain oil and gas wastes from RCRA. In one such challenge, the U.S. District Court for the District of Columbia entered a consent decree requiring EPA to evaluate the exclusion and, by March 2019, to either sign a notice of proposed rulemaking revising the regulations excluding oil and gas wastes or sign a determination that revision of the exclusion is not necessary. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes, if EPA were to eliminate the exclusion, could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.

We currently owns, leases, or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property, or performance of remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. To the extent the rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of the Clean Water Act, and implementation of the rule has been stayed pending resolution of the court

 

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challenge. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of pollutants in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

In addition, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations and further believes we are in substantial compliance with the terms thereof. We are currently undertaking a review of all properties to determine the need for new or updated SPCC plans, and, where necessary, we will be developing or upgrading such plans and implementing the physical and operation controls imposed by these plans, the costs of which are not expected to be substantial.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Air Emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit its ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. More recently, in May 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

 

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Regulation of GHG Emissions

In response to findings that emissions of carbon dioxide, methane, and other GHG present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that otherwise require such permits for non-GHG emissions. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Furthermore, in May 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category, including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. The EPA has also announced that it intends to impose methane emission standards for existing sources as well but, to date, has not yet issued a proposal. Compliance with these rules will require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities to address emissions leakage. The rules will also likely require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance. These new and proposed rules could result in increased compliance costs on our operations.

While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues. Most recently in April 2016, the United States was one of 175 countries to ratify the Paris Agreement, which requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce. Finally, it should be noted that some scientists, reportedly a majority who have studied the issue, have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts, and other climatic events. Our operations are onshore and not located in coastal or flood-prone regions of the United States, but if any such effects were to occur at our locations, these effects have the potential to cause physical damage to our assets or affect the availability of water for our operations and thus could have a material adverse effect on our operations.

Hydraulic Fracturing Activities

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly uses hydraulic fracturing as part of its operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act (“SDWA”) over certain hydraulic fracturing

 

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activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The EPA has also issued final regulations under the federal Clean Air Act establishing performance standards, including standards for the capture of air emissions released during hydraulic fracturing, and advance notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding chemicals used in hydraulic fracturing. EPA also finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. In addition, the Bureau of Land Management (“BLM”) finalized rules in March 2015 that impose new or more stringent standards for performing hydraulic fracturing on federal and American Indian lands. The U.S. District Court of Wyoming set aside the rules as beyond BLM’s jurisdiction to promulgate. The district court’s decision is on appeal to the Tenth Circuit, with oral argument scheduled for March 2017.

In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing activities under the SDWA and to enact statutes requiring disclosure of the chemicals used in the hydraulic fracturing process. It is unclear whether the available information justifies repeal of the SDWA exemption for the hydraulic fracturing injection itself or how any additional federal regulation of hydraulic fracturing activities, if enacted, would affect our operations.

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from drilling wells.

ESA and Migratory Birds

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered or proposed for listing are known to exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the Agency’s 2017 fiscal year. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The federal government recently issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could

 

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have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as a critical or suitable habitat, it could adversely impact the value of our leases.

OSHA

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state, and local governmental authorities and citizens. We believe that we are in substantial compliance with all applicable laws and regulations relating to worker health and safety.

Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other oil and natural gas activities, and to maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.

We have not experienced any material adverse effect from compliance with environmental requirements; however, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2015 or 2016, nor do we anticipate that such expenditures of ours will be material in 2017.

Related Insurance

We maintain insurance against some risks associated with the release of contaminants that may occur as a result of its development activities. However, this insurance is limited in scope, and there can be no assurance that this insurance will continue to be commercially available, will be adequate to cover a loss, or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.

Employees

As of December 31, 2016, we had 30 employees, all of whom were full-time. We hire independent contractors on an as needed basis. We have no collective bargaining agreements with its employees.

Legal Proceedings

We are a party to lawsuits arising in the ordinary course of its business. We cannot predict the outcome of any such lawsuits with certainty, but management believes our is remote that pending or threatened legal matters will have a material adverse impact on its financial condition.

Due to the nature of our business, we expect to be, from time to time, involved in other routine litigation or subject to disputes or claims related to their business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, none of these other pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.

Price Range of Securities

Historical market price information regarding us is not provided because there is no public market for our units.

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial Information” and the accompanying carve-out financial statements of the Assets and Liabilities of the Business Contributed to Rosehill Operating Company, LLC and related notes included elsewhere in this prospectus. 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 of our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and natural gas liquids (“NGLs”), production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We have no direct operations and no significant assets other than an ownership interest in Rosehill Operating. Rosehill Operating is considered our accounting predecessor and, accordingly, the following financial results and discussion and analysis reflect the results of Rosehill Operating prior to the closing of the Business Combination.

We are an independent oil and natural gas company focused on the development and acquisition of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin and in the Fort Worth Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Rosehill Operating has established commercial production in the Delaware Basin in four distinct formations: the Upper Avalon, Lower Avalon, Wolfcamp A (XY Sand) and Lower Wolfcamp A Shale. As of December 31, 2016, we also operate 18 vertical and 21 horizontal wells in the Barnett Shale in the Fort Worth Basin.

Market Conditions

The oil and natural gas industry is cyclical and commodity prices are highly volatile. In the second half of 2014, oil prices began a rapid and significant decline as the global oil supply began to outpace demand. During 2015 and 2016, the global oil supply continued to outpace demand, resulting in a sustained decline in realized prices for oil production. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including the efforts of Russia and Saudi Arabia to retain market share, combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begin to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward pressure to oil prices. NGL prices generally correlate to the price of oil. Also adversely affecting NGL prices is the supply of NGLs in recent years. Prices for domestic natural gas began to decline during the third quarter of 2014 and continued to be weak throughout 2015 and 2016. This decline is primarily due to an imbalance between supply and demand across North America. The duration and magnitude of commodity price declines cannot be accurately predicted.

Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production, as well as NGLs that are extracted from our natural gas during processing.

 

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Compared to 2014, our average realized oil price for 2015 fell 44% to $43.62 per barrel, and our average realized price for the year ended December 31, 2016 has further decreased to $40.52 per barrel. Similarly, our average realized natural gas price for 2015 dropped 42% to $2.37 per Mcf, and our average realized price for NGLs declined 53% to $12.75 per barrel. For the year ended December 31, 2016, our average realized price for natural gas was $2.23 per Mcf, and our average realized price for NGLs was $12.68 per barrel. Lower oil, natural gas and NGL prices may not only decrease our revenues but may also reduce the amount of oil, natural gas and NGLs that we can produce economically, which may consequently reduce our oil, natural gas, and NGL reserves. Lower commodity prices in the future could result in impairments of its properties and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity, or ability to finance planned capital expenditures. Lower oil, natural gas, and NGL prices may also reduce the borrowing base under our credit agreements, which may be determined at the discretion of the lenders and is on the collateral value of our proved reserves that have been mortgaged to the lenders. Alternatively, higher oil and natural gas prices may result in significant non-cash fair value losses being incurred on our commodity derivatives, which could cause us to experience net losses when oil and natural gas prices rise.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of its oil and natural gas operations, including:

 

•

realized prices on the sale of oil, natural gas, and NGLs, including the effect of our commodity derivative contracts on our oil and natural gas production;

 

•

production results;

 

•

lease operating expenses; and

 

•

Adjusted EBITDAX.

See “—Sources of Our Revenues,” “—Production Results,” “—Operating Costs and Expenses,” “—Adjusted EBITDAX” below for a discussion of these metrics.

Sources of Our Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. Oil sales contributed 72% of our total revenues for the year ended December 31, 2016. Natural gas sales contributed 15% and NGL sales contributed 13% of our total revenues for the year ended December 31, 2016. Its oil, natural gas, and NGL revenues do not include the effects of commodity derivatives.

Increases or decreases in our revenue, profitability, and future production growth are highly dependent on the commodity prices we receives. Oil, natural gas, and NGL prices are market driven and have been historically volatile, and we expect that future prices will continue to fluctuate due to supply and demand factors, seasonality, and geopolitical and economic factors. See “—Market Conditions” for information regarding the current commodity price environment. A 10% per barrel change in our realized oil price would have resulted in a $2.5 million change in oil revenues for the year ended December 31, 2016. A 10% per Mcf change in our realized natural gas price would have resulted in a $0.5 million change in our natural gas revenues for the year ended December 31, 2016. A 10% per barrel change in NGL prices would have changed revenue by $0.5 million for the year ended December 31, 2016.

 

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The following table presents our average realized commodity prices.

 

		Year Ended December 31,
		2016				2015				2014
Crude Oil (per Bbl):
Average realized price, before the effects of cash settled commodity derivatives		$	40.52			$	43.62			$	77.93
Natural Gas (per Mcf):
Average realized price, before the effects of cash settled commodity derivatives			2.23				2.37				4.06
NGLs (per Bbl):
Average realized price, before the effects of cash settled commodity derivatives			12.68				12.75				26.93

While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within our industry, the prices we receive are affected by quality, energy content, transportation fees, and regional price differentials for these products.

See “—Results of Operations” below for an analysis of the impact changes in realized prices had on our revenues.

Production Results

The following table presents historical production volumes for our properties for the years ended December 31, 2016, 2015, and 2014:

 

		Year Ended December 31,
		2016				2015				2014
Oil (MBbls)			612				472				365
Natural gas (MMcf)			2,381				2,074				1,834
NGLs (MBbls)			358				312				285
Total (MBoe)(1)			1,367				1,130				956
Average net daily production (Boe/d)(1)			3,734				3,096				2,618

 

(1)	May not sum or recalculate due to rounding.

As reservoir pressures decline, production from a given well or formation decreases. Growth in our future production and reserves will depend on our ability to continue to add proved reserves in excess of our production. Accordingly, our plans to maintain our focus on adding reserves through drilling as well as acquisitions. Our ability to add reserves through development projects and acquisitions is dependent on many factors, including our ability to borrow or raise capital, obtain regulatory approvals, procure contract drilling rigs and personnel and successfully identify and consummate acquisitions. Please read “Risk Factors—Risks Related to Our Operations” for a discussion of these and other risks affecting our proved reserves and production.

Derivative Activity

To achieve a more predictable cash flow and reduce exposure to adverse fluctuations in commodity prices, we have historically used commodity derivative instruments, such as collars, swaps, and basis swaps, to hedge price risk associated with a portion of our anticipated oil and natural gas production. By removing a significant portion of the price volatility associated with our oil and natural gas production, we believe we will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, in a portion of our current positions, hedging activity may also reduce our

 

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ability to benefit from increases in oil and natural gas prices. We will sustain losses to the extent our commodity derivative contract prices are lower than market prices and, conversely, we will sustain gains to the extent we commodity derivative contract prices are higher than market prices. In certain circumstances, where we have unrealized gains in our commodity derivatives portfolio, we may choose to restructure existing commodity derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions. See “—Quantitative and Qualitative Disclosure About Market Risk—Commodity Price Risk” for information regarding our exposure to market risk, including the effects of changes in commodity prices, and its commodity derivative contracts.

We have historically relied on commodity derivative contracts to mitigate our exposure to lower commodity prices, and we expect to continue to utilize commodity derivative instruments to hedge price risk in the future. From time to time, we have been able to hedge our oil and natural gas production at prices that are higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements at favorable prices may be limited. Our hedging strategy and future hedging transactions will generally be determined at our discretion and may be different than what we have done on a historical basis.

As a result of recent volatility in the price of oil and natural gas, we have relied on a variety of hedging strategies and instruments to hedge future price risk. We have utilized swaps, put options and call options to reduce the effect of price changes on a portion of our oil and natural gas production.

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract value.

A put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.

A call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.

 

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Below is a summary of our open commodity derivative instrument positions for 2017 and beyond as of December 31, 2016, by product and strategy:⁴

 

		Three Months Ended
		3/31/17				6/30/17				9/30/17				12/31/17
NYMEX WTI(1) Crude Swaps:
Notional volume (Bbl)			100,000				71,000				66,000				36,000
Weighted average fixed price ($/Bbl)		$	48.98			$	51.58			$	53.35			$	55.43
NYMEX WTI(1) Crude Options:
Puts:
Notional volume (Bbl)			88,000				120,000				84,000				42,000
Weighted average fixed price ($/Bbl)		$	43.37			$	43.75			$	43.00			$	40.00
Calls:
Notional volume (Bbl)			32,000				40,000				—				—
Weighted average fixed price ($/Bbl)		$	65.00			$	65.00			$	—			$	—
NYMEX HH(2) Natural Gas Swaps:
Notional volume (Mcf)			250,000				450,000				300,000				480,000
Weighted average fixed price ($/Mcf)		$	3.26			$	3.13			$	3.08			$	3.15
NYMEX HH(2) Natural Gas Options:
Puts:
Notional volume (Mcf)			560,000				420,000				660,000				60,000
Weighted average fixed price ($/Mcf)		$	2.94			$	2.88			$	2.87			$	2.90
Calls:
Notional volume (Mcf)			280,000				210,000				330,000				30,000
Weighted average fixed price ($/Mcf)		$	3.61			$	3.60			$	3.72			$	3.90

 

(1)	NYMEX WTI refers to West Texas Intermediate crude oil price on the New York Mercantile Exchange.

(2)	NYMEX HH refers to Henry Hub natural gas price on the New York Mercantile Exchange.

The following table summarizes our historical derivative positions and the settlement amounts for each of the periods indicated:

 

Commodity Swaps		Year Ended December 31, 2016				Year Ended December 31, 2015				Year Ended December 31, 2014
Oil Swap:
Vol (Bbls)			173,000				13,000				50,000
Weighted avg fixed price		$	42.15			$	54.58			$	93.54
Natural gas Swap:
Vol (Mcf)			720,000				—				90,000
Weighted avg fixed price		$	2.69				—			$	4.30
NGL Swap:
Vol (Bbls)			42,000				89,000				136,000
Weighted avg fixed price		$	14.73			$	13.38			$	23.63

 

 

4	NTD: Company to confirm whether all derivative instruments transferred.

 

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Commodity Swaps		Year Ended December 31, 2016				Year Ended December 31, 2015				Year Ended December 31, 2014
Options
Oil Options:
Sold Puts:
Vol (Bbls)			140,000				517,000				149,000
Weighted avg fixed price		$	56.83			$	55.91			$	87.02
Purchased Puts:
Vol (Bbls)			140,000				517,000				149,000
Weighted avg fixed price		$	47.32			$	48.25			$	79.83
Sold Calls:
Vol (Bbls)			—				—				97,000
Weighted avg fixed price		$	—			$	—			$	99.38
Purchased Calls:
Vol (Bbls)			—				—				97,000
Weighted avg fixed price		$	—			$	—			$	103.44
Natural gas Options:
Sold Puts:
Vol (Mcf)			960,000				2,440,000				590,000
Weighted avg fixed price		$	2.65			$	3.64			$	4.14
Purchased Puts:
Vol (Mcf)			960,000				2,440,000				590,000
Weighted avg fixed price		$	2.31			$	2.94			$	3.77
Sold Calls:
Vol (Mcf)			120,000				—				570,000
Weighted avg fixed price		$	3.57			$	—			$	4.05
Purchased Calls:
Vol (Mcf)			120,000				—				570,000
Weighted avg fixed price		$	3.76			$	—			$	4.72

We are not, and we are not expected to be, under an obligation to hedge a specific portion of its production. Tema’s hedging instruments were either transferred to us or settled at the closing of the Business Combination.

Commodity derivative instruments are recognized on the balance sheet as either assets or liabilities measured at fair value. We have not elected to apply cash flow hedge accounting, and consequently, recognizes gains and losses in earnings rather than deferring such amounts in other comprehensive income as allowed under cash flow hedge accounting. Fair value gains or losses, as well as cash receipts or payments on settled commodity derivative contracts, are recognized in our results of operations. Cash flows from commodity derivatives are reported as cash flows from operating activities. These gains and losses have been allocated to us for the purpose of the our financial statements.

Operating Costs and Expenses

Costs associated with producing oil, natural gas, and NGLs are substantial. Some of these costs vary with commodity prices, some trend with the type and volume of production, and others are a function of the number of wells we own. As of December 31, 2016 and December 31, 2015, we owned interests in 69 and 64 gross wells, respectively.

Lease Operating Expenses. Lease operating expenses (“LOE”) are the costs incurred in the operation of producing properties and workover costs. Expenses for direct labor, water/gas injection, water disposal, compressor rental, and chemicals comprise the most significant portion of our LOE. Certain items, such as direct labor and compressor rental, generally remain relatively fixed across broad production volume ranges, but can

 

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fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities result in increased LOE in periods during which they are performed. Certain of our operating cost components are variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we incur water disposal costs in connection with various production-related activities, such as trucking water for disposal until connection can be made to a water disposal well.

We monitor our operations to ensure that we are incurring LOE at an acceptable level. For example, we monitor our LOE per Boe to determine if any wells or properties should be shut in, recompleted, or sold. This unit rate also allows us to monitor these costs in certain fields and geographic areas to identify trends and to benchmark against other producers. Although we strive to reduce our LOE, these expenses can increase or decrease on a per unit basis as a result of various factors as we operate our properties or makes acquisitions and dispositions of properties. For example, we may increase field level expenditures to optimize our operations, incurring higher expenses in one quarter relative to another, or we may acquire or dispose of properties that have different LOE per Boe. These initiatives would influence our overall operating cost and could cause fluctuations when comparing LOE on a period to period basis.

We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and natural gas properties, which also trend with oil and natural gas prices.

Production Taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from production sold at fixed rates established by federal, state, or local taxing authorities. In general, the production taxes we pay correlate to the changes in oil, natural gas, and NGL revenues.

Gathering and Transportation Expense. Gathering and transportation expense principally consists of expenditures to prepare and transport production from the wellhead to a specified sales point and gas processing costs. These costs will fluctuate with increases or decreases in production volumes, contractual fees, and changes in fuel and compression costs.

Depreciation, Depletion, and Amortization. Depreciation, depletion, and amortization (“DD&A”) is the systematic expensing of the capitalized costs incurred to acquire and develop oil and natural gas properties. We use the successful efforts method of accounting for oil and natural gas activities, and, as such, we capitalize all costs associated with our development and acquisition efforts and all successful exploration efforts, which are then allocated to each unit of production using the unit of production method. Please read “—Critical Accounting Policies and Estimates—Successful Efforts Method of Accounting for Oil and Natural Gas Activities” for further discussion.

Accretion Expense. Accretion expense is the periodic accreting of the present value of the estimated asset retirement liability to reflect the passage of time.

Impairment Expense. We review our proved properties and unproved leasehold costs for impairment whenever events and changes in circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Impairment is reviewed and recorded on a property-by-property basis. Please read “—Critical Accounting Policies and Estimates—Impairment of Oil and Natural Gas Properties” for further discussion.

General and Administrative Expenses. General and administrative (“G&A”) expenses are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining its headquarters, costs of managing our production and development operations, audit and other fees for professional services, and legal compliance. A portion of these expenses have been allocated to us (on the basis of direct usage when identifiable with the remainder allocated proportionately on a Boe basis) for the purpose of our carve-out financial statements.

 

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Interest Expense, Net. We have financed a portion of its working capital requirements and capital expenditures with borrowings under our secured line of credit. As a result, we have incurred interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest paid to lenders under the secured line of credit is reflected in interest expense, net. These expenses have been allocated to us for purposes of the our carve-out financial statements.

Adjusted EBITDAX

We define Adjusted EBITDAX as net income (loss) before interest expense, income taxes, DD&A, accretion and impairment of oil and natural properties, (gains) losses on commodity derivatives excluding net cash receipts (payments) on settled commodity derivatives, gains and losses from the sale of assets, and other non-cash operating items.

We believe Adjusted EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of its operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within the industry depending upon accounting methods and book values of assets, capital structures, and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. For further discussion, please read “Selected Historical Financial Information of Us—Non-GAAP Financial Measure.”

Factors Affecting the Comparability of Our Future Financial Data Attributable to Rosehill Operating to the Historical Financial Results of Rosehill Operating’s Operations

The future results of our operations after the Business Combination attributable to Rosehill Operating may not be comparable to the historical results of operations of Rosehill Operating for the periods presented due to the following reasons:

Income Taxes. Rosehill Operating is a limited liability company electing to be taxed as a partnership and, therefore, it will not incur entity level tax. Subject to certain restrictions, we generally will be required to make pro rata distributions to our members in an amount at least sufficient to allow them to pay their taxes. Such distributions will reduce the cash available to be used in Rosehill Operating’s business.

Public Company Expenses. We incur direct G&A expense as a result of being a publicly traded company, including, but not limited to, costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, and independent director compensation. These direct G&A expenses are not included in Rosehill Operating’s historical financial results of operations.

 

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Results of Operations

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

Oil, Natural Gas, and NGL Sales Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period’s respective average prices and production volumes:

 

		Year Ended December 31,
		2016				2015				Change				Change %
		(Unaudited)
Revenues (in thousands):
Oil sales		$	24,807			$	20,601			$	4,206				20	%
Natural gas sales			5,304				4,909				395				8	%
NGL sales			4,534				3,977				557				14	%
Gain (loss) on commodity derivatives, net			(4,169	)			3,735				(7,904	)			(212	%)
Total revenues		$	30,476			$	33,222			$	(2,746	)			(8	%)
Average sales price (1):
Oil (per Bbl)		$	40.52			$	43.62			$	(3.10	)			(7	%)
Natural gas (per Mcf)			2.23				2.37				(0.14	)			(6	%)
NGL (per Bbl)			12.68				12.75				(0.07	)			(1	%)
Total (per Boe)		$	25.35			$	26.09			$	(0.74	)			(3	%)
Total, after effects of gain (loss) from commodity derivatives (per Boe)		$	22.30			$	29.40			$	(7.10	)			(24	%)
Production:
Oil (MBbls)			612				472				140				30	%
Natural gas (MMcf)			2,381				2,074				307				15	%
NGL (MBbls)			358				312				46				15	%
Total (MBoe)(2)			1,367				1,130				237				21	%
Average daily production volume:
Oil (Bbl/d)			1,673				1,294				379				29	%
Natural gas (Mcf/d)			6,506				5,683				823				14	%
NGL (Bbls/d)			977				855				122				14	%
Total (per Boe/d)(2)			3,734				3,096				638				21	%

 

(1)	Average prices shown in the table reflect prices before the effects of realized commodity derivative transactions.

(2)	Totals may not sum or recalculate due to rounding.

As reflected in the table above, our total revenues for 2016 were 8% lower, or $2.7 million, as compared to 2015. The decrease was primarily due to a 212%, or $7.9 million, decrease in gain (loss) on commodity derivatives, net. The decrease in commodity prices that resulted in a 3% decrease in the average sales price per Boe, or $1.8 million ($0.74 per Boe), was offset by a 21% increase in average daily production, or $6.9 million (237 MBoe), as compared to the prior year. The increase in average daily production was attributable to four operated and one non-operated new wells coming on line during the year ended December 31, 2016.

Oil sales for 2016 as compared to 2015 increased 20%, or $4.2 million, primarily due to a 30% increase in oil production (140 MBbls), or $5.7 million, offset by a 21% decrease in the average sales price for oil ($3.10 per Bbl), or $1.5 million. Natural gas sales for 2016 as compared to 2015 increased 8%, or $0.4 million, primarily due to a 15% increase in natural gas production (307 MMcf), or $0.7 million, offset by a 6% decrease in the

 

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average sales price for natural gas ($0.14 per Mcf), or $0.3 million. NGL sales for 2016 as compared to 2015 increased 14%, or $0.6 million, primarily due to a 15% increase in NGL production (46 MBbls), or $0.6 million.

During 2016, we recognized a $4.2 million commodity derivative loss as compared to a $3.7 million commodity derivative gain in 2015. Net gains and losses on our commodity derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

Operating Expenses. Per Boe information is presented by us because we use this information to evaluate our performance relative to our peers and to identify and measure trends we believes may require additional analysis.

The following table summarizes our expenses for the periods indicated:

 

		Year Ended December 31,
		2016				2015				Change				Change %
		(Unaudited)
Operating expenses (in thousands):
Lease operating expenses		$	4,800			$	4,582			$	218				5	%
Production taxes			1,541				1,311				230				18	%
Gathering and transportation expenses			2,398				2,094				304				15	%
Depreciation, depletion and amortization			24,789				23,244				1,545				7	%
Accretion expense			176				120				56				47	%
Impairment of oil and gas properties			—				8,131				(8,131	)			(100	%)
Exploration costs			794				960				(166	)			(17	%)
General and administrative expenses			9,000				4,234				4,766				113	%
Loss on sale of other assets			(50	)			18				(68	)			(378	%)
Total operating expenses before other miscellaneous (income) expense		$	43,448			$	44,694			$	(1,246	)			(3	%)
Operating expenses per Boe:
Lease operating expenses		$	3.51			$	4.06			$	(0.55	)			(14	%)
Production taxes			1.13				1.16				(0.03	)			(3	%)
Gathering and transportation expenses			1.75				1.85				(0.10	)			(5	%)
Depreciation, depletion and amortization			18.14				20.57				(2.43	)			(12	%)
Accretion expense			0.13				0.11				0.02				18	%
Impairment of oil and gas properties			—				7.20				(7.20	)			(100	%)
Exploration costs			0.58				0.85				(0.27	)			(32	%)
General and administrative expenses			6.58				3.75				2.83				75	%
(Gain) loss on sale of other assets			(0.04	)			0.02				(0.06	)			300	%
Total operating expenses per Boe		$	31.78			$	39.57			$	(7.79	)			(20	%)

Lease Operating Expenses. LOE increased 5%, or $0.2 million, in 2016 as compared to 2015. The increase was due to purchased injection water and gas of $0.2 million. On a Boe basis, LOE decreased 14%, or $1.0 million, primarily due to a 237 MBoe increase in production during 2016 compared to 2015.

Production Taxes. Production taxes are primarily based on the market value of our production at the wellhead. Production taxes increased 18%, or $0.2 million, in 2016 as compared to 2015 due to an increase of $5.2 million in production revenues in 2016 as compared to 2015. On a Boe basis, production taxes decreased 3%, or $0.03 per Boe, primarily due to higher production volumes (237 MBoe) in 2016 as compared to 2015. Production taxes as a percentage of our revenue was 5% for 2016 compared to 4% for 2015.

 

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Gathering and Transportation Expenses. Gathering and transportation expenses increased 15%, or $0.3 million, during 2016 as compared to 2015 due to a 237 MBoe increase in sales and processing volumes. On a Boe basis, gathering and transportation expenses decreased 5%, or $0.10 per Boe, due to higher sales and processing volumes (237 MBoe) during 2016 compared to 2015.

Depreciation, Depletion, and Amortization. Our DD&A rate can fluctuate as a result of impairments, dispositions, exploration and development costs, and proved reserve volumes. DD&A increased 7%, or $1.5 million, during the year ended December 31, 2016 compared to the prior year, due to higher production volumes in 2016 (237 MBoe), or $4.3 million, offset by a lower DD&A rate, or $2.8 million. The DD&A rate on a Boe basis decreased 12%, or $1.8 million ($2.43 per Boe), due to the increases in proved developed reserves during 2016 (767 MBoe).

Accretion Expense. Accretion expense increased 47%, or $0.1 million, during the year ended December 31, 2016 compared to the prior year due to the addition of five new producing wells. On a Boe basis, accretion expense increased 18%, or $0.02 per Boe.

Impairment of Oil and Gas Properties. We did not record any impairment in 2016. In 2015, we recorded an $8.1 million impairment expense, all of which was attributable to an impairment of developed properties.

Exploration Costs. Exploration costs decreased 17%, or $0.2 million, due to a reduction in contract personnel during the year ended December 31, 2016 compared to the prior year. On a Boe basis, exploration costs decreased 32%, or $0.27 per Boe.

General and Administrative Expenses. G&A expense increased 113%, or $4.8 million, due to an increase in salaries and benefits ($1.4 million), transaction expenses related to the Business Combination ($3.1 million), and legal expense ($0.3 million). On a Boe basis, G&A expense increased 75%, or $2.83 per Boe.

Other Income and Expenses. The following table summarizes our other income and expenses for the periods indicated:

 

		Year Ended December 31,
		2016				2015				Change				Change %
		(Unaudited)
Other (expense) income (in thousands):
Interest expense, net		$	(1,822	)		$	(3,247	)		$	1,425				(44	%)
Other income (expense), net			(247	)			7				(254	)			(3629	%)
Total other expense		$	(2,069	)		$	(3,240	)		$	1,171				(36	%)
Income tax expense			(148	)			(108	)			(40	)			37	%

Interest Expense, Net. Interest expense, net decreased 44%, or $1.4 million, due to a decrease in the average borrowings under our secured line of credit during the year ended December 31, 2016 ($55.0 million) compared to the prior year ($65.0 million).

Other Income (Expense), Net. Other income (expense), net decreased $0.2 million as a result of write offs of obsolete field equipment inventory.

 

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Year Ended December 31, 2015 Compared to the Year Ended December 31, 2014

Oil and Natural Gas Revenues. The following table provides the components of our revenues for the years indicated, as well as each year’s respective average prices and production volumes:

 

		Year Ended December 31,								Change				Change %
		2015				2014
Revenues (in thousands):
Oil sales		$	20,601			$	28,444			$	(7,843	)			(28	%)
Natural gas sales			4,909				7,445				(2,536	)			(34	%)
NGL sales			3,977				7,674				(3,697	)			(48	%)
Gain on commodity derivatives, net			3,735				2,404				1,331				55	%
Total revenues		$	33,222			$	45,967			$	(12,745	)			(28	%)
Average sales price(1):
Oil (per Bbl)		$	43.62			$	77.93			$	(34.31	)			(44	%)
Natural gas (per Mcf)			2.37				4.06				(1.69	)			(42	%)
NGL (per Bbl)			12.75				26.93				(14.18	)			(53	%)
Total (per Boe)		$	26.09			$	45.58			$	(19.49	)			(43	%)
Total, after effects of gain (loss) from commodity derivatives (per Boe)		$	29.40			$	48.10			$	(18.70	)			(39	%)
Production:
Oil (MBbls)			472				365				107				29	%
Natural gas (MMcf)			2,074				1,834				240				13	%
NGL (MBbl)			312				285				27				9	%
Total (MBoe)(2)			1,130				956				174				18	%
Average daily production volume:
Oil (Bbls/d)			1,294				1,000				294				29	%
Natural gas (Mcf/d)			5,683				5,025				658				13	%
NGL (Bbls/d)			855				781				74				9	%
Total (Boe/d)(2)			3,096				2,618				478				18	%

 

(1)	Average prices shown in the table reflect prices before the effects of realized commodity derivative transactions.

(2)	Totals may not sum or recalculate due to rounding.

As reflected in the table above, our total revenues for 2015 were 28%, or $12.7 million, lower than 2014. The decrease was primarily due to a significant decrease in commodity prices resulting in a 43% decrease in the average sales price per Boe, or $19.7 million ($19.49 per Boe), which was partially offset by a 18% increase in average daily production, or $5.6 million (174 MBoe), as compared to the prior year. The increase in production was attributable to one operated and two non-operated new wells coming on line during the year ended December 31, 2015.

Oil sales for 2015 as compared to 2014 decreased 28%, or $7.8 million, primarily due to a 44% decrease in average sales price for oil ($34.31 per Bbl), or $12.5 million, offset by a 29% increase in oil production (107 MBbl), or $4.7 million. Natural gas sales for 2015 as compared to 2014 decreased 34%, or $2.5 million, primarily due to a 42% decrease in average sales price for natural gas ($1.69 per Mcf), or $3.1 million, offset by a 13% increase in natural gas production (240 MMcf), or $0.6 million. NGL sales for 2015 as compared to 2014 decreased 48%, or $3.7 million, primarily due to a 53% decrease in the average sales price for NGLs ($14.18 per Bbl), or $4.0 million, offset by a 9% increase in NGL production (27 MBbls), or $0.3 million.

 

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In 2015, we recognized a $3.7 million gain on commodity derivative instruments compared to a $2.4 million gain on commodity derivative instruments in 2014. Net gains and losses on our commodity derivatives are a function of fluctuations in the underlying commodity prices and the monthly settlement of the instruments.

Operating Expenses. The following table summarizes our expenses for the periods indicated:

 

		Year Ended December 31,
		2015				2014				Change				Change %
Operating expenses (in thousands):
Lease operating expenses		$	4,582			$	6,103			$	(1,521	)			(25	%)
Production taxes			1,311				1,861				(550	)			(30	%)
Gathering and transportation expenses			2,094				2,462				(368	)			(15	%)
Depreciation, depletion and amortization			23,244				15,842				7,402				47	%
Accretion expense			120				125				(5	)			(4	%)
Impairment of oil and natural gas properties			8,131				27,595				(19,464	)			(71	%)
Exploration costs			960				960				—				—	%
General and administrative expenses			4,234				5,151				(917	)			(18	%)
(Gain) on sale of oil and natural gas properties			—				(6	)			6				(100	%)
(Gain) loss on sale of other assets			18				(26	)			44				(169	%)
Total operating expenses before other miscellaneous (income) expense		$	44,694			$	60,067			$	(15,373	)			(26	%)
Operating expenses per Boe:
Lease operating expenses		$	4.06			$	6.39			$	(2.33	)			(36	%)
Production taxes			1.16				1.95				(0.79	)			(41	%)
Gathering and transportation expenses			1.85				2.58				(0.73	)			(28	%)
Depreciation, depletion and amortization			20.57				16.58				3.99				24	%
Accretion expense			0.11				0.13				(0.02	)			(15	%)
Impairment of oil and natural gas properties			7.20				28.87				(21.67	)			(75	%)
Exploration costs			0.85				1.00				(0.15	)			(15	%)
General and administrative expenses			3.75				5.39				(1.64	)			(30	%)
(Gain) on sale of oil and natural gas properties			—				(0.01	)			0.01				(100	%)
(Gain) loss on sale of other assets			0.02				(0.03	)			0.05				(167	%)
Total operating expenses per Boe		$	39.57			$	62.85			$	(23.28	)			(37	%)

Lease Operating Expenses. LOE decreased 25%, or $1.5 million, in 2015 as compared to 2014, due to reduced cost of water disposal ($1.5 million) as a result of us having drilled a saltwater disposal well in 2015 reducing the cost to haul disposal water. On a Boe basis, LOE decreased 36%, or $2.33 per Boe.

Production Taxes. Production taxes are primarily based on the market value of our production at the wellhead. Production taxes decreased 30%, or $0.6 million, due to lower production revenues ($12.7 million lower in 2015) as a result of lower realized commodity prices ($19.49 per Boe lower in 2015). On a Boe basis, production taxes decreased 41%, or $0.79 per Boe. Production taxes as a percentage of our revenue was 4% for 2015 and 2014, respectively.

Gathering and Transportation Expenses. Gathering and transportation expenses decreased 15%, or $0.4 million. In 2015, lower prices for natural gas ($1.69 per Mcf lower in 2015) and NGLs ($14.18 per Bbl lower in 2015) resulted in lower costs ($0.7 million) associated with fuel and processing fees, which were partially offset by higher processing volumes (174 MBoe), or $0.3 million. On a Boe basis, gathering and transportation expense decreased 28%, or $0.73 per Boe.

 

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Depreciation, Depletion, and Amortization. Our DD&A rate can fluctuate as a result of impairments, dispositions, finding and development costs, and proved reserve volumes. DD&A expense increased 47%, or $7.4 million, due to an increase in production volumes (174 MBoe), or $3.6 million, and lower reserve volumes (5.2 MBoe), or $3.8 million. DD&A per Boe was $20.57 for 2015, an increase of $3.99 as compared to $16.58 in 2014.

Accretion Expense. Accretion expense was consistent in 2015 compared to 2014. Increases due to the addition of three new producing wells $2.7 million was offset by decreases in estimated plugging and abandonment costs $3.1 million. On a Boe basis, accretion expense decreased 15%, or $0.02 per Boe, due to consistent costs being allocated over a 174 MBoe increase in production in 2015 as compared to 2014.

Impairment of Oil and Gas Properties. In 2015, we recorded an $8.1 million impairment expense, all of which was attributable to an impairment of developed properties. In 2014, we recorded a $27.6 million impairment expense, of which $0.1 million was attributable to an impairment of undeveloped properties.

Exploration Costs. Exploration costs were consistent in 2015 compared to 2014. On a Boe basis, exploration costs decreased 15%, or $0.15 per Boe, due to consistent costs being allocated over a 174 MBoe increase in production in 2015 as compared to 2014.

General and Administrative Expenses. G&A expenses decreased 18%, or $0.9 million, due to a reduction in salaries and related benefits ($1.6 million) offset by an increase in legal expense ($0.4 million) as compared to 2014. On a Boe basis, G&A decreased 30%, or $1.64 per Boe.

Other Income and Expenses. The following table summarizes our other income and expenses for the years indicated:

 

		Year Ended December 31,
		2015				2014				Change				Change %
Other (expense) income (in thousands):
Interest expense, net		$	(3,247	)		$	(5,469	)		$	2,222				(41	%)
Other income, net			7				316				(309	)			(98	%)
Total other expense		$	(3,240	)		$	(5,153	)		$	1,913				(37	%)
Income tax expense			(108	)			—				(108	)			100	%

Interest Expense, Net. Interest expense, net decreased 41%, or $2.2 million, due to a decrease in the average amounts outstanding under Tema’s secured line of credit in 2015 ($65.0 million) as compared to 2014 ($75.0 million).

Capital Requirements and Sources of Liquidity

Our development and acquisition activities require us to make significant operating and capital expenditures. Historically, our primary sources of liquidity have been cash flows from operations, borrowings under our secured line of credit, proceeds from asset dispositions and capital contributions from Tema. To date, our primary use of capital has been for the development of oil and natural gas properties.

We plan to continue to enter into hedging arrangements to reduce the impact of commodity price volatility on our cash flow from operations. Under this strategy, we expect to maintain an active hedging program that seeks to reduce our exposure to commodity prices and protect our cash flow.

The amount and allocation of future capital expenditures will depend upon a number of factors, including the number and size of acquisition opportunities, our cash flows from operations, investing and financing

 

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activities, and our ability to assimilate acquisitions and execute our drilling program. We have historically reviewed our capital expenditure budget periodically to assess changes in current and projected cash flows, acquisition and divestiture activities, debt requirements, and other factors. If we are unable to obtain funds when needed or on acceptable terms, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to maintain our production or proved reserves.

Our 2016 capital budget for drilling, completion and recompletion activities and facilities costs was approximately $25.5 million, excluding leasing and other acquisitions. We have allocated approximately $24.8 million to drill and complete operated wells and $0.7 million to participate in the drilling and completion of non-operated wells. For 2016, we budgeted $1.6 million for leasing. In the year ended December 31, 2016, we incurred capital costs of approximately $22.9 million, excluding leasing and acquisition costs and inclusive of changes in accrual of capital expenditures.

Our 2017 capital budget for drilling, completion and recompletion activities and facilities costs is approximately $89.9 million, excluding leasing and other acquisitions. For 2017, we allocated approximately $88.7 million to drill and complete operated wells and $1.2 million to participate in the drilling and completion of non-operated wells. For 2017, we have budgeted $4.0 million for leasing.

Because we are the operator of a high percentage of its acreage, the amount and timing of these capital expenditures is largely discretionary and within our control. We could choose to defer a portion of these planned capital expenditures depending on a variety of factors, including, but not limited to, the success of our drilling activities, prevailing and anticipated prices for oil and natural gas, the availability of necessary equipment, infrastructure and capital, the receipt and timing of required regulatory permits and approvals, seasonal conditions, drilling and acquisition costs, and the level of participation by other working interest owners. A deferral of planned capital expenditures, particularly with respect to drilling and completing new wells, could result in a reduction in anticipated production and cash flows. Additionally, if we curtail our drilling program, we may lose a portion of our acreage through lease expirations. See “Information About Us—Oil and Natural Gas Production Prices and Costs—Developed and Undeveloped Acreage.” In addition, we may be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves if such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

As of April 27, 2017, we had $0 million outstanding under our Credit Agreement and the borrowing base under our Credit Agreement was $55.0 million.

Based upon current oil and natural gas price expectations for 2017, we believe that its cash flow from operations and borrowings under its future secured line of credit will provide it with sufficient liquidity to fund its operations for the next twelve months. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop its properties. We cannot ensure that operations and other needed capital will be available on acceptable terms or at all. In the event we make additional acquisitions and the amount of capital required is greater than the amount it has available for acquisitions at that time, we could be required to reduce the expected level of capital expenditures and/or seek additional capital. If we require additional capital for that or other reasons, it may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financings, asset sales, offerings of debt and equity securities by us or by other means. We cannot ensure that needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, it may be required to curtail its current drilling program, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to it or finance the capital expenditures necessary to maintain its production or replace its reserves.

 

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Working Capital

We define working capital as current assets minus current liabilities. At December 31, 2016, we had working capital of $2.0 million, and at December 31, 2015, it had a working capital of $4.5 million. we may incur working capital deficits in the future due to liabilities incurred in connection with its drilling program. Our collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. Our cash and cash equivalents balance totaled $8.4 million and $27.7 million, at December 31, 2016 and 2015, respectively. We expect that the pace of development, production volumes, commodity prices, and differentials to NYMEX prices for its oil and natural gas production will be the largest variables affecting its working capital.

Cash Flows

The following table summarizes our cash flows for the periods indicated:

 

		Year Ended December 31,
		2016				2015				2014
Net cash provided by operating activities		$	11,461			$	18,244			$	25,525
Net cash used in investing activities			(22,164	)			(16,993	)			(53,392	)
Net cash provided by (used in) financing activities			(8,597	)			17,519				23,457
Net change in cash and cash equivalents		$	(19,300	)		$	18,770			$	(4,410	)

Analysis of Cash Flow Changes for the Year Ended December 31, 2016 and 2015

Operating Activities. Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs, production volumes, and changes in working capital. The decrease in net cash provided by operating activities of $6.8 million for the year ended December 31, 2016 as compared to the prior year was due to a decrease in net revenues, a decrease in accounts receivable ($3.9 million), and a decrease in prepaid and other current assets ($0.8 million), offset by an increase in accounts payable and accrued liabilities and other ($2.8 million), and an increase in net change in derivative instruments ($1.6 million).

Investing Activities. Net cash used in investing activities is primarily comprised of acquisition and development of oil and natural gas properties, net of dispositions. In 2016, net cash used for investing activities included $22.0 million attributable to the acquisition and development of oil and natural gas properties. In 2015, net cash used for investing activities included $17.2 million attributable to the acquisition and development of oil and natural gas properties.

Financing Activities. Net cash provided by financing activities in 2016 included $10.0 million of borrowings on Tema’s secured line of credit, $20.0 million of repayments under Tema’s secured line of credit and $1.4 million of parent investment. Net cash provided by financing activities in 2015 included $10.0 million of repayments under Tema’s secured line of credit, $25.9 million of parent investment and $1.8 million of borrowings under a related party unsecured credit agreement.

Analysis of Cash Flow Changes for the Year Ended December 31, 2015 and 2014

Operating Activities. Net cash provided by operating activities is primarily affected by the price of oil, natural gas and NGLs, production volumes and changes in working capital. The decrease in net cash provided by operating activities for the year ended December 31, 2015 as compared to the prior year is primarily due to a decrease in net loss ($4.4 million) and impairment ($19.5 million) offset by an increase in DD&A ($7.4 million).

Investing Activities. Net cash used in investing activities is primarily comprised of acquisition and development of oil and natural gas properties net of dispositions. In 2015, net cash used for investing activities

 

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included $17.2 million attributable to the acquisition and development of oil and natural gas properties. In 2014, net cash used for investing activities included $76.7 million attributable to the acquisition and development of oil and natural gas properties, offset by $24.6 million in proceeds from sales of marketable securities.

Financing Activities. Net cash provided by financing activities in 2015 included $10.0 million of repayments to Tema’s secured line of credit, offset by parent investment of $25.9 million and $1.8 million of borrowings under a related party unsecured credit agreement. Net cash provided by financing activities in 2014 included $15.0 million of borrowing under Tema’s secured line of credit, $10.0 million of borrowings under a related party unsecured credit agreement, offset by $1.5 million parent distribution.

Our Credit Agreement

On April 27, 2017, we entered into the Credit Agreement. Borrowings under the Credit Agreement will bear interest at a base rate plus an applicable margin ranging from 1.00% to 2.00% or at LIBOR plus an applicable margin ranging from 2.00% to 3.00%. The Credit Agreement will mature on April 27, 2022. For additional information regarding the Credit Agreement, see “Certain Relationships and Related Transactions—Agreements Relating to Our Business Combination—Credit Agreement.”

Contractual Obligations

A summary of our contractual obligations as of December 31, 2016 is provided in the following table.

 

		Payments Due by Period For the Year Ending December 31,
		2017				2018				2019				2020				2021				Thereafter				Total
(In thousands):
Credit Agreement(1)		$	—			$	55,000			$	—			$	—			$				$	—			$	55,000
Operating leases(2)			1,062				1,104				1,090				1,076				1,087				552				5,971
Capital leases(2)			34				34				34				—								—				102
Asset retirement obligations(3)			251				—				—				—								5,180				5,431
Total		$	1,347			$	56,138			$	1,124			$	1,076			$	1,087			$	5,732			$	66,504

 

(1)

This table does not include future commitment fees, amortization of deferred financing costs, interest expense, or other fees on Tema’s secured line of credit because Tema’s secured line of credit was paid off by us in connection with our assumption of Tema’s assets and liabilities. We entered into a new credit agreement on the closing date of the Business Combination. For additional information regarding our Credit Agreement, see “—Our Credit Agreement.”

(2)	The Company has noncancelable operating and capital leases for office space and equipment that are expected to be transferred to us.

(3)

Amounts represent estimates of our future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology, and the political and regulatory environment.

Quantitative and Qualitative Disclosure About Market Risk

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

 

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Commodity Price Risk

Our major market risk exposure is in the pricing that we receive for our oil, natural gas, and NGL production. Pricing for oil, natural gas, and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. Since January 1, 2014, the WTI spot price for oil declined from a high of $107.95 per barrel on June 20, 2014 to $26.19 per barrel on February 11, 2016, and the Henry Hub spot price for natural gas declined from a high of $8.15 per MMBtu on February 10, 2014 to a low of $1.49 per MMBtu on March 4, 2016. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have suffered significant recent declines in realized prices.

The prices we receive for our oil, natural gas, and NGL production depend on numerous factors beyond our control, some of which are discussed in “Risk Factors—Risks Related to our Operations—Oil, natural gas and natural gas liquid (“NGL”) prices are volatile. A sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.”

A 10% per barrel change in our realized oil price would have resulted in a $2.5 million change in oil revenues for 2016. A 10% per Mcf change in its realized natural gas price would have resulted in a $0.5 million change in natural gas revenues for 2016. A 10% per barrel change in NGL prices would have changed NGL revenue by $0.5 million for 2016. Oil sales contributed 72% of our total revenues for 2016. Natural gas sales contributed 15% and NGL sales contributed 13% of total revenues for 2016. Our oil, natural gas, and NGL revenues do not include the effects of commodity derivatives.

Due to this volatility, we have historically used, and we expect to continue to use, commodity derivative instruments, such as collars, swaps, and basis swaps, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments allow us to reduce, but not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices.

For further discussion of our historical use of derivatives, please see “—Overview—Derivative Activity.”

Counterparty and Customer Credit Risk

Our commodity derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our commodity derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. The counterparties to our commodity derivative contracts currently in place, all of which will either be transferred to us or settled in connection with the closing of the Business Combination, have investment grade ratings.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of its oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, the credit quality of our customers is believed to be high.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

 

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Interest Rate Risk

As of May 4, 2017, we had no debt outstanding under our Credit Agreement. Interest under our Credit Agreement is tiered based on amount borrowed. The interest rate is LIBOR +2% (lowest) up to +3% (highest) depending on the outstanding balance. Assuming the full borrowing base of $55.0 million was outstanding, the impact on interest expense of a 1% increase or decrease in the assumed weighted average interest rate would be approximately $0.5 million per year. We currently do not have a derivative arrangement to protect against fluctuations in interest rates applicable to our outstanding indebtedness.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon financial statements prepared on a carve-out basis and are derived from the financial statement and accounting records of Tema, which have been prepared in accordance with GAAP. The preparation of the financial statements requires it to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and related disclosure of contingent assets and liabilities. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

Our oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, we capitalize lease acquisition costs, all development costs, and successful exploration costs.

Proved Oil and Natural Gas Properties. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil, natural gas, and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Unproved Properties. Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees, and other similar costs related to acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Costs. Exploration costs, other than exploration drilling costs, are charged to expense as incurred. These costs include exploratory seismic expenditures, other geological and geophysical costs, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

Impairment of Oil and Natural Gas Properties

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in the interpretations or assumptions could materially affect the estimated quantities and present value of the reserves. Actual future production, commodity prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves may vary, and has historically varied, from estimates.

Our proved oil and natural gas properties are recorded at cost. Our proved properties are evaluated for impairment on a field-by-field basis whenever events or changes in circumstances indicate that an asset’s

 

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carrying value may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on its estimate of future oil and natural gas prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using WTI and Henry Hub natural gas NYMEX strip market pricing, adjusted for quality, transportation fees and a regional price differential. Fair value is calculated by discounting the future cash flows at a rate of 10%. Our management considers 10% to be an appropriate discount rate to apply in determining fair value. We believe a 10% discount rate is commonly used by oil and gas industry peers, analysts, and investors in evaluating the monetary significance of oil and gas properties and for comparing the size and value of proved reserves among companies in our industry. Accordingly, we currently believe a 10% discount rate is consistent with a rate a market participant would consider in evaluating onshore domestic proved oil and gas reserves and produces a reasonable estimate of fair value.

While it is difficult to project future impairment write-downs in light of numerous factors involved, fluctuations in prices or costs could result in an impairment of our oil and natural gas properties. Our average realized price per barrel of oil decreased approximately 7%, and our average realized price per Mcf of natural gas decreased approximately 6%, for the year ended December 31, 2016 as compared to the year ended December 31, 2015. Lease operating expenses increased 5% for the year ended December 31, 2016 as compared to the year ended December 31, 2015. If we had used the average realized prices of oil and natural gas utilized in the preparation of our 2016 oil and gas reserve report and reduced it by 10% and held lease operating expenses constant, we would have incurred impairment of approximately $2.8 million in 2016. However, we use NYMEX and Henry Hub strip pricing for our impairment calculations. Assuming a 10% reduction in the NYMEX and Henry Hub pricing, we would not have incurred impairment in 2016. Further, assuming a 10% increase in the lease operating expenses utilized in the preparation of our 2016 oil and gas reserve report, and holding average realized oil and gas prices constant, we would not have incurred additional impairment.

Commodity prices are volatile, and there can be no assurance that we will not experience a more significant decline in average realized prices than discussed above. Depending upon the then-current commodity price environment, we may not be able to economically produce in the assumed quantities, which could have a negative impact on expected cash flows. In addition, during periods of rising commodity prices, lease operating costs have typically risen as well, and there can be no assurance that such costs will not increase more than the amount assumed above.

Unproved oil and natural gas properties are assessed periodically, and no less than annually, for impairment on an aggregate basis based on remaining lease term, drilling results, reservoir performance, seismic interpretation and future plans to develop acreage. As unproved oil and natural gas properties are developed and reserves are proved, the capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved oil and natural gas properties are written off or reclassified to proved oil and natural gas properties depends on the timing and success of our future exploration and development program.

Oil and Natural Gas Reserve Quantities

Our estimated proved reserve quantities and future net cash flows are critical to the understanding of the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in its financial statements, including the calculations of depletion and impairment of proved oil and natural gas properties. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials, and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure calculations require a 10% discount rate to be applied. Although reserve estimates are

 

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inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We have and expect to evaluate and estimate our proved reserves each year-end. For purposes of depletion and impairment, reserve quantities are adjusted in accordance with GAAP for the impact of additions and dispositions.

Revenue Recognition

Our revenue recognition policy is significant because revenue is a key component of our results of operations and our forward-looking statements contained in the above analysis of liquidity and capital resources. We derive our revenue primarily from the sale of produced oil, natural gas, and NGLs. Revenue is recognized when our production is delivered to the purchaser, but payment is generally received between 30 and 90 days after the date of production. No revenue is recognized unless it is determined that title to the product has transferred to a purchaser. At the end of each month, we make estimates of the amount of production delivered to the purchaser and the price we will receive. We use our knowledge of our properties, contractual arrangements, NYMEX and local spot market prices, and other factors as the basis for these estimates. Variances between our estimates and the actual amounts received are recorded in the month payment is received.

Commodity Derivative Instruments

We utilize commodity derivative instruments, including swaps, collars, and basis swaps, to manage the price risk associated with the forecasted sale of its oil and natural gas production. These commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, changes in fair value are recognized in our statements of operations in the period of change. Gains and losses on commodity derivatives and premiums paid for put options are included in cash flows from operating activities.

Asset Retirement Obligations

Our asset retirement obligation represents the estimated present value of the amount we will incur to retire long-lived assets at the end of their productive lives, in accordance with applicable state laws. Our asset retirement obligation is determined by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of inception with an offsetting increase in the carrying amount of the related long-lived asset. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset.

Asset retirement liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of assets, and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity of assumptions, the costs to ultimately retire our wells may vary significantly from prior estimates.

Recently Issued Accounting Pronouncements

In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, including interim periods therein, and is applied retrospectively. Early adoption is permitted for financial statements that have not been previously issued. In August 2015, ASU 2015-15, Presentation and Subsequent Measurement of Debt Issue Costs Associated with Line of Credit Arrangements, was subsequently

 

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issued to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements and states that the SEC staff will not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The adoption of this ASU will impact the presentation of Deferred Financing Costs on our balance sheet.

In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of Effective Date, which defers the effective date of ASU 2014-09 by one year to be effective for annual reporting periods beginning after December 15, 2018, and interim reporting periods within annual reporting periods beginning after December 31, 2019. As a public entity, ASU 2014-09 is effective for annual periods beginning after December 31, 2017 and the interim periods therein. ASU 2014-09, Revenue from Contracts with Customers, supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Subsequently, in April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing as further clarification on identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow—Scope Improvements and Practical Expedients, as clarifying guidance to improve the operability and understandability of the implementation guidance on principal versus agent considerations. In December 2016, the FASB further issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, to increase stakeholders’ awareness of the proposals and to expedite improvements to ASU 2014-09. The adoption of this ASU is not expected to have a material impact on our financial statements and related disclosures.

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 704): Balance Sheet Classification of Deferred Taxes. ASU No. 2015-17 eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and non-current in a classified balance sheet. Instead, companies are required to classify all deferred tax assets and liabilities as non-current. ASU 2015-17 is effective for interim and annual periods beginning after December 15, 2016. The adoption of this ASU is not expected to have a material impact on our financial statements.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. We are currently evaluating the method of adoption and impact this standard will have on our financial statements and related disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments requiring the measurement of all expected credit losses for financial assets, which include trade receivables, held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. We are currently evaluating the method of adoption and impact this standard will have on our financial statements and related disclosures.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 320): Classification of Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity of presentation and classification in the statement of cash flows. The new standard applies to cash flows associated with debt payment or debt extinguishment costs, settlement of zero-coupon debt or other debt instruments with coupon rates that are insignificant in relation to effective interest rate of borrowing,

 

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contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows, and application of the predominance principle. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal periods. Early adoption is permitted, but only if all amendments are adopted in the same period. The adoption of this ASU is not expected to have a material impact on our financial statements and related disclosures.

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years beginning after December 15, 2018, including interim periods within these fiscal years. The impact this standard will have on the financial statements and related disclosures is currently being evaluated.

In February 2017, the FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets, which clarifies the scope of Subtopic 610-20 and provides further guidance for partial sales of nonfinancial assets. Subtopic 610-20, which was issued in May 2014 as part of ASU 2014-09, provides guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with noncustomers. An entity is required to apply the amendments in ASU 2017-05 at the same time it applies the amendments in ASU 2014-09. An entity may elect to apply the amendments in ASU 2017-05 either retrospectively to each period presented in the financial statements in accordance with the guidance on accounting changes in FASB’s Accounting Standards Codification (“ASC”) Topic 250, Accounting Changes and Error Corrections, paragraphs 10-45-5 through 10-45-10 (i.e. the retrospective approach) or retrospectively with a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption (i.e. the modified retrospective approach). An entity may elect to apply all of the amendments in ASU 2017-05 and ASU 2014-09 using the same transition method, and alternatively may elect to use different transition methods. The impact ASU 2017-05 will have on the financial statements and related disclosures is currently being evaluated.

Internal Controls and Procedures

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of their internal control over financial reporting for that purpose.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2016, 2015, or 2014. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and natural gas prices increase drilling activity in our areas of operations.

Off-Balance Sheet Arrangements

Currently, we have no off-balance sheet arrangements.

 

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MANAGEMENT

Management and Board of Directors

Set forth below are the names, ages and positions of each of each of our directors and executive officers:

 

Name		Age		Position
Gary C. Hanna		58		Chairman
Edward Kovalik		42		Director
Frank Rosenberg		58		Director
William Mayer		76		Director
Harry Quarls		64		Director
Francis Contino		71		Director
J.A. (Alan) Townsend		66		President, Chief Executive Officer and Director
T. J. Thom		44		Interim Chief Financial Officer
Brian K. Ayers		60		Vice President of Geology
R. Colby Williford		52		Vice President of Land

Gary C. Hanna, our Chairman since September 2015, has over 30 years of executive experience in the energy exploration and production and service sectors, with a primary focus in the mid-continent U.S. and Gulf of Mexico regions. Between September 2015 and April 2017, Mr. Hanna also served as our Chief Executive Officer. Between June 2015 and September 2015, Mr. Hanna evaluated various investment and employment opportunities. Mr. Hanna was a consultant for Energy XXI Gulf Coast, Inc. from June 2014 to June 2015. From 2009 until June 2014, Mr. Hanna served as the Chief Executive Officer of EPL Oil & Gas, Inc., or EPL, a publicly-traded company that was acquired by Energy XXI in June 2014 for $2.3 billion, and was elected as a director of EPL in June 2010 and Chairman in 2013. From 2008 to 2009, Mr. Hanna served as President and Chief Executive Officer of Admiral Energy Services, a start-up company focused on the development of offshore energy services. From 1999 to 2007, Mr. Hanna served in various capacities at Tetra Technologies, Inc., an international oil and gas services production company, including serving as Senior Vice President from 2002 to 2007. Mr. Hanna also served as President and Chief Executive Officer of Tetra’s affiliate, Maritech Resources, Inc., and as President of Tetra Applied Technologies, Inc., another Tetra affiliate. From 1996 to 1998, Mr. Hanna served as the President and Chief Executive Officer of Gulfport Energy Corporation, a public oil and gas exploration company. From 1995 to 1998, he also served as the Chief Operations Officer for DLB Oil& Gas, Inc., a mid-continent exploration public company. From 1982 to 1995, Mr. Hanna served as President and Chief Executive Officer of Hanna Oil Properties, Inc., a company engaged in oil services and the development of mid-continent oil and gas prospects. Since November 2015, Mr. Hanna has served as a member of the boards of directors of Hercules Offshore, Inc. and Aspire Holdings Corp. Mr. Hanna holds a B.B.A. in Economics from the University of Oklahoma. Mr. Hanna is well-qualified to serve as director due to his extensive operational, financial and management background.

Edward Kovalik has served as a director since September 2015. Between September 2015 and April 2017, Mr. Kovalik also served as President of the Company. Mr. Kovalik has also been the Chief Executive Officer and Managing Partner of KLR Holdings and KLR Group, LLC (“KLR Group”), an investment bank specializing in the energy sector which he co-founded in the spring of 2012. Mr. Kovalik manages the firm and focuses on structuring bespoke financing solutions for the firm’s clients. Mr. Kovalik has over 17 years of experience as an investment banker. Prior to founding KLR Holdings, from 2002 until April 2012, Mr. Kovalik served in various capacities of Rodman & Renshaw, most recently as Head of Capital Markets and the head of Rodman’s Energy Investment Banking team. From 1999 to 2002, Mr. Kovalik was a Vice President at Ladenburg Thalmann & Co., where he focused on private placement transactions for public companies. Mr. Kovalik has served as a member of the boards of directors of River Bend Oil and Gas, LLC since June 2013 and Marathon Patent Group, Inc. a public company, since April 2014. Mr. Kovalik is well-qualified to serve as director due to his extensive financial and management background.

 

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Frank Rosenberg has served as a director since the closing of the Business Combination. Since 2006, Mr. Rosenberg has been a Director of Tema Oil & Gas, Gateway Gathering and Marketing and Rosemore, Inc. Mr. Rosenberg is also the Co-Chairman of the Board of Directors (since 2013) and Chief Investment Officer of Rosemore, Inc., Chairman of the Board of Attransco, which historically operated U.S.-flagged mixed-use oil tankers, and a Director of Glen Eagle Resources (since 2013), a junior miner based in Montreal, Canada. Prior to joining Rosemore, Mr. Rosenberg had a breadth of assignments with Crown Central Petroleum Corporation at the refinery, in the trading operation, the wholesale and retail marketing departments, with the last job being as President & CEO. Mr. Rosenberg began his career with General Electric Credit Corporation (currently, GE Capital) in the marketing and then credit departments. He received an MBA from Emory University and a B.S. in Chemical Engineering from Bucknell University. Mr. Rosenberg was selected to serve on the board of directors due to his extensive experience in the oil and gas industry and significant financial experience.

William Mayer has served as a director since the closing of the Business Combination. He has served as a director of Rosemore, Inc. since 2005. Over the past 45 years, he has been a board member of numerous other public and private companies and is currently serving on the board of the following companies: Lee Enterprises since 1998, BlackRock Capital Investment Corporation since 2005, Premier, Inc. since 2013, Finworx, Inc. since 2016, Hambrecht Partners Holdings since 2009, and Miller Buckfire since 2011. He has previously been a member of the board at the Aspen Institute and University of Maryland. Mr. Mayer is the founding partner of Park Avenue Equity Partners, which is a private equity firm. Mr. Mayer was named to the 2013 NACD (National Association of Corporate Directors), which honors leaders in corporate governance and in the boardroom. He earned a Bachelor of Science in 1966 and Masters of Businesses Administration in 1967 from the University of Maryland. Mr. Mayer was a First Lieutenant in the U.S. Air Force. Mr. Mayer brings significant experience as a board member to the Company’s board of directors.

Harry Quarls has served as a director since the closing of the Business Combination. He has been Managing Director at Global Infrastructure Partners since January 2009. He serves as Chairman of the Board of Penn Virginia Corporation and Woodbine Holdings LLC and as a Director of US Oil Sands Corporation and Opal Resources LLC. Mr. Quarls previously served as Chairman of the Board of Directors of Trident Resources Corp. and as a Director for Fairway Resources LLC. He also served as a Managing Director and Practice Leader for Global Energy at Booz & Co., a leading international management consulting firm, and as a member of Booz’s Board of Directors. Mr. Quarls earned an M.B.A. degree from Stanford University and also holds ScM. and B.S. degrees, both in chemical engineering, from M.I.T. and Tulane University, respectively. Mr. Quarls will bring considerable financial and energy investing experience, as well as experience on the boards of numerous public and private energy companies, to the Board of Directors.

Francis Contino has served as a director since the closing of the Business Combination. He currently serves as Managing Director of FAC&B LLC, a consulting firm he founded in 2008. Additionally, since 2004 he has served as member of the board and Chairman of the Audit Committee of Mettler Toledo International, Inc., a leading global supplier of precision instruments and services. Mr. Contino previously served as Chief Financial Officer, Executive Vice President, and Director of McCormick & Company from 1998 to 2008. Prior to joining McCormick, Mr. Contino served as the Managing Partner of the Baltimore office of Ernst & Young, where he began his career. Mr. Contino completed the Executive Leadership Education Program at The Kellogg School of Business at Northwestern University. He graduated from the University of Maryland in 1968. Mr. Contino was selected to join the Company’s board of directors due to his considerable board experience and financial background.

J.A. (Alan) Townsend has served as our President and Chief Executive Officer since the closing of the Business Combination. Mr. Townsend has been the President and a Director of Tema since April 2008. He also currently serves and has served as President and Director of several of Rosemore’s subsidiaries, including Gateway since April 2008, President of Crown Central New Holdings, LLC since 2010, President and Director of Tema of PA, LLC since 2012, and President and Director of Raven Gathering System, LLC since 2015. He has been employed by Tema since November 2001. Mr. Townsend has 44 years of engineering, operations, and

 

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management experience in the oil and gas industry. He has held several executive positions in public companies, including serving as President of Equitable Resources Energy Co., an exploration and production subsidiary of Equitable Resources, Vice President of KRM Petroleum Inc., an independent exploration and production company, and Chief Executive Officer of Camelot Oil and Gas Company, a privately owned exploration and production company. He earned a Bachelor of Science in Petroleum Engineering in 1972 and a Masters of Engineering in Petroleum Engineering from the Colorado School of Mines in 1977. Mr. Townsend brings significant industry experience leading oil and gas companies to the Company’s management team and the Board of Directors.

Tiffany J. (“T.J.”) Thom, our Chief Financial Officer since September 2015, has more than 20 years of financial and operational experience in the energy industry. Between December 2014 and September 2015, Ms. Thom evaluated various investment and employment opportunities. Ms. Thom was a consultant for Energy XXI Gulf Coast, Inc. from July 2014 to December 2014. Ms. Thom served in various capacities for EPL from October 2000 until June 2014, when EPL was acquired by Energy XXI for $2.3 billion. Ms. Thom served as Principal Financial Officer of EPL from July 2009, as Senior Vice President of Business Development from September 2009, as Chief Financial Officer from June 2010 and as Executive Vice President from January 2014, to June 2014. Ms. Thom helped lead EPL through its Chapter 11 bankruptcy proceeding which culminated in 2009. From 1992 to 2000, Ms. Thom served as Senior Reservoir Engineer for Exxon Production Company and ExxonMobil Company with operational roles, including reservoir engineering and subsurface completion engineering for numerous offshore Gulf of Mexico properties. Ms. Thom has served as a member of the board of directors of Yates Petroleum Corporation since October 2015 and as a member of the board of directors of Patterson-UTI Energy Inc. since August 2014. Ms. Thom holds a B.S. in Engineering from the University of Illinois and an M.B.A. in Management with a concentration in Finance from Tulane University.

Brian K. Ayers was named Vice President of Geology for Rosehill Resources in April 2017. Mr. Ayers has over 35 years of geology, operations, and management experience in the oil and gas industry. Prior to Rosehill, Mr. Ayers served as Vice President of Geology for Tema from June 2012 to April 2017, and as Vice President of Land from June 2012 to May 2014. Mr. Ayers served Marshfield Oil and Gas as Consultant, Business Development and Geology from January 2012 to May 2012. Mr. Ayers has also held numerous executive positions for public and private companies, including President and Chief Executive Officer of Centurion Exploration Company, Senior Vice President of Geology for America Capital Energy Corporation, Vice President, Division Manager for Samson Lone Star and Vice President, Domestic Exploration for Coastal Oil & Gas Corporation. He began his career in 1980 as an Exploration Geophysicist at Texaco in New Orleans. Mr. Ayers served as an independent director on the Board of Directors of Tamaska Oil and Gas, Ltd. from 2007 to 2014. Mr. Ayers holds a Bachelors of Arts in Geophysical Science from The University of Chicago and a Masters of Business Administration from the Else School of Management, Millsaps College.

R. Colby Williford was named Vice President of Land for Rosehill Resources in April 2017. Mr. Williford has nearly 30 years of petroleum land management experience, including field and in-house positions in Texas, Louisiana, Oklahoma, New Mexico, Colorado, and Wyoming. From May 2014 to April 2017, Mr. Williford served as Vice President to Land for Tema. He held the same position with Momentum Oil & Gas, LLC, from April 2011 to May 2014. Additionally, Mr. Williford has served as Vice President of Land for Centurion Exploration Company and America Capital Energy Corporation, the U.S. oil & gas subsidiary of the ZhongRong Group, Shanghai, China. He began his career in 1985 as a field landman working for small to medium sized companies and transitioned to in-house work providing acquisition & divestiture due diligence, land management and contract negotiation. Mr. Williford holds a Bachelors of Business Administration in International Business from The University of Houston.

Board of Directors and Terms of Office of Directors

The Company’s amended and restated certificate of incorporation provides for the classification of our board of directors into three separate classes, with each class serving a three-year term. At the Special Meeting,

 

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the stockholders elected seven directors to our board of directors, with each Class I director having a term that expires at the Company’s annual meeting of stockholders in 2018, each Class II director having a term that expires at the Company’s annual meeting of stockholders in 2019 and each Class III director having a term that expires at the Company’s annual meeting of stockholders in 2020, or in each case until their respective successors are duly elected and qualified, or until their earlier resignation, removal or death.

Our board of directors consists of each of two individuals serving as Class I directors, two individuals serving as Class II directors and three individuals serving as Class III directors.

Independence of Directors

Following the completion of the Business Combination, Tema and our Sponsor control a majority of the combined voting power of all classes of our outstanding voting stock. As a result, we qualify as a “controlled company” within the meaning of the NASDAQ corporate governance standards and may elect not to comply with certain NASDAQ corporate governance requirements, including requirements that: a majority of the board of directors consist of independent directors; the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. We have elected to utilize these exemptions, and therefore do not have a majority of independent directors serving on our board and have individuals serving on our compensation committee and nominating and corporate governance committee that may not qualify as independent according to NASDAQ listing standards and the rules and regulations of the SEC. These independence requirements will not apply to us as long as we remain a controlled company.

The Company’s board of directors has determined that Messrs. Contino, Mayer, Quarls and Rosenberg are independent within the meaning of NASDAQ Rule 5605(a)(2).

Committees of the Board of Directors

The standing committees of the Company’s board of directors consist of an audit committee (the “Audit Committee”), a compensation committee (the “Compensation Committee”) and a corporate governance and nominating committee (the “Corporate Governance and Nominating Committee”). Each of the committees reports to the board of directors.

The composition, duties and responsibilities of these committees are set forth below.

Audit Committee

The principal functions of the Company’s Audit Committee are detailed in the Company’s Audit Committee charter, which is available on the Company’s website, and include:

 

•

the appointment, compensation, retention, replacement, and oversight of the work of the independent auditors and any other independent registered public accounting firm engaged by us;

 

•

pre-approving all audit and non-audit services to be provided by the independent auditors or any other registered public accounting firm engaged by us, and establishing pre-approval policies and procedures;

 

•

reviewing and discussing with the independent auditors all relationships the auditors have with the Company in order to evaluate their continued independence;

 

•

setting clear hiring policies for employees or former employees of the independent auditors;

 

•

setting clear policies for audit partner rotation in compliance with applicable laws and regulations;

 

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•

obtaining and reviewing a report, at least annually, from the independent auditors describing (i) the independent auditor’s internal quality-control procedures and (ii) any material issues raised by the most recent internal quality-control review, or peer review, of the audit firm, or by any inquiry or investigation by governmental or professional authorities, within, the preceding five years respecting one or more independent audits carried out by the firm and any steps taken to deal with such issues;

 

•

reviewing and approving any related party transaction required to be disclosed pursuant to Item 404 of Regulation S-K promulgated by the SEC prior to us entering into such transaction; and

 

•

reviewing with management, the independent auditors, and our legal advisors, as appropriate, any legal, regulatory or compliance matters, including any correspondence with regulators or government agencies and any employee complaints or published reports that raise material issues regarding our financial statements or accounting policies and any significant changes in accounting standards or rules promulgated by the Financial Accounting Standards Board, the SEC or other regulatory authorities.

Under the NASDAQ listing standards and applicable SEC rules, the Company is required to have at least three members of the Audit Committee, all of whom must be independent. Following the closing of the Business Combination, our Audit Committee consists of Messrs. Contino, Mayer and Quarls, with Mr. Contino serving as the Chair. We believe that Messrs. Contino, Mayer and Quarls qualify as independent directors according to the rules and regulations of the SEC with respect to audit committee membership. We also believe that Mr. Contino qualifies as our “audit committee financial expert,” as such term is defined in Item 401(h) of Regulation S-K.

Compensation Committee

The principal functions of the Company’s Compensation Committee are detailed in the Company’s Compensation Committee charter, which is available on the Company’s website, and include:

 

•

reviewing and approving on an annual basis the corporate goals and objectives relevant to the Company’s Chief Executive Officer’s compensation, evaluating its Chief Executive Officer’s performance in light of such goals and objectives and determining and approving the remuneration (if any) of its Chief Executive Officer based on such evaluation;

 

•

reviewing and approving on an annual basis the compensation of all of the Company’s other officers;

 

•

reviewing on an annual basis the Company’s executive compensation policies and plans;

 

•

implementing and administering the Company’s incentive compensation equity-based remuneration plans;

 

•

assisting management in complying with the Company’s proxy statement and annual report disclosure requirements;

 

•

approving all special perquisites, special cash payments and other special compensation and benefit arrangements for the Company’s officers and employees;

 

•

if required, producing a report on executive compensation to be included in the Company’s annual proxy statement; and

 

•

reviewing, evaluating and recommending changes, if appropriate, to the remuneration for directors.

Our Compensation Committee consists of Messrs. Mayer, Quarls, Rosenberg and Kovalik, with Mr. Mayer serving as the Chair.

 

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Nominating and Governance Committee

The principal functions of the Company’s Nominating and Governance Committee are detailed in the Company’s Corporate Governance and Nominating Committee charter, which is available on the Company’s website, and include:

 

•

identifying individuals qualified to become members of our board of directors, consistent with criteria approved by our board of directors;

 

•

overseeing the organization of our board of directors to discharge the board’s duties and responsibilities properly and efficiently;

 

•

identifying best practices and recommending corporate governance principles; and

 

•

developing and recommending to our board of directors a set of corporate governance guidelines and principles applicable to us.

The Nominating and Governance Committee also develops and recommends to the board of directors corporate governance principles and practices and assists in implementing them, including conducting a regular review of our corporate governance principles and practices. The Nominating and Governance Committee oversees the annual performance evaluation of the board of directors and the committees of the board of directors and makes a report to the board of directors on succession planning.

Our Nominating and Governance Committee consists of Messrs. Rosenberg, Contino and Kovalik, with Mr. Rosenberg serving as the Chair.

Indemnification of Directors and Executive Officers

Our amended and restated charter provides that our executive officers and directors are indemnified by us to the fullest extent authorized by Delaware law, as it now exists or may in the future be amended. In addition, our amended and restated certificate of incorporation provides that our directors will not be personally liable for monetary damages to us for breaches of their fiduciary duty as directors, except to the extent such exemption from liability or limitation thereof is not permitted by the DGCL.

We have entered into agreements with our executive officers and directors to provide contractual indemnification in addition to the indemnification provided for in our amended and restated certificate of incorporation. Our bylaws also permit us to maintain insurance on behalf of any executive officer, director or employee for any liability arising out of his or her actions, regardless of whether Delaware law would permit such indemnification. We have purchased a policy of directors’ and officers’ liability insurance that insures our executive officers, directors and director nominees against the cost of defense, settlement or payment of a judgment in some circumstances and insures us against our obligations to indemnify our executive officers and directors.

These provisions may discourage stockholders from bringing a lawsuit against our directors for breach of their fiduciary duty. These provisions also may have the effect of reducing the likelihood of derivative litigation against executive officers and directors, even though such an action, if successful, might otherwise benefit us and our stockholders. Furthermore, a stockholder’s investment may be adversely affected to the extent we pay the costs of settlement and damage awards against executive officers and directors pursuant to these indemnification provisions.

We believe that these provisions and the insurance and the indemnity agreements are necessary to attract and retain talented and experienced officers and directors.

 

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Financial Code of Ethics

We have adopted a Financial Code of Ethics applicable to our directors, executive officers and employees. We have filed copies of our Financial Code of Ethics as an exhibit to our Current Report on Form 8-K filed on May 3, 2017. You will be able to review these documents by accessing our public filings at the SEC’s web site at www.sec.gov. In addition, a copy of the Financial Code of Ethics will be provided without charge upon request from us. We intend to disclose any amendments to or waivers of certain provisions of our Financial Code of Ethics Code of Ethics in a Current Report on Form 8-K. See “Where You Can Find More Information.”

 

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EXECUTIVE AND DIRECTOR COMPENSATION

KLR Energy Acquisition Corp.

This section sets forth the pre-Business Combination compensation of the Company’s named executive officers and non-employee directors, and is presented based on the reduced disclosure rules applicable to emerging growth companies.

For the fiscal year ended December 31, 2016, our “Named Executive Officers,” or “NEOs,” are:

 

•

Gary C. Hanna, Chief Executive Officer;

 

•

Edward Kovalik, President; and

 

•

T.J. Thom, Chief Financial Officer.

Prior to the Business Combination, other than Ms. Thom, none of the Company’s named executive officers or non-employee directors had received any compensation from us for services rendered to us. Since our formation, we have not granted any equity compensation awards to any of our named executive officers or non-employee directors. Our Sponsor, executive officers and directors, and their respective affiliates, are reimbursed for any out-of-pocket expenses incurred in connection with activities on our behalf such as identifying potential target businesses and performing due diligence on suitable business combinations. Our non-employee directors review on a quarterly basis all payments that are made to our Sponsor, officers, directors and their respective affiliates.

2016 Summary Compensation Table

 

Name and Principal Position		Year				Salary ($)				Total ($)
Gary C. Hanna			2016				—				—
Chief Executive Officer
Edward Kovalik			2016				—				—
President
T.J. Thom.			2016				158,197				158,197
Chief Financial Officer

Narrative Disclosure to Summary Compensation Table

Employment Agreement

The Company previously entered into an employment agreement with Ms. Thom. The agreement with Ms. Thom provides for an annualized base salary of $200,000 through December 31, 2016 and a bonus payment equal to the amount of such base salary that Ms. Thom would have received for the period between January 1, 2017 and the effective date the Business Combination, so long as she remains employed by us continuously through the date of the Business Combination. We have not entered into an employment agreement with, and did not provide any cash or other compensation to, either of Mr. Hanna or Mr. Kovalik in fiscal 2016.

Base Salary

Under the terms of her employment agreement, Ms. Thom received an annualized base salary of $200,000 starting on the effective date of our initial public offering through December 31, 2016. We did not pay a base salary to either of Mr. Hanna or Mr. Kovalik in fiscal 2016.

 

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Bonus

Our Named Executive Officers generally do not receive a bonus. However, under the terms of her employment agreement, in lieu of any base salary for fiscal 2017 prior to the Business Combination, the Company has an obligation to pay Ms. Thom a bonus payment equal to the amount of base salary that Ms. Thom would have received for the period between January 1, 2017 and the effective date of the Business Combination.

Rosehill Operating

This section sets forth the pre-Business Combination compensation of Rosehill Operating’s named executive officers and directors, and is presented based on the reduced disclosure rules applicable to emerging growth companies.

Compensation of Rosehill Operating’s Named Executive Officers

During 2016, Rosehill Operating’s named executive officers were employees of Tema, a wholly-owned subsidiary of Rosemore. In connection with the Business Combination, Tema’s executive officers and certain other employees providing services to Tema became employees of Rosehill Operating.

Summary Compensation Table

 

Name and Principal Position		Year				Salary  ($)				Bonus ($)(1)				Non-Equity Incentive Plan Compensation ($)(2)				Stock Awards ($)				All Other Compensation ($)(3)				Total ($)
J. Alan Townsend, Chief Executive Officer			2016				307,000				112,285				76,321				—				43,721	(4)			539,327
Brian Ayers, Vice President, Geology			2016				267,750				53,550				53,282				—				16,926	(5)			391,508
Colby Williford Vice President, Land			2016				240,000				48,000				34,328				—				10,776	(6)			333,104

 

(1)	Amounts in this column reflect the discretionary bonus paid by Rosehill Operating to its named executive officers for services provided in 2016.

(2)

Amounts in this column reflect awards earned by our named executive officers under Rosemore’s long-term incentive compensation program, referred to as the Value Added Rights (“VAR”) program. The numbers represented in this column reflect an estimate of amounts earned at the December 31, 2016 evaluation date under the VAR program. This estimate is based on the price per VAR used for VAR awards evaluated in 2015. The price per VAR for awards evaluated in 2016 likely will be determined in conjunction with Rosemore’s third party consultants in the third quarter of 2017.

(3)

Amounts in this column reflect, for all named executive officers, matching contributions to Rosemore Employee Savings Plan and Trust (the “401(k) Plan”) made on behalf of Rosehill Operating’s named executive officers and employer contributions made on behalf of the named executive officers under the Rosemore Employee Retirement Account Plan (the “ERA Plan”), the Supplemental Savings Plan, and the Supplemental Executive Retirement Plan for 2016. See “—Retirement Benefits” and “—Nonqualified Retirement Plans” below for more information on employer contributions to the 401(k) Plan and ERA Plan and other reflected compensation.

(4)

Includes matching contributions under the 401(k) plan of $3,594, employer contributions under the Supplemental Savings Plan, Supplemental Executive Retirement Plan, and the ERA Plan of $8,686, $2,940, and $17,365, respectively, includes $336 of life insurance premiums, and an annual automobile allowance of $10,800.

(5)	Includes matching contributions under the 401(k) plan of $10,710, employer contributions under the ERA Plan of $5,355 and includes $861 of life insurance premiums.

(6)	Includes matching contributions under the employer contributions under the ERA Plan of $9,315 and includes $1,461 of life insurance premiums.

 

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Incentive Plans

VAR Incentive Plan. In 2012, Tema’s parent company, Rosemore, on behalf of itself and its subsidiaries, adopted and approved the Rosemore, Inc. Value Added Rights Plan (the “VAR Plan” and each right granted thereunder, a “VAR”). The VAR Plan is a long-term incentive plan, which provides participants a monetary award based on appreciation in the value of Tema and Gateway. There are two classes of VARs, Class A VARs and Class B VARs. Pursuant to the VAR Plan, certain eligible Tema employees entered into Tema Class B Value Added Rights Grant Agreements, which provided them with the ability to benefit from the growth in Tema’s operations and business. Class B VARs are valued based on the change in the combined value of Tema and Rosemore’s Gateway Gathering and Marketing Company subsidiary (the “Tema/Gateway Value”). The value of a Class B VAR is equal to sum of (a) the dollar amount found by dividing the Tema/Gateway Value on the last day of the performance period (the evaluation date) by the number of Class B VARs authorized minus (b) the dollar amount found by dividing the Tema/Gateway Value on the reference date of the performance period by the number of Class B VARs authorized. Successive VARs awarded have performance periods of three years. Payments of awards under the VAR Plan are evaluated on December 31 of each fiscal year and paid on or before October 15 of the year following such evaluation date.

The VAR Plan remained with Tema after the closing of the Business Combination and was not transferred to Rosehill Operating. Post-Business Combination treatment of payments of awards with settlement dates subsequent to 2016 have not been determined between Rosemore, Tema and the executive officers.

Retirement Benefits

Prior to the Business Combination, Rosehill Operating’s named executive officers were eligible to participate in a 401(k) Plan sponsored by an affiliate of Rosehill Operating pursuant to which employees could elect to contribute a portion of their base compensation to a tax-qualified retirement account. Rosehill Operating, or its affiliate, provided matching contributions equal to 100% of the first 3% and 50% of the next 2% of employees’ eligible compensation contributed to the 401(k) Plan. Employees were 100% vested in the matching contributions made to their 401(k) Plan account and the employee contributions they made to their 401(k) Plan account at all times. Employees generally receive a distribution of the vested portion of their 401(k) Plan account upon (i) a termination of employment, (ii) normal retirement, (iii) late retirement, (iv) disability or (v) death. Following the Business Combination, employees of Rosehill Operating, including the named executive officers, may no longer make contributions or receive matching contributions under this 401(k) Plan.

Rosehill Operating’s named executive officers also participated in a defined benefit pension plan of Rosemore, which is referred to as the Employee Retirement Account (“ERA”). Under such plan, Rosehill Operating made a minimum contribution of 2% of the participating employee’s base salary to the ERA, regardless of employee contribution. In addition, a participating employee could contribute to the ERA 1.5% of the employee’s base salary up to the social security wage base (“SSWB”) and 3% of the employee’s base salary over the SSWB. If a participating employee made such a contribution to the ERA, Rosehill Operating made an additional employer contribution to the ERA on the employee’s behalf. The amount of the employer contribution was the following percentage of compensation for compensation up to the SSWB: (a) 3.5% for 1-4 years of service; (b) 5% for 5-9 years of service; (c) 6% for 10-19 years of service; and (d) 7.5% for 20 years or more of service. The amount of the employer contribution was the following percentage of compensation for compensation in excess of the SSWB: (a) 4.5% for 1-4 years of service; (b) 6% for 5-9 years of service; (c) 7% for 10-19 years of service; and (d) 8.5% for 20 years or more of service. Following the Business Combination, benefits for employees of Rosehill Operating under the ERA were frozen.

Nonqualified Retirement Plans

Rosehill Operating’s named executive officers could also participate in a nonqualified deferred compensation plan, referred to as the Supplemental Savings Plan. Under the plan, an employee could elect to

 

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defer up to 60% of the employee’s compensation for that year. Rosehill Operating provided a matching contribution in an amount equal to 100% of the first 3% and 50% of the next 2% of the employees’ eligible compensation deferred under the plan. Participating employees vest in matching contributions pursuant to the vesting schedule that applies to employer contributions under the 401(k) Plan. Following the Business Combination, the named executive officers may no longer make contributions or receive matching contributions under the Supplemental Savings Plan.

Rosehill Operating’s named executive officers could also participate in a nonqualified deferred compensation plan, referred to as the Deferred Incentive Bonus Plan. Under the plan, an employee could elect to defer all or part of the compensation to be earned by the employee for the year as a contribution. A participating employee is immediately 100% vested in amounts deferred under the plan. Following the Business Combination, the named executive officers may no longer defer compensation under the Deferred Incentive Bonus Plan.

Rosehill Operating’s named executive officers could also participate in a nonqualified deferred compensation plan, referred to as the Rosehill, Inc. Supplemental Executive Retirement Plan. The Plan is designed to provide a participant with a benefit equal to (i) minus (ii) where (i) is the benefit that the participant would have accrued under the ERA in the absence of the Internal Revenue Code’s limit on compensation that may be recognized by the ERA’s benefit formula and the Internal Revenue Code’s limit on benefits that may be paid by the ERA and (ii) is the benefit that the participant actually accrued under the ERA. Following the Business Combination, benefits for the named executive officers under the Supplemental Executive Retirement Plan were frozen.

Employment, Severance or Change in Control Agreements

Prior to the Business Combination, Rosehill Operating historically had not maintained any employment, severance or change in control agreements with its named executive officers, other than certain triggering events under the VAR Plan, which were not applicable to the Business Combination.

Compensation of Directors

Individuals serving on the board of directors of Tema did not receive any compensation for their services during fiscal year 2016, other than Tommie E. Yates, who received $3,000 per meeting attended in 2016.

 

Name		Fees Earned or  Paid in Cash Compensation				All Other Compensation				Total
Henry A. Rosenberg, Jr.		$	—			$	—			$	—
Frank B. Rosenberg			—				—				—
Paul J. Ebner			—				—				—
J. Alan Townsend			—				—				—
Tommie E. Yates			18,000				—				18,000

Actions Taken Since Fiscal Year End

Rosehill Resources Inc. 2017 Long Term Incentive Plan

On April 27, 2017, the stockholders of the Company approved the Rosehill Resources Inc. Long Term Incentive Plan, dated as of April 27 2017 (the “LTIP”), which permits the grant of a number of different types of equity, equity-based, and cash awards to employees directors and consultants. The maximum aggregate number of shares of common stock available for any and all awards under the LTIP shall not exceed 7,500,000 (subject to any adjustment due to recapitalization or reorganization permitted under the LTIP). The purpose of the LTIP is to provide a means to attract and retain qualified service providers by affording such individuals a means to acquire

 

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and maintain stock ownership or awards, the value of which is tied to the performance of the Company. The LTIP also provides additional incentives and reward opportunities designed to strengthen such individuals’ concern for the welfare of the Company and their desire to remain in its employ.

Employment Agreements

In connection with the closing of the Business Combination, we entered into employment agreements with each of Messrs. Townsend, Ayers, and Williford and certain other executive officers (the “Employment Agreements”) setting forth the terms and conditions of their employment. The Employment Agreements provide for a two-year initial term beginning on the closing date of the Business Combination, which initial term is automatically extended for successive, additional one-year periods, unless either the applicable executive or we provide 30 days’ prior written notice that no such automatic extension will occur. The Employment Agreements provide for an annualized base salary and a discretionary annual bonus based on performance targets determined annually by the Compensation Committee. The Employment Agreements also provide that the applicable executives will be eligible to receive annual awards under the LTIP on the terms and conditions determined by the Compensation Committee from time to time. While employed under the Employment Agreements, the executives are eligible for certain additional benefits, including reimbursement of reasonable business expenses, paid vacation, and participation in our benefit plans, programs or arrangements.

The Employment Agreements provide for potential severance benefits in connection with certain terminations of employment. Generally, the Employment Agreements provide that, upon a resignation by the applicable executive for “good reason” or upon a termination by us without “cause” (including upon the expiration of the then-existing initial term or renewal term, as applicable, due to non-renewal by us), then, subject to the applicable executive’s execution and non-revocation of a release within the time provided to do so, the applicable executive will be eligible to receive a severance payment in an amount equal to 12 months’ worth of the applicable executive’s base salary for the year in which such termination occurs, payable in a lump sum following such termination.

The Employment Agreements also contain certain restrictive covenants, including provisions that create restrictions, with certain limitations, on the applicable executive competing with the Company and its affiliates, soliciting any customers, or soliciting or hiring Company employees or inducing them to terminate their employment. These restrictions are generally intended to apply during the term of the executives’ employment with us and for the one-year period following termination of employment. The foregoing description of the Employment Agreements is qualified in its entirety by reference to the form of Employment Agreement filed as Exhibit 10.6.

Compensation of Non-Employee Directors

In connection with the closing of the Business Combination, the Company adopted a compensation policy for our non-employee directors (the “Non-Employee Director Compensation Policy”). Our non-employee directors are entitled to receive compensation for services they provide to us consisting of retainers, fees and equity compensation as described below. Each non-employee director will be eligible to receive the following for each complete calendar year pursuant to the Non-Employee Director Compensation Policy:

 

•

an annual retainer fee of $75,000 per year;

 

•

an additional $50,000 per year for the Chairman of the board of directors;

 

•

an additional retainer of $20,000 per year for the non-employee director serving as Chair of the Audit Committee;

 

•

an additional retainer of $15,000 per year for the non-employee director serving as Chair of the Compensation Committee; and

 

•

an additional retainer of $10,000 per year for the non-employee director serving as Chair of the Corporate Governance and Nominating Committee.

 

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All retainers are paid in cash on a quarterly basis in arrears. In addition, each director is reimbursed for: (1) travel and miscellaneous expenses to attend meetings and activities of the board of directors or its committees and (2) travel and miscellaneous expenses related to his or her participation in general education and orientation programs for directors.

In addition to cash compensation, the Company’s non-employee directors will receive annual equity-based compensation consisting of restricted stock awards with an aggregate grant date value equal to $140,000. The forfeiture restrictions applicable to the restricted stock awards will generally lapse on the one-year anniversary of the date of grant of such awards. The restricted stock awards granted to the Company’s non-employee directors will be subject to the terms and conditions of the LTIP and the award agreements pursuant to which such awards are granted.

 

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Founder Shares

In November 2015, pursuant to that certain Securities Subscription Agreement, dated as of November 20, 2015, our Sponsor purchased 4,312,500 shares of common stock (such stock, the “Founder Shares”), for $25,000, or approximately $0.006 per share. The Founder Shares are identical to the common stock included in the units sold in the IPO except that the Founder Shares are subject to certain transfer restrictions, as described in more detail below. In December 2015 and February and March 2016, our Sponsor returned to us, at no cost, an aggregate of 1,972,500 Founder Shares, which we cancelled. In January 2016, our Sponsor transferred 150,000 shares to Ms. Thom, 50,000 shares to Mr. Dow, and 10,000 shares to Messrs. Abbas, Buckner and York. In March 2016, Mr. Dow and Ms. Thom returned to us, at no cost, 10,000 and 30,000 Founder Shares, respectively, which we cancelled. Also in March 2016, the Sponsor forfeited an aggregate of 253,670 Founder Shares at no cost upon receiving the underwriters’ notice of only a partial exercise of their over-allotment option in connection with the IPO. All of the Founder Shares forfeited were cancelled by the Company. The 2,046,330 remaining Founder Shares represented 20.0% of the outstanding shares upon the completion of the IPO.

On April 28, 2017, all of the outstanding Founder Shares were automatically converted into 3,475,663 shares of Class A Common Stock in connection with the closing of the Business Combination. As used herein, unless the context otherwise requires, “Founder Shares” are deemed to include the shares of Class A Common Stock issued upon conversion thereof.

Subject to certain limited exceptions, 50% of the Founder Shares will not be transferred, assigned or sold until the earlier of (i) one year after the date of the consummation of Business Combination or (ii) the date on which the closing price of our common stock equals or exceeds $12.00 per share (as adjusted for stock splits, stock dividends, reorganizations and recapitalizations) for any 20 trading days within any 30-trading day period commencing 150 days after the Business Combination and pursuant to the transfer restrictions agreed upon by our Sponsor at the time of our IPO, the remaining 50% of the Founder Shares will not be transferred, assigned or sold until six months after the date of the consummation of the Business Combination, or earlier, in either case, if, subsequent to the Business Combination, we consummate a subsequent liquidation, merger, stock exchange or other similar transaction which results in all of our shareholders having the right to exchange their common stock for cash, securities or other property, which we refer to as the “Lock-Up Period.”

Private Placement Warrants

Simultaneously with the closing of the IPO, the Company consummated the private placement of 8,310,000 warrants at a price of $0.75 per warrant, of which 7,776,667 private placement warrants were sold to our Sponsor, and 533,333 private placement warrants were sold to EarlyBirdCapital, Inc. (“EBC”), the representative of the underwriters in the IPO, and its designees, generating gross proceeds of approximately $6.2 million.

On March 21, 2016, simultaneously with the exercise of the over-allotment, the Company consummated the private placement of an additional 98,838 private placement warrants to the Sponsor and EBC and its designees, among which 86,483 private placement warrants were purchased by the Sponsor and 12,355 private placement warrants were purchased by EBC and its designees, generating gross proceeds of approximately $74,000. The purchase price of the private placement warrants was added to the proceeds from the IPO to be held in the Trust Account pending completion of the Business Combination. Each private placement warrant entitles the holder to purchase one share of our Class A Common Stock at $11.50 per share.

The private placement warrants (including the Class A Common Stock issuable upon exercise of the private placement warrants) may not, subject to certain limited exceptions, be transferred, assigned or sold by our Sponsor until 30 days after the completion of the Business Combination and they will be non-redeemable so long as they are held by our Sponsor or its permitted transferees. Our Sponsor agreed to additional transfer restrictions

 

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relating to its common stock in connection with its entry into the SHRRA. If the private placement warrants are held by someone other than our Sponsor or its permitted transferees, the private placement warrants will be redeemable by the Company and exercisable by such holders on the same basis as the public warrants included in the units being sold in the IPO. Otherwise, the private placement warrants have terms and provisions that are identical to those of the public warrants sold as part of the units issued in the IPO.

Shareholders’ and Registration Rights Agreement

The holders of the Founder Shares and private placement warrants hold registration rights to require the Company to register the sale of any of the securities held by them pursuant to a registration rights agreement. The holders of these securities, including Anchorage, are entitled to make up to three demands, excluding short form registration demands, that the Company register such securities for sale under the Securities Act. In addition, these holders, including Anchorage, have “piggy-back” registration rights to include their securities in other registration statements filed by the Company. The Company will bear the costs and expenses of filing any such registration statements. The SHRRA governs the rights and obligations of our Sponsors and Anchorage with respect to the Company following the closing of the Business Combination.

Related Party Transactions

Our Sponsor and its affiliates loaned the Company $275,000 in the aggregate by the issuance of unsecured promissory notes, which we refer to as the “Notes”, for $275,000 to cover expenses related to the IPO. These Notes were non-interest bearing and payable on the completion of the IPO. In October 2016, the sponsor provided a commitment to loan KLRE up to an additional $100,000 for working capital purposes. On March 1, 2017, KLRE borrowed the full amount under this commitment.

If any of our executive officers or directors becomes aware of a business combination opportunity that falls within the line of business of any entity to which he or she has then current fiduciary or contractual obligations, he or she may be required to present such business combination opportunity to such entity prior to presenting such business combination opportunity to us. Our executive officers and directors currently have certain relevant fiduciary duties or contractual obligations that may take priority over their duties to us.

Prior to the completion of the Business Combination, KLR Group Holdings, LLC, an affiliate of our Sponsor, provided, at no cost to KLRE, office space and general administrative services.

Pursuant to an employment agreement entered into between us and Ms. Thom, we paid Ms. Thom an annualized salary of $200,000 from the consummation of the IPO through December 31, 2016. In lieu of any salary in 2017, Ms. Thom is eligible to receive a bonus equal to the amount of salary she would have received from January 1, 2017 through the date of our initial business combination, or approximately $65,000. We have historically reimbursed an affiliate of our Sponsor for certain expenses incurred in connection with the employment of Mr. Hanna and Ms. Thom, including employment related taxes (to be paid in connection with Ms. Thom’s annual salary and bonus) and health benefits.

Our Sponsor, executive officers and directors, or any of their respective affiliates, have historically been reimbursed for any out-of-pocket expenses incurred in connection with activities on our behalf such as identifying potential target businesses and performing due diligence on suitable business combinations. Our audit committee reviews on a quarterly basis all payments that are made to our Sponsor, executive officers, directors or our or their affiliates and determines which expenses and the amount of expenses that will be reimbursed. There is no cap or ceiling on the reimbursement of out-of-pocket expenses incurred by such persons in connection with activities on our behalf.

In connection with the consummation of the Business Combination, or thereafter, we may retain KLR Group to provide certain financial advisory, underwriting, capital raising, and other services for which they may

 

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receive fees upon consummation of such business combination or thereafter. The amount of fees we pay to KLR Group will be based upon the prevailing market for similar services rendered by comparable investment banks for such transactions at such time, and will be subject to the review of our audit committee pursuant to the audit committee’s policies and procedures relating to transactions that may present conflicts of interest.

In October 2016, we entered into an agreement with a placement agent and KLR Group in connection with the PIPE Investment. As compensation for the services, we paid the placement agent and KLR Group a cash fee equal to 5.5% of the aggregate gross proceeds of the PIPE Investment (or $4.125 million). Such fee has been split 50-50 among the placement agent and KLR Group.

At the time of our initial public offering, we engaged EBC as an advisor in connection with our business combination. We agreed to pay EBC a cash fee for such services upon the consummation of our initial business combination in an amount equal to $2,800,000 (exclusive of any applicable finders’ fees which might become payable). Of such amount, we were allowed to allocate 1% of the gross proceeds of our initial public offering to other firms that assisted us with our initial business combination, and in connection with the closing of the Business Combination, we allocated $818,530 to KLR Group in consideration of its role in assisting us with our initial business combination.

Agreements Relating to Our Business Combination

Shareholders’ and Registration Rights Agreement

Concurrently with the execution of the Business Combination Agreement, KLRE entered into the Shareholders’ and Registration Rights Agreement (the “SHRRA”) with our Sponsor and Tema (each an “SHRRA Sponsor” and together, the “SHRRA Sponsors”) and Anchorage Illiquid Opportunities V, L.P. and AIO AIV 3 Holdings, L.P. (collectively, “Anchorage”), the primary investor in the Private Placement, which will govern the rights and obligations of the SHRRA Sponsors and Anchorage with respect to KLRE following the closing of the Business Combination. Pursuant to the terms of the SHRRA, and subject to certain exceptions, the SHRRA Sponsors will be bound by restrictions on the transfer of (i) 33% of their Common Stock (as defined in the SHRRA) through the first anniversary of the closing of the Business Combination and (ii) 67% of their Common Stock through the second anniversary of the closing of the Business Combination, provided that sales of Common Stock above certain specified prices will be permitted between the first and second anniversaries of the closing of the Business Combination.

Pursuant to the SHRRA, the SHRRA Sponsors and Anchorage are entitled to certain registration rights, including the right to initiate two underwritten offerings in any twelve-month period and unlimited piggyback registration rights, subject to customary black-out periods, cutback provisions and other limitations as set forth in the SHRRA. Pursuant to the SHRRA, as promptly as practicable and in no event later than seven days following the completion of the Business Combination, KLRE has agreed to file with the SEC a shelf registration statement relating to the offer and sale of the Registrable Securities (as defined in the SHRRA) owned by the SHRRA Sponsors and Anchorage (and any permitted transferees) and to keep such shelf registration statement effective on a continuous basis until the date as of which all such Registrable Securities have been sold or another registration statement is filed under the Securities Act of 1933, as amended (the “Securities Act”).

Subject to specified ownership thresholds, our Sponsor is entitled to designate two directors for appointment to the Board, Tema is entitled to designate four directors and Anchorage is entitled to designate one director. Each SHRRA Sponsor and Anchorage is entitled to appoint a representative or observer on each committee of the Board. Our Sponsor initially designated Gary C. Hanna (who serves as the Chairman of the Board) and Edward Kovalik, Tema initially designated J.A. (Alan) Townsend, Frank Rosenberg, Paul Ebner and Fransis Contino and Anchorage designated Harry Quals. Pursuant to the terms of the SHRRA, each SHRRA Sponsor must vote for the designees of the other SHRRA Sponsor and is entitled to replace any of its designees that are removed from the Board.

 

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Also pursuant to the SHRRA, during the period beginning on the date of closing of the Business Combination and ending on the two year anniversary thereof, the Board may not approve, or cause Rosehill Operating to approve, certain Major Transactions (as such defined in the SHRRA) without the affirmative vote of at least 70% of the directors then serving on the Board. In addition, Anchorage will have preemptive rights under the SHRRA to participate in future equity issuances by KLRE, subject to certain exceptions, so as to maintain its then-current percentage ownership of our capital stock.

Certain rights and obligations of the SHRRA Sponsor and Anchorage under the SHRRA will automatically cease if the SHRRA Sponsor and Anchorage (i) no longer hold any equity securities of KLRE or (ii) no longer have the right to designate an individual for nomination to the Board.

Subscription Agreements

In connection with its entry into the Business Combination Agreement, KLRE entered into Subscription Agreements, each dated as of December 20, 2016, with our Sponsor and each of The K2 Principal Fund, L.P., Anchorage Illiquid Opportunities V, L.P., AIO V AIV 3 Holdings, L.P. and Geode Diversified Fund, a segregated account of Geode Capital Master Fund Ltd., pursuant to which, among other things, KLRE issued and sold in a private placement an aggregate of 75,000 shares of Series A Preferred Stock, which will be convertible into shares of Class A Common Stock at a conversion price of $11.50 per share (subject to certain adjustments) and (b) 5,000,000 Warrants for aggregate gross proceeds of $75 million. Additionally, our Sponsor contributed 476,540 shares of Class A Common Stock to the purchasers in the Private Placement. The proceeds from the Private Placement were used to fund the cash portion of the consideration required to effect the Business Combination and any remaining proceeds will be used for general corporate purposes, including to finance development and acquisition activities following the consummation of the Business Combination.

Pursuant to the Subscription Agreements, purchasers of Series A Preferred Stock and Warrants in the Private Placement are entitled to certain registration rights, subject to customary black-out periods, cutback provisions and other limitations as set forth therein.

Side Letter

On December 20, 2016, our Sponsor and Rosemore, Inc. entered into a Side Letter pursuant to which the parties agreed to backstop redemptions by the Company’s public stockholders in excess of 30% of the outstanding shares of Class A common stock by purchasing shares of Class A common stock or Series A Preferred Stock in an amount up to $20 million. On the closing date of the Business Combination, the Company sold 2,200 shares of Series A Preferred Stock to our Sponsor and 17,800 shares of Series A Preferred Stock to Rosemore Holdings, Inc., an affiliate of Rosemore, Inc., pursuant to the Side Letter.

Tax Receivable Agreement

On April 27, 2017, in connection with the closing of the Business Combination, KLRE entered into that certain Tax Receivable Agreement (the “Tax Receivable Agreement”) with Tema. The Tax Receivable Agreement generally provides for the payment by the Company to Tema of 90% of the net cash savings, if any, in U.S. federal, state and local income tax that the Company actually realizes (or is deemed to realize in certain circumstances) in periods after the closing of the Business Combination as a result of: (i) any tax basis increases in the assets of Rosehill Operating resulting from the distribution to Tema of the Cash Consideration, the shares of Class B common stock and the warrants and the assumption of the Tema Liabilities in connection with the Business Combination, (ii) the tax basis increases in the assets of Rosehill Operating resulting from the redemption by Rosehill Operating or the exchange by the Company, as applicable, of the membership interests in Rosehill Operating (the “Rosehill Operating Common Units”) for Class A common stock or cash, as applicable, and (iii) imputed interest deemed to be paid by the Company as a result of, and additional tax basis arising from, payments it makes under the Tax Receivable Agreement. The Tax Receivable Agreement also provides that, until

 

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36 months from the closing date of the Business Combination (the “Protection Period”), for so long as Tema beneficially holds at least 20% of the total issued and outstanding equity of Rosehill Operating (excluding Tema’s beneficial ownership of Rosehill Operating through Tema’s ownership of Class A common stock of the Company), the Company shall not cause Rosehill Operating to sell, exchange or dispose of Contributed Assets (as defined in the Business Combination Agreement) in any 12-month period during the Protection Period if, following such disposition, the cumulative aggregate amount realized (as that term is defined in Section 1001 of the Internal Revenue Code of 1986, as amended) from all dispositions of Contributed Assets during such 12-month period would be in excess of $40 million, without the consent of Tema, which consent may be granted or withheld in Tema’s sole discretion. The Company shall provide notice to Tema of any proposed disposition of Contributed Assets which would have an amount realized in excess of $20 million and the material terms of such disposition no later than 15 business days prior to the proposed disposition. Due to the uncertainty surrounding the amount and timing of future redemptions of Rosehill Operating Common Units by Tema, it is uncertain as to when payments under the Tax Receivable Agreement will commence. However, it is expected that payments will continue to be made under the Tax Receivable Agreement for 15 years after the date of the last exchange of the Rosehill Operating Common Units by Tema.

The foregoing description of the Tax Receivable Agreement does not purport to be complete and is qualified in its entirety by the terms and conditions of the Tax Receivable Agreement, which is attached hereto as Exhibit 10.1, and is incorporated herein by reference.

Amended and Restated Limited Liability Company Agreement of Rosehill Operating

At the closing of the Business Combination, KLRE and Tema entered into that certain First Amended and Restated Limited Liability Company Agreement of Rosehill Operating (the “A&R LLC Agreement”). Following the closing of the Business Combination, we operate our business through Rosehill Operating and its subsidiaries. The operations of Rosehill Operating, and the rights and obligations of the holders of the Rosehill Operating Common Units, are set forth in the A&R LLC Agreement.

Appointment as Managing Member. Under the A&R LLC Agreement, we are a member and the sole managing member of Rosehill Operating. As the sole managing member, we control all of the day-to-day business affairs and decision-making of Rosehill Operating without the approval of any other member, unless otherwise stated in the A&R LLC Agreement. As such, we, through our officers and directors, are responsible for all operational and administrative decisions of Rosehill Operating and the day-to-day management of Rosehill Operating’s business.

Compensation. We are not entitled to compensation for our services as managing member. We are entitled to reimbursement by Rosehill Operating for any costs, fees or expenses incurred on behalf of Rosehill Operating (including costs of securities offerings not borne directly by members, board of directors compensation and meeting costs, cost of periodic reports to its stockholders, litigation costs and damages arising from litigation, accounting and legal costs); provided that we will not be reimbursed for any of our income tax obligations.

Distributions. The A&R LLC Agreement requires Rosehill Operating to make a corresponding cash distribution to the Company at any time a dividend is to be paid by us to the holders of our Series A Preferred Stock. The A&R LLC Agreement allows for distributions to be made by Rosehill Operating to its members on a pro rata basis in accordance with the number of Rosehill Operating Common Units owned by each member out of funds legally available therefor. We expect Rosehill Operating may make distributions out of distributable cash periodically to the extent permitted by the debt agreements of Rosehill Operating and necessary to enable us to cover our operating expenses and other obligations, as well as to make dividend payments, if any, to the holders of our Class A common stock. In addition, the A&R LLC Agreement generally requires Rosehill Operating to make pro rata distributions to its members, including us, in an amount at least sufficient to allow us to (i) pay our taxes and (ii) satisfy our obligations under the Tax Receivable Agreement.

 

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Rosehill Operating Common Unit Redemption Right. The A&R LLC Agreement provides Tema with a redemption right, which entitles Tema to cause Rosehill Operating to redeem, from time to time, all or a portion of its Rosehill Operating Common Units (and a corresponding number of shares of Class B common stock) for, at Rosehill Operating’s option, newly-issued shares of our Class A common stock on a one-for-one basis or a cash payment equal to the average of the volume-weighted closing price of one share of Class A common stock for the twenty trading days prior to the date Tema delivers a notice of redemption for each Rosehill Operating Common Unit redeemed (subject to customary adjustments, including for stock splits, stock dividends and reclassifications). In the event of a “Reclassification Event” (as defined in the A&R LLC Agreement), the managing member is to ensure that each Rosehill Operating Common Unit (and a corresponding share of Class B common stock) is redeemable for the same amount and type of property, securities or cash that a share of Class A common stock becomes exchangeable for or converted into as a result of such “Reclassification Event.” Upon the exercise of the redemption right, Tema will surrender its Rosehill Operating Common Units (and a corresponding number of shares of Class B common stock) to Rosehill Operating and (i) Rosehill Operating shall cancel such Rosehill Operating Common Units and issue to the Company a number of Rosehill Operating Common Units equal to the number of surrendered Rosehill Operating Common Units and (ii) the Company shall cancel the surrendered shares of Class B common stock. The A&R LLC Agreement requires that we contribute cash or shares of our Class A common stock to Rosehill Operating in exchange for the issuance to the Company described in clause (i). Rosehill Operating will then distribute such cash or shares of our Class A common stock to Tema to complete the redemption. Upon the exercise of the redemption right, we may, at our option, effect a direct exchange of cash or our Class A common stock for such Rosehill Operating Common Units in lieu of such a redemption.

Maintenance of One-to-One Ratios. The A&R LLC Agreement includes provisions intended to ensure that we at all times maintain a one-to-one ratio between (a) (i) the number of outstanding shares of Class A common stock and (ii) the number of Rosehill Operating Common Units owned by the Company (subject to certain exceptions for certain rights to purchase equity securities of the Company under a “poison pill” or similar shareholder rights plan, if any, certain convertible or exchangeable securities issued under the Company’s equity compensation plans and certain equity securities issued pursuant to the Company’s equity compensation plans (other than a stock option plan) that are restricted or have not vested thereunder) and (b) (i) the number of other outstanding equity securities of the Company (including the Series A Preferred Stock and the warrants) and (ii) the number of corresponding outstanding equity securities of Rosehill Operating. These provisions are intended to result in Tema having a voting interest in the Company that is identical to Tema’s economic interest in Rosehill Operating.

Transfer Restrictions. The A&R LLC Agreement generally does not permit transfers of Rosehill Operating Common Units by members, subject to limited exceptions. Any transferee of Rosehill Operating Common Units must, among other things, assume by written agreement all of the obligations of a transferring member with respect to the transferred units.

Dissolution. The A&R LLC Agreement provides that Rosehill Operating shall dissolve upon the earlier of the sale of all or substantially all of the assets of Rosehill Operating or upon the determination of the managing member. Upon a dissolution event, the proceeds of a liquidation will be distributed in the following order: (i) first, to pay the expenses of winding up Rosehill Operating; (ii) second, to pay debts and liabilities owed to creditors of Rosehill Operating; and (iii) third, to set up cash reserves which the managing member reasonably deems necessary for contingent or unforeseen liabilities or certain future payments and (iv) fourth, (A) to the holders of Series A preferred units pursuant to the terms of such securities and (B) then to the members pro-rata in accordance with their respective relative ownership of Rosehill Operating Common Units.

Indemnification and Fiduciary Duties. The A&R LLC Agreement provides for indemnification of the managing member, members and officers of Rosehill Operating and their respective subsidiaries or affiliates and provides that, except as otherwise provided therein, we, as the managing member of Rosehill Operating, have the same fiduciary duties to Rosehill Operating and its members as are owed to a corporation organized under Delaware law and its stockholders by its directors.

 

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A copy of the A&R LLC Agreement is filed with this prospectus as Exhibit 10.3 and is incorporated herein by reference, and the foregoing description of the A&R LLC Agreement is qualified in its entirety by reference thereto.

Gathering Agreements

At the closing of the Business Combination, Rosehill Operating entered into certain crude oil gathering and gas gathering agreements with Gateway, a wholly-owned subsidiary of Rosemore, Inc., pursuant to which Gateway will receive, gather, store, treat, and redeliver crude oil and gas production from receipt points within certain production areas located in Loving County, Texas that are exclusively dedicated by Rosehill Operating to Gateway, at certain delivery points for downstream transportation. Each gathering agreement has a term of 10 years that automatically renews on a year-to-year basis until terminated by either party pursuant to the agreements. Rosehill Operating will pay Gateway a fee for such services set forth in the gathering agreements. Gateway provided the same services to Tema in the same dedicated area before the Business Combination.

Copies of the crude oil gathering agreement and gas gathering agreement are filed with this prospectus as Exhibit 10.6 and 10.7 and are incorporated herein by reference, and the foregoing descriptions of each of the crude oil gathering agreement and gas gathering agreement are qualified in their entirety by references thereto.

Indemnification Agreements

Effective as of the closing date of the Business Combination, we entered into indemnification agreements with certain of our directors and executive officers. Each indemnification agreement provides that, subject to limited exceptions, and among other things, we will indemnify the director or executive officer to the fullest extent permitted by law for claims arising in his or her capacity as our director or officer.

A copy of a form indemnification agreement is filed with this prospectus as Exhibit 10.2 and is incorporated herein by reference, and the foregoing description of the indemnification agreements is qualified in its entirety by reference thereto.

Credit Agreement

On April 27, 2017, Rosehill Operating and PNC Bank, National Association (as lender, Administrative Agent and Issuing Bank), and each of the lenders from time to time party thereto (collectively, the “Lenders”) entered into the Credit Agreement.

Pursuant to the terms and conditions of the Credit Agreement, Rosehill Operating has a revolving line of credit and a letter of credit facility of up to $250 million, subject to a borrowing base that is determined semi-annually by the Lenders based upon Rosehill Operating’s financial statements and the estimated value of its oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. Rosehill Operating and the Lenders may each request an additional redetermination of the borrowing base once between two successive scheduled redeterminations. The borrowing base will be automatically reduced upon the issuance or incurrence of debt under senior unsecured notes or upon Rosehill Operating’s or any of its subsidiary’s disposition of properties or liquidation of hedges in excess of certain thresholds. Amounts borrowed under the Credit Agreement may not exceed the borrowing base. Rosehill Operating’s initial borrowing base is $55 million, which may be increased with the consent of all lenders. The senior secured revolving credit facility also does not permit Rosehill Operating to borrow funds if at the time of such borrowing, Rosehill Operating is not in pro forma compliance with the financial covenants. Additionally, Rosehill Operating’s borrowing base may be reduced in connection with the subsequent redetermination of the borrowing base. The amounts outstanding under the senior secured revolving credit facility are secured by first priority liens on substantially all of Rosehill Operating’s oil and natural gas properties and associated assets and all of the stock of Rosehill Operating’s material operating subsidiaries that are guarantors of the senior secured revolving credit facility. If an event of

 

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default occurs under the senior secured revolving credit facility, PNC Bank, National Association will have the right to proceed against the pledged capital stock and take control of substantially all of Rosehill Operating and Rosehill Operating’s material operating subsidiaries that are guarantors’ assets.

Borrowings under the Credit Agreement will bear interest at a base rate plus an applicable margin ranging from 1.00% to 2.00% or at LIBOR plus an applicable margin ranging from 2.00% to 3.00%. The Credit Agreement will mature on April 27, 2022.

The Credit Agreement contains various affirmative and negative covenants. These negative covenants may limit Rosehill Operating’s ability to, among other things: incur additional indebtedness; make loans to others; make investments; enter into mergers; make or declare dividends or distributions; enter into commodity hedges exceeding a specified percentage of Rosehill Operating’s expected production; enter into interest rate hedges exceeding a specified percentage of Rosehill Operating’s outstanding indebtedness; incur liens; sell assets; and engage in certain other transactions without the prior consent of PNC Bank, National Association and/or lenders.

The Credit Agreement also requires Rosehill Operating to maintain the following financial ratios: (1) a working capital ratio, which is the ratio of consolidated current assets (including unused commitments under the Credit Agreement, but excluding non-cash assets) to consolidated current liabilities (excluding non-cash obligations, reclamation obligations to the extent classified as current liabilities and current maturities under the Credit Agreement), of not less than 1.0 to 1.0, and (2) a leverage ratio, which is the ratio of the sum of all of Rosehill Operating’s Total Funded Debt to EBITDAX (as such terms are defined in the Credit Agreement) for the four fiscal quarters then ended, of not greater than 4.00 to 1.00.

Related Party Policy

Prior to the closing of our initial public offering, we did not have a formal policy for the review, approval or ratification of related party transactions. Accordingly, certain of the transactions discussed above were not reviewed, approved or ratified in accordance with any such policy.

We have adopted a Financial Code of Ethics requiring us to avoid, wherever possible, all conflicts of interests, except under guidelines or resolutions approved by our board of directors (or the appropriate committee of our board) or as disclosed in our public filings with the SEC. Under our Financial Code of Ethics, conflict of interest situations include any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) involving the company. A copy of our code of ethics is available on our website.

In addition, our Audit Committee, pursuant to its charter, is responsible for reviewing and approving related party transactions to the extent that we enter into such transactions. An affirmative vote of a majority of the members of the Audit Committee present at a meeting at which a quorum is present is required in order to approve a related party transaction. A majority of the members of the entire Audit Committee will constitute a quorum. Without a meeting, the unanimous written consent of all of the members of the Audit Committee will be required to approve a related party transaction. A copy of the Audit Committee charter is available on our website. We also require each of our directors and executive officers to complete a directors’ and officers’ questionnaire that elicits information about related party transactions.

These procedures are intended to determine whether any such related party transaction impairs the independence of a director or presents a conflict of interest on the part of a director, employee or officer.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information known to the Company regarding ownership of shares of common stock of the Company as of April 28, 2017:

 

•

each person who is the beneficial owner of more than 5% of the outstanding shares of the Company’s voting common stock;

 

•

each of the Company’s current officers and executive directors; and

 

•

all current officers and executive directors of the Company, as a group.

Beneficial ownership is determined according to the rules of the SEC, which generally provide that a person has beneficial ownership of a security if he, she or it possesses sole or shared voting or investment power over that security, including options and warrants that are currently exercisable or exercisable within 60 days.

The percentages in the table below are based on 5,856,579 shares Class A Common Stock and 29,807,692 shares of Class B Common Stock issued and outstanding as of April 28, 2017. In calculating the percentages for a particular holder, we treated as outstanding the number of shares of Class A Common Stock issuable upon exercise of that particular holder’s warrants or conversion of that particular holder’s Series A Preferred Stock and did not assume exercise of any other holder’s warrants or conversion of any other holder’s Series A Preferred Stock.

Unless otherwise indicated, we believe that all persons named in the table below have sole voting and investment power with respect to all shares of voting common stock beneficially owned by them.

 

		Class A Stock								Class B Stock								% of Total Voting Power
Name and Address of Beneficial Owners (1)		Number of Shares				%				Number of Shares				%
KLR Energy Sponsor, LLC (2)			10,076,366				76.6	%			—				—				23.5	%
Gary C. Hanna (3)			—				—				—				—				—
Edward Kovalik (2)			10,076,366				76.6	%			—				—				23.5	%
T.J. Thom			140,000				2.4	%			—				—				*
Frank Rosenberg			—				—				—				—				—
William Mayer			—				—				—				—				—
Harry Quarls			—				—				—				—				—
Francis Contino			—				—				—				—				—
J.A. (Alan) Townsend			—				—				—				—				—
Brian K. Ayers			—				—				—				—				—
R. Colby Williford			—				—				—				—				—
Rosemore, Inc. (4)			36,105,518				86.0	%			29,807,692				100	%			86.0	%
K2 Principal Fund, L.P. (5)			2,567,064				30.5	%			—				—				6.7	%
Anchorage (6)			8,441,287				59.0	%			—				—				19.1	%
Geode Diversified Fund (7)			2,107,704				26.5	%			—				—				5.6	%
All directors and executive officers as a group (10 individuals)			10,253,578				76.8	%			—				—				23.7	%

 

*	Less than one percent.

(1)	Unless otherwise noted, the business address of each of the entities or individuals set forth in the table is c/o Rosehill Resources Inc., 16200 Park Row, Suite 300, Houston, Texas 77084.

(2)

Includes 7,113,150 shares of Class A Common Stock issuable upon exercise of outstanding warrants and 191,304 shares of Class A Common Stock issuable upon conversion of shares of Series A Preferred Stock. KLR Group Investments, LLC is the managing member of our Sponsor. Mr. Kovalik is the managing member of KLR Group Holdings, LLC, which owns 100% of KLR Group Investments, LLC, which is the managing member of our Sponsor. Our Sponsor has entered into a Shareholders’ and Registration Rights

 

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Agreement, dated as of December 20, 2016 (“the SHRRA”) with Tema and other holders. Pursuant to the SHRRA, our Sponsor and Tema have agreed to, among other things, vote their shares of common stock to elect members of the Board of Directors of the Company as set forth therein. Because of the relationship between our Sponsor and Tema as a result of the SHRRA, our Sponsor may be deemed, pursuant to Rule 13d-3 under the Act, to beneficially own the shares of common stock held by Tema. Our Sponsor disclaims beneficial ownership of the shares of common stock held by Tema.

(3)	Mr. Hanna does not beneficially own any shares of our common stock. However, Mr. Hanna has a pecuniary interest in shares of our common stock through his ownership of membership interests of our Sponsor.

(4)

Rosemore, Inc.’s address is 1 North Charles Street, 22nd Floor, Baltimore, MD 21201. Includes: (i) 29,807,692 shares of Class B common stock convertible into Class A common stock on a one-to-one basis held by Tema, (ii) 4,000,000 warrants to purchase Class A common stock held by Tema, (iii) 750,000 warrants to purchase Class A common stock held by Rosemore, Inc. and (iv) 17,800 shares of Series A Preferred Stock held by Rosemore Holdings, Inc., a wholly owned subsidiary of Rosemore, Inc. that are convertible into 1,547,826 shares of Class A common stock. Shares held by Tema and Rosemore Holdings, Inc. may be deemed beneficially owned by Rosemore, Inc., their sole parent. Tema’s address is 1 North Charles Street, 22nd Floor, Baltimore, MD 21201, and Rosemore Holdings, Inc.’s address is 7 St. Paul Street, Suite 820, Baltimore, MD 21202. Tema has entered into the SHRRA with our Sponsor and other holders. Pursuant to the SHRRA, our Sponsor and Tema have agreed to, among other things, vote their shares of common stock to elect members of the Board of Directors of the Company as set forth therein. Because of the relationship between our Sponsor and Tema as a result of the SHRRA, Tema may be deemed, pursuant to Rule 13d 3 under the Act, to beneficially own the shares of common stock held by our Sponsor. Tema disclaims beneficial ownership of the shares of common stock held by our Sponsor.

(5)

Includes 1,165,848 shares of Class A common stock issuable upon exercise of outstanding warrants and 869,565 shares of Class A common stock issuable upon conversion of shares of Series A Preferred Stock. K2 Principal Fund, L.P.’s address is 2 Bloor St West, Suite 801, Toronto, Ontario, M4W 3E2. The reported securities are owned directly by the K2 Principal Fund, L.P. (the “Fund”), and indirectly by: K2 GenPar L.P., the general partner of the Fund (the “GP”), K2 GenPar 2009 Inc., the general partner of the GP (“GenPar 2009”), Shawn Kimel Investments Inc., which owns 100% of the equity interests in GenPar 2009 (“SKI”), and Shawn Kimel, the sole owner of SKI. SKI owns 66.5% of the equity interests of K2 & Associates Investment Management Inc. (“K2 & Associates”). K2 & Associates is the investment manager of the Fund. Shawn Kimel, through his ownership of SKI and his being president of each of SKI, the GP, GenPar2009 and K2 & Associates, controls the voting and dispositive power for all of its shares of our common stock.

(6)

Includes a total of 3,245,678 shares of Class A common stock issuable upon exercise of outstanding warrants, including 1,570,759 shares issuable to Anchorage Illiquid Opportunities V, L.P. and 1,674,919 shares issuable to AIO V AIV 3 Holdings, L.P., and a total of 4,782,607 shares of Class A common stock issuable upon conversion of shares of Series A Preferred Stock, including 2,314,521 shares issuable to Anchorage Illiquid Opportunities V, L.P. and 2,468,086 shares issuable to AIO V AIV 3 Holdings, L.P. Anchorage Capital Group, L.L.C. (“ACG”), an SEC-registered investment advisor, is the investment manager of each of Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P. ACG’s address is 610 Broadway, 6th Floor, New York, NY 10112. Anchorage Advisors Management, L.L.C. (“AAM”) is the sole managing member of ACG. Mr. Kevin Ulrich is the Chief Executive Officer of ACG and the senior managing member of AAM. ACG, AAM and Mr. Ulrich have indirect voting or investment power with respect to each of Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P., but each of those entities or natural persons disclaims beneficial ownership in the registrable securities owned by each of Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P.

(7)

Includes 1,238,139 shares of Class A common stock issuable upon exercise of outstanding warrants and 869,565 shares of Class A common stock issuable upon conversion of shares of Series A Preferred Stock. Geode is a segregated account of Geode Capital Master Fund Ltd and is in the care of Geode Capital Management LP (“GCM LP”). GCM LP’s address is One Post Office Square, 20th Floor, Boston, MA 02109. GCM LP has the sole voting or investment power with respect to Geode.

 

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SELLING SECURITYHOLDERS

The selling securityholders may offer and sell, from time to time, any or all of the 114,441 shares of Series A Preferred Stock being offered by this prospectus, including 37,241 shares of Series A Preferred Stock potentially issuable over the next five years as dividends. The term “selling securityholders” includes the securityholders listed in the table below and their permitted transferees. We may amend or supplement this prospectus from time to time in the future to update or change the selling securityholders list and the securities that may be resold.

The Securities are being registered by the registration statement of which this prospectus forms a part pursuant to the following agreements:

 

•

the Business Combination Agreement,

 

•

the SHRRA,

 

•

the Subscription Agreement, dated as of December 20, 2016, by and between the Company and AIO V AIV 3 Holdings, L.P., the Subscription Agreement, dated as of December 20, 2016, by and between the Company and Anchorage Illiquid Opportunities V, L.P., the Subscription Agreement, dated as of December 20, 2016, by and between the Company and Geode Diversified Fund, a segregated account of Geode Capital Master Fund Ltd., and the Subscription Agreement, dated as of December 20, 2016, by and between the Company and The K2 Principal Fund, L.P. (collectively, the “Subscription Agreements”), and

 

•

the Side Letter, dated as of December 20, 2016, by and between the Company, our Sponsor and Rosemore, Inc.(the “Side Letter”).

The table below presents information regarding the selling securityholders and the Securities that the selling securityholders may offer and sell from time to time under this prospectus.

The following table sets forth:

 

•

the name of the selling securityholders;

 

•

the number of shares of Series A Preferred Stock beneficially owned by the selling securityholders prior to the sale of the Series A Preferred Stock covered by this prospectus;

 

•

the number of shares of Series A Preferred Stock beneficially owned by the selling securityholders following the sale of the Series A Preferred Stock covered by this prospectus; and

 

•

the percentage of Series A Preferred Stock owned by the selling securityholders prior to the sale of the Series A Preferred Stock covered by this prospectus.

Beneficial ownership is determined according to the rules of the SEC, which generally provide that a person has beneficial ownership of a security if he, she or it possesses sole or shared voting or investment power over that security, including options and warrants that are currently exercisable or exercisable within 60 days.

All information with respect to the selling securityholders’ ownership of the Securities has been furnished by or on behalf of the selling securityholders and is as of May 3, 2017. We believe, based on information supplied by the selling securityholders, that except as may otherwise be indicated in the footnotes to the table below, the selling securityholders have sole voting and dispositive power with respect to the Class A Common Stock reported as beneficially owned by them. Because the selling securityholders identified in the table may sell some or all of the Securities owned by them which are included in this prospectus, no estimate can be given as to the number of Securities available for resale hereby that will be held by the selling securityholders upon termination of this offering. In addition, the selling securityholders may have sold, transferred or otherwise disposed of, or may sell, transfer or otherwise dispose of, at any time and from time to time, the Securities they hold in transactions exempt

 

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from the registration requirements of the Securities Act after the date on which the selling securityholders provided the information set forth on the table below. We have, therefore, assumed for the purposes of the following table, that the selling securityholders will sell all of the Securities beneficially owned by them that are covered by this prospectus, but will not sell any other Securities that they may presently own. The percent of beneficial ownership for the selling securityholders is based on 95,000 shares of our shares of Series A Preferred Stock outstanding as of April 28, 2017.

 

Name of Selling Securityholders		Series A Preferred Stock Beneficially Owned Prior to Offering				Series A Preferred Stock to be Sold Pursuant to this Offering(5)				Series A Preferred Stock Beneficially Owned After Offering				Percentage of Shares of Series A Preferred Stock Beneficially Owned After Offering
KLR Energy Sponsor, LLC (1)			2,200				3,262				0				0	%
Anchorage Capital Group, LLC (2)			55,000				81,531				0				0	%
Geode Capital Management LP (3)			10,000				14,824				0				0	%
The K2 Principal Fund, L.P. (4)			10,000				14,824				0				0	%

 

(1)	KLR Group Investments, LLC is the managing member of our Sponsor. Edward Kovalik is the managing member of KLR Group Holdings, LLC, which owns 100% of KLR Group Investments, LLC, which is the managing member of KLR Energy Sponsor, LLC.

(2)

Includes 26,617 shares Series A Preferred Stock held by Anchorage Illiquid Opportunities V, L.P. and 28,383 shares of Series A Preferred Stock held by AIO V AIV 3 Holdings, L.P. Anchorage Capital Group, L.L.C., an SEC-registered investment advisor, is the investment manager of each of Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P. ACG’s address is 610 Broadway, 6th Floor, New York, NY 10112. Anchorage Advisors Management, L.L.C. is the sole managing member of ACG. Mr. Kevin Ulrich is the Chief Executive Officer of ACG and the senior managing member of AAM. ACG, AAM and Mr. Ulrich have indirect voting or investment power with respect to each of Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P., but each of those entities or natural persons disclaims beneficial ownership in the registrable securities owned by each of Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P.

(3)	Geode is a segregated account of Geode Capital Master Fund Ltd and is in the care of Geode Capital Management LP. GCM LP’s address is One Post Office Square, 20th Floor, Boston, MA 02109. GCM LP has the sole voting or investment power with respect to Geode.

(4)

K2 Principal Fund, L.P.’s address is 2 Bloor St West, Suite 801, Toronto, Ontario, M4W 3E2. The reported securities are owned directly by the K2 Principal Fund, L.P., and indirectly by: K2 GenPar L.P., the general partner of the Fund, K2 GenPar 2009 Inc., the general partner of the GP, Shawn Kimel Investments Inc., which owns 100% of the equity interests in GenPar 2009, and Shawn Kimel, the sole owner of SKI. SKI owns 66.5% of the equity interests of K2 & Associates Investment Management Inc. K2 & Associates is the investment manager of the Fund. Shawn Kimel, through his ownership of SKI and his being president of each of SKI, the GP, GenPar2009 and K2 & Associates, controls the voting and dispositive power for all of its shares of our common stock.

(5)	Includes additional shares of Series A Preferred Stock that may be issued over the next five years as dividends.

The selling securityholders may from time to time offer and sell pursuant to this prospectus any or all of the Securities owned by them but make no representation that any of the Securities will be offered for sale.

 

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PLAN OF DISTRIBUTION

We are registering the resale of the Securities by the selling securityholders named herein. The selling securityholders, which as used herein includes their permitted transferees, may, from time to time, sell, transfer or otherwise dispose of any or all of their Securities on any stock exchange, market or trading facility on which such Securities are traded or in private transactions. These dispositions may be at fixed prices, at prevailing market prices at the time of sale, at prices related to the prevailing market price, at varying prices determined at the time of sale or at negotiated prices.

The selling securityholders may use any one or more of the following methods when disposing of Securities:

 

•

ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

 

•

block trades in which the broker-dealer will attempt to sell the Securities as agent, but may position and resell a portion of the block as principal to facilitate the transaction;

 

•

purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

 

•

an exchange distribution in accordance with the rules of the applicable exchange;

 

•

privately negotiated transactions;

 

•

in underwriting transactions;

 

•

short sales;

 

•

through the writing or settlement of options or other hedging transactions, whether through an options exchange or otherwise;

 

•

broker-dealers may agree with the selling securityholders to sell a specified number of such Securities at a stipulated price;

 

•

distribution to employees, members, limited partners or stockholders of selling securityholders;

 

•

a combination of any such methods of sale;

 

•

“at the market” or through market makers or into an existing market for the shares; and

 

•

any other method permitted pursuant to applicable law.

The selling securityholders may, from time to time, pledge or grant a security interest in some or all of the Securities owned by them and, if they default in the performance of their secured obligations, the pledgees or secured parties may offer and sell their Securities, from time to time, under this prospectus, or under an amendment to this prospectus under Rule 424(b)(3) or other applicable provision of the Securities Act amending the list of selling securityholders to include the pledgee, transferee or other successors in interest as selling securityholders under this prospectus. The selling securityholders also may transfer their Securities in other circumstances, in which case the transferees, pledgees or other successors in interest will be the selling beneficial owners for purposes of this prospectus.

In connection with the sale of the Securities or interests therein, the selling securityholders may enter into hedging transactions with broker-dealers or other financial institutions, which may in turn engage in short sales of the Securities in the course of hedging the positions they assume. The selling securityholders may also sell their Securities short and deliver these Securities to close out their short positions, or loan or pledge such Securities to broker-dealers that in turn may sell these Securities. The selling securityholders may also enter into option or other transactions with broker-dealers or other financial institutions or the creation of one or more derivative securities which require the delivery to such broker-dealer or other financial institution of the Securities offered by this prospectus, which Securities such broker-dealer or other financial institution may resell pursuant to this prospectus (as supplemented or amended to reflect such transaction).

 

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The selling securityholders also may resell all or a portion of the shares in open market transactions in reliance upon Rule 144 under the Securities Act, provided that they meet the criteria and conform to the requirements of that rule.

The aggregate proceeds to the selling securityholders from the sale of the Securities offered by them will be the purchase price of the Securities less discounts or commissions, if any. Each of the selling securityholders reserves the right to accept and, together with their agents from time to time, to reject, in whole or in part, any proposed purchase of their Securities to be made directly or through agents. We will not receive any of the proceeds from the resale of the Securities being offered by the selling securityholders named herein.

In connection with an underwritten offering, underwriters or agents may receive compensation in the form of discounts, concessions or commissions from the selling securityholders or from purchasers of the offered Securities for whom they may act as agents. In addition, underwriters may sell the Securities to or through dealers, and those dealers may receive compensation in the form of discounts, concessions or commissions from the underwriters and/or commissions from the purchasers for whom they may act as agents. The selling securityholders and any underwriters, dealers or agents participating in a distribution of the Securities may be deemed to be “underwriters” within the meaning of the Securities Act, and any profit on the sale of the Securities by the selling securityholders and any commissions received by broker-dealers may be deemed to be underwriting commissions under the Securities Act.

To the extent required, the Securities to be sold, the names of the selling securityholders, the respective purchase prices and public offering prices, the names of any agent, dealer or underwriter, and any applicable commissions or discounts with respect to a particular offer will be set forth in an accompanying prospectus supplement or, if appropriate, a post-effective amendment to the registration statement that includes this prospectus.

Blue Sky Restrictions on Resale

In order to comply with the securities laws of some states, if applicable, the Securities may be sold in these jurisdictions only through registered or licensed brokers or dealers. In addition, in some states the Securities may not be sold unless they have been registered or qualified for sale or an exemption from registration or qualification requirements is available and is complied with.

If a selling securityholders wants to sell its Securities under this prospectus in the United States, the selling securityholders will also need to comply with state securities laws, also known as “Blue Sky laws,” with regard to secondary sales. All states offer a variety of exemption from registration for secondary sales. Many states, for example, have an exemption for secondary trading of securities registered under Section 12(g) of the Exchange Act or for securities of issuers that publish continuous disclosure of financial and non-financial information in a recognized securities manual, such as Standard & Poor’s. The broker for a selling securityholders will be able to advise a selling securityholders in which states the Securities are exempt from registration for secondary sales.

Any person who purchases the Securities from a selling securityholders offered by this prospectus who then wants to sell such Securities will also have to comply with Blue Sky laws regarding secondary sales.

When the registration statement that includes this prospectus becomes effective, and a selling securityholder indicates in which state(s) he desires to sell its Securities, we will be able to identify whether it will need to register or will rely on an exemption therefrom.

We have advised the selling securityholders that the anti-manipulation rules of Regulation M under the Exchange Act may apply to sales of securities in the market and to the activities of the selling securityholders and their affiliates. In addition, we will make copies of this prospectus (as it may be supplemented or amended from time to time) available to the selling securityholders for the purpose of satisfying the prospectus delivery

 

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requirements of the Securities Act. The selling securityholders may indemnify any broker-dealer that participates in transactions involving the sale of their Securities against certain liabilities, including liabilities arising under the Securities Act.

We have agreed to indemnify, to the extent permitted by law, the selling securityholders (and each selling securityholder’s officers and directors and each person who controls such selling securityholder) against liabilities caused by any untrue or alleged untrue statement of material fact contained in this prospectus or the registration statement of which this prospectus forms a part (including any amendment or supplement thereof) or any omission or alleged omission of a material fact required to be stated therein or necessary to make the statements therein not misleading, except insofar as the same are caused by or contained in any information furnished in writing to us by such selling securityholder expressly for use herein.

We are required to pay all fees and expenses incident to the registration of the Securities covered by this prospectus, including with regard to compliance with state securities or Blue Sky laws. Otherwise, all discounts, commissions, transfer taxes or fees incurred in connection with the sale of the Securities offered hereby will be paid by the selling securityholders.

 

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DESCRIPTION OF SECURITIES

The following description of the Securities, together with the additional information we include in any applicable prospectus supplements, summarizes the material terms and provisions of the Securities that we may offer under this prospectus. It may not contain all the information that is important to you. For the complete terms of the Securities, please refer to our amended and restated certificate of incorporation, and our bylaws, which are incorporated by reference into the registration statement which includes this prospectus. The Delaware General Corporation Law may also affect the terms of these securities.

We have authorized 95,000,000 shares of Class A Common Stock, $0.0001 par value per share, 30,000,000 shares of Class B Common Stock, $0.0001 par value per share and 1,000,000 shares of preferred stock, par value $0.0001 per share. As of the closing date of the Business Combination, there were: (a) 10 holders of record of Class A Common Stock and 5,856,579 shares of Class A Common Stock outstanding; (b) 1 holder of record of Class B Common Stock and 29,807,692 shares of Class B Common Stock outstanding; (c) 6 holders of record of Series A Preferred Stock and 95,000 shares of Series A Preferred Stock outstanding and (d) 9 holders of the Company’s Warrants and 25,594,158 Warrants outstanding. The number of shares of Class A Common Stock and Warrants outstanding include 208,453 outstanding units, each consisting of one share of Class A Common Stock and one Warrant.

Common Stock

Holders of our Class A Common Stock are entitled to one vote for each share held on all matters to be voted on by our stockholders. Holders of the Class A Common Stock, holders of the Class B Common Stock and holders of the Class F Common Stock, voting together as a single class, have the exclusive right to vote for the election of directors and on all other matters properly submitted to a vote of the stockholders. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50% of the shares voted for the election of directors can elect all of the directors. Subject to the rights, if any, of the holders of any outstanding series of the preferred stock, the holders of shares of our common stock (other than holders of shares of Class B Common Stock) are entitled to receive such dividends and other distributions (payable in cash, property or capital stock of the Company) when, as and if declared thereon by the board of directors from time to time out of any assets or funds of the Company and will share equally on a per share basis in such dividends and distributions.

Subject to the rights, if any, of the holders of any outstanding series of the Preferred Stock, in the event of any voluntary or involuntary liquidation, dissolution or winding up of the Corporation, after payment or provision for payment of the debts and other liabilities of the Corporation, the holders of shares of Common Stock (other than holders of shares of Class B Common Stock) shall be entitled to receive all the remaining assets of the Corporation available for distribution to its stockholders, ratably in proportion to the number of shares of Common Stock (other than shares of Class B Common Stock) held by them.

In the event of any voluntary or involuntary liquidation, dissolution or winding up of the Company, after payment or provision for payment of the debts and other liabilities of the Company, and subject to the rights, if any, of any outstanding series of the preferred stock, the holders of shares of our common stock are entitled to receive all the remaining assets of the Company available for distribution to its stockholders, ratably in proportion to the number of shares of common stock (other than shares of Class B Common Stock) held by them. Our stockholders have no preemptive or other subscription rights and there are no sinking fund or redemption provisions applicable to our common stock.

Class B Common Stock

In connection with the Business Combination, the Company issued 29,807,692 shares of Class B common stock with a par value of $0.0001 per share. Shares of Class B common stock may be issued only to Tema, their

 

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respective successors and assigns, as well as any permitted transferees of Tema. A holder of Class B common stock may transfer shares of Class B common stock to any transferee (other than the Company) only if, and only to the extent permitted by the First Amended and Restated Limited Liability Company Agreement of Rosehill Operating (the “A&R LLC Agreement”), such holder also simultaneously transfers an equal number of such holder’s Rosehill Operating Common Units to such transferee in compliance with the A&R LLC Agreement. Holders of our Class B common stock will vote together as a single class with holders of our Class A common stock on all matters properly submitted to a vote of the stockholders. In addition, the holders of Class B common stock, voting as a separate class, will be entitled to approve any amendment, alteration or repeal of any provision of our proposed certificate that would alter or change the powers, preferences or relative, participating, optional or other or special rights of the Class B common stock. Holders of Class B common stock will not be entitled to any dividends from the Company and will not be entitled to receive any of our assets in the event of any voluntary or involuntary liquidation, dissolution or winding up of our affairs.

Tema generally has the right to cause Rosehill Operating to redeem all or a portion of its Rosehill Operating Common Units in exchange for shares of our Class A common stock or, at Rosehill Operating’s option, an equivalent amount of cash; provided that we may, at our option, effect a direct exchange of cash or Class A common stock for such Rosehill Operating Common Units in lieu of such a redemption. Upon the future redemption or exchange of Rosehill Operating Common Units held by Tema, a corresponding number of shares of Class B common stock will be cancelled. Our certificate requires us to maintain a one-to-one ratio between the number of outstanding shares of our Class B common stock and the number of Rosehill Operating Common Units owned by Tema. This construct is intended to result in Tema having a voting interest in the Company that is identical to Tema’s percentage economic interest in Rosehill Operating.

Preferred Stock

Our amended and restated certificate of incorporation provides that shares of preferred stock may be issued from time to time in one or more series. Our board of directors is authorized to fix the voting rights, if any, designations, powers, preferences, the relative, participating, optional or other special rights and any qualifications, limitations and restrictions thereof, applicable to the shares of each series. Our board of directors is able to, without stockholder approval, issue preferred stock with voting and other rights that could adversely affect the voting power and other rights of the holders of the common stock and could have anti-takeover effects. The ability of our board of directors to issue preferred stock without stockholder approval could have the effect of delaying, deferring or preventing a change of control of us or the removal of existing management.

8.0% Series A Cumulative Perpetual Preferred Stock

At the closing of the Business Combination, we issued 75,000 shares of Series A Preferred Stock pursuant to the PIPE Investment and 20,000 shares of Series A Preferred Stock pursuant to the Side Letter. Pursuant to that certain Certificate of Designation of Series A Preferred Stock (the “Certificate of Designation”) filed with the Secretary of State of the State of Delaware on April 27, 2017, holders of Series A Preferred Stock are entitled to receive, when, as and if declared by our board of directors, cumulative dividends, payable in cash, Series A Preferred Stock, or a combination thereof, in each case, at the sole discretion of the Company, at an annual rate of 8% on the $1,000 liquidation preference per share of the Series A Preferred Stock, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on July 15, 2017.

Each share of Series A Preferred Stock has a liquidation preference of $1,000 per share and is convertible, at the holder’s option at any time, initially into 86.9565 shares of our Class A common stock (which is equivalent to an initial conversion price of approximately $11.50 per share of Class A common stock), subject to specified adjustments and limitations as set forth in the Certificate of Designations. Under certain circumstances, we will increase the conversion rate upon a “fundamental change” as described in the Certificate of Designations. Based on the initial conversion rate, 8,260,867 shares of the Company’s Class A common stock would be issuable upon conversion of all of the Series A Preferred Stock.

 

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At any time on or after the second anniversary of the closing date of the Business Combination, we may, at our option, give notice of our election to cause all outstanding shares of Series A Preferred Stock to be automatically converted into shares of our Class A common stock at the conversion rate, if the closing sale price of our Class A common stock equals or exceeds 120% of the conversion price for at least 20 trading days in a period of 30 consecutive trading days, as described in the Certificate of Designations. However, in any 30-day period, we may not convert a number of shares of Series A Preferred Stock in excess of the number of shares of Series A Preferred Stock which would convert into 15% of the number of shares of Class A common stock traded on NASDAQ in the preceding calendar month.

Except as required by law or the Charter, which includes the Certificate of Designations, the holders of Series A Preferred Stock have no voting rights (other than with respect to certain matters regarding the Series A Preferred Stock or when dividends payable on the Series A Preferred Stock have not been paid for an aggregate of six or more quarterly dividend periods, whether or not consecutive, as provided in the Certificate of Designations).

Upon our voluntary or involuntary liquidation, winding-up or dissolution, each holder of Series A Preferred Stock will be entitled to receive a liquidation preference in the amount of $1,000 per share of Series A Preferred Stock, plus an amount equal to accrued and unpaid dividends on the shares to but excluding the date fixed for liquidation, winding-up or dissolution, to be paid out of our assets legally available for distribution to our stockholders, after satisfaction of liabilities to our creditors and distributions to holders of shares of senior stock and before any payment or distribution is made to holders of junior stock (including our Class A common stock).

Warrants

Each of our warrants entitles the registered holder to purchase one share of our Class A common stock at a price of $11.50 per share, subject to adjustment as discussed below, at any time commencing 30 days after the completion of the Business Combination. The warrants will expire five years after the completion of our initial business combination, at 5:00 p.m., New York City time, or earlier upon redemption or liquidation.

No warrant will be exercisable for cash or on a cashless basis, and we will not be obligated to issue any shares to holders seeking to exercise their warrants, unless the issuance of the shares upon such exercise is registered or qualified under the securities laws of the state of the exercising holder, unless an exemption is available. In the event that the conditions in the immediately preceding sentence is not satisfied with respect to a warrant, the holder of such warrant will not be entitled to exercise such warrant and such warrant may have no value and expire worthless, in which case, the purchaser of a unit containing such warrant will have paid the full purchase price for the unit solely for the share of Class A common stock underlying such unit.

We have agreed that as soon as practicable, but in no event later than 30 days after the closing of the Business Combination, we will use our best efforts to file with the SEC a registration statement for the registration, under the Securities Act, of the shares of Class A common stock issuable upon exercise of the warrants. We will use our best efforts to cause the same to become effective no later than 90 days after the closing of our initial business combination and to maintain the effectiveness of such registration statement, and a current prospectus relating thereto, until the expiration of the warrants in accordance with the provisions of the warrant agreement. Notwithstanding the foregoing, if a registration statement covering the shares of Class A common stock issuable upon exercise of the public warrants is not effective within 90 days following the consummation of our initial business combination, public warrant holders may, until such time as there is an effective registration statement and during any period when we shall have failed to maintain an effective registration statement, exercise warrants on a cashless basis pursuant to an available exemption from registration under the Securities Act. In such event, each holder would pay the exercise price by surrendering the warrants for that number of shares of Class A common stock equal to the quotient obtained by dividing (x) the product of the number of shares of Class A common stock underlying the warrants, multiplied by the difference between the exercise price of the warrants and the “fair market value” (defined below) by (y) the fair market value. The “fair

 

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market value” shall mean the average reported last sale price of the shares of Class A common stock for the 10 trading days ending on the day prior to the date of exercise. If an exemption from registration is not available, holders will not be able to exercise their warrants on a cashless basis.

Once the warrants become exercisable, the Company may call the warrants for redemption:

 

•

in whole and not in part;

 

•

at a price of $0.01 per warrant;

 

•

upon not less than 30 days’ prior written notice of redemption (the “30-day redemption period”) to each warrant holder; and

 

•

if, and only if, the reported last sale price of the Class A common stock equals or exceeds $21.00 per share for any 20 trading days within a 30-trading day period ending on the third trading day prior to the date we send to the notice of redemption to the warrant holders; provided there is an effective registration statement with respect to the shares of Class A common stock underlying such warrants and a current prospectus relating to those shares of Class A common stock is available throughout the 30-day redemption period.

We have established the last of the redemption criterion discussed above to prevent a redemption call unless there is at the time of the call a significant premium to the warrant exercise price. If the foregoing conditions are satisfied and we issue a notice of redemption of the warrants, each warrant holder will be entitled to exercise his, her or its warrant prior to the scheduled redemption date. However, the price of the Class A common stock may fall below the $21.00 redemption trigger price as well as the $11.50 warrant exercise price after the redemption notice is issued.

If we call the warrants for redemption as described above, our management will have the option to require any holder that wishes to exercise his, her or its warrant to do so on a “cashless basis.” In determining whether to require all holders to exercise their warrants on a “cashless basis,” our management will consider, among other factors, our cash position, the number of warrants that are outstanding and the dilutive effect on our stockholders of issuing the maximum number of shares of Class A common stock issuable upon the exercise of our warrants. If our management takes advantage of this option, all holders of warrants would pay the exercise price by surrendering their warrants for that number of shares of Class A common stock equal to the quotient obtained by dividing (x) the product of the number of shares of Class A common stock underlying the warrants, multiplied by the difference between the exercise price of the warrants and the “fair market value” (defined below) by (y) the fair market value. The “fair market value” shall mean the average reported last sale price of the Class A common stock for the 10 trading days ending on the third trading day prior to the date on which the notice of redemption is sent to the holders of warrants. If our management takes advantage of this option, the notice of redemption will contain the information necessary to calculate the number of shares of Class A common stock to be received upon exercise of the warrants, including the “fair market value” in such case. Requiring a cashless exercise in this manner will reduce the number of shares to be issued and thereby lessen the dilutive effect of a warrant redemption. If we call our warrants for redemption and our management does not take advantage of this option, our Sponsor and its permitted transferees would still be entitled to exercise their private placement warrants for cash or on a cashless basis using the same formula described above that other warrant holders would have been required to use had all warrant holders been required to exercise their warrants on a cashless basis, as described in more detail below.

A holder of a warrant may notify us in writing in the event it elects to be subject to a requirement that such holder will not have the right to exercise such warrant, to the extent that after giving effect to such exercise, such person (together with such person’s affiliates), to the warrant agent’s actual knowledge, would beneficially own in excess of 9.8% (or such other amount as a holder may specify) of the shares of Class A common stock outstanding immediately after giving effect to such exercise.

 

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If the number of outstanding shares of Class A common stock is increased by a stock dividend payable in shares of Class A common stock, or by a split-up of shares of Class A common stock or other similar event, then, on the effective date of such stock dividend, split-up or similar event, the number of shares of Class A common stock issuable on exercise of each warrant will be increased in proportion to such increase in the outstanding shares of Class A common stock. A rights offering to holders of Class A common stock entitling holders to purchase shares of Class A common stock at a price less than the fair market value will be deemed a stock dividend of a number of shares of Class A common stock equal to the product of (i) the number of shares of Class A common stock actually sold in such rights offering (or issuable under any other equity securities sold in such rights offering that are convertible into or exercisable for Class A common stock) multiplied by (ii) one (1) minus the quotient of (x) the price per share of Class A common stock paid in such rights offering divided by (y) the fair market value. For these purposes (i) if the rights offering is for securities convertible into or exercisable for Class A common stock, in determining the price payable for Class A common stock, there will be taken into account any consideration received for such rights, as well as any additional amount payable upon exercise or conversion and (ii) fair market value means the volume weighted average price of Class A common stock as reported during the ten (10) trading day period ending on the trading day prior to the first date on which the shares of Class A common stock trade on the applicable exchange or in the applicable market, regular way, without the right to receive such rights.

In addition, if we, at any time while the warrants are outstanding and unexpired, pay a dividend or make a distribution in cash, securities or other assets to the holders of Class A common stock on account of such shares of Class A common stock (or other shares of our capital stock into which the warrants are convertible), other than (a) as described above, (b) certain ordinary cash dividends, (c) to satisfy the redemption rights of the holders of Class A common stock in connection with the Business Combination or any initial business combination, (d) as a result of the repurchase of shares of Class A common stock by the company if the Business Combination or any initial business combination is presented to the stockholders of the company for approval, or (e) in connection with the redemption of our public shares upon our failure to complete the Business Combination or any initial business combination, then the warrant exercise price will be decreased, effective immediately after the effective date of such event, by the amount of cash and/or the fair market value of any securities or other assets paid on each share of Class A common stock in respect of such event.

If the number of outstanding shares of our Class A common stock is decreased by a consolidation, combination, reverse stock split or reclassification of shares of Class A common stock or other similar event, then, on the effective date of such consolidation, combination, reverse stock split, reclassification or similar event, the number of shares of Class A common stock issuable on exercise of each warrant will be decreased in proportion to such decrease in outstanding shares of Class A common stock.

Whenever the number of shares of Class A common stock purchasable upon the exercise of the warrants is adjusted, as described above, the warrant exercise price will be adjusted by multiplying the warrant exercise price immediately prior to such adjustment by a fraction (x) the numerator of which will be the number of shares of Class A common stock purchasable upon the exercise of the warrants immediately prior to such adjustment, and (y) the denominator of which will be the number of shares of Class A common stock so purchasable immediately thereafter.

In case of any reclassification or reorganization of the outstanding shares of Class A common stock (other than those described above or that solely affects the par value of such shares of Class A common stock), or in the case of any merger or consolidation of us with or into another corporation (other than a consolidation or merger in which we are the continuing corporation and that does not result in any reclassification or reorganization of our outstanding shares of Class A common stock), or in the case of any sale or conveyance to another corporation or entity of the assets or other property of us as an entirety or substantially as an entirety in connection with which we are dissolved, the holders of the warrants will thereafter have the right to purchase and receive, upon the basis and upon the terms and conditions specified in the warrants and in lieu of the shares of our Class A common stock immediately theretofore purchasable and receivable upon the exercise of the rights represented

 

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thereby, the kind and amount of shares of stock or other securities or property (including cash) receivable upon such reclassification, reorganization, merger or consolidation, or upon a dissolution following any such sale or transfer, that the holder of the warrants would have received if such holder had exercised their warrants immediately prior to such event. However, if such holders were entitled to exercise a right of election as to the kind or amount of securities, cash or other assets receivable upon such consolidation or merger, then the kind and amount of securities, cash or other assets for which each warrant will become exercisable will be deemed to be the weighted average of the kind and amount received per share by such holders in such consolidation or merger that affirmatively make such election, and if a tender, exchange or redemption offer has been made to and accepted by such holders (other than a tender, exchange or redemption offer made by the company in connection with redemption rights held by stockholders of the Company as provided for in the Company’s Charter or as a result of the repurchase of shares of Class A common stock by the company if a proposed initial business combination is presented to the stockholders of the company for approval) under circumstances in which, upon completion of such tender or exchange offer, the maker thereof, together with members of any group (within the meaning of Rule 13d-5(b)(1) under the Exchange Act) of which such maker is a part, and together with any affiliate or associate of such maker (within the meaning of Rule 12b-2 under the Exchange Act) and any members of any such group of which any such affiliate or associate is a part, own beneficially (within the meaning of Rule 13d-3 under the Exchange Act) more than 50% of the outstanding shares of Class A common stock, the holder of a warrant will be entitled to receive the highest amount of cash, securities or other property to which such holder would actually have been entitled as a stockholder if such warrant holder had exercised the warrant prior to the expiration of such tender or exchange offer, accepted such offer and all of the Class A common stock held by such holder had been purchased pursuant to such tender or exchange offer, subject to adjustments (from and after the consummation of such tender or exchange offer) as nearly equivalent as possible to the adjustments provided for in the warrant agreement. Additionally, if less than 70% of the consideration receivable by the holders of Class A common stock in such a transaction is payable in the form of Class A common stock in the successor entity that is listed for trading on a national securities exchange or is quoted in an established over-the-counter market, or is to be so listed for trading or quoted immediately following such event, and if the registered holder of the warrant properly exercises the warrant within thirty days following public disclosure of such transaction, the warrant exercise price will be reduced as specified in the warrant agreement based on the per share consideration minus Black-Scholes Warrant Value (as defined in the warrant agreement) of the warrant.

The warrants may be exercised upon surrender of the warrant certificate on or prior to the expiration date at the offices of the warrant agent, with the exercise form on the reverse side of the warrant certificate completed and executed as indicated, accompanied by full payment of the exercise price (or on a cashless basis, if applicable), by certified or official bank check payable to us, for the number of warrants being exercised. The warrant holders do not have the rights or privileges of holders of Class A common stock and any voting rights until they exercise their warrants and receive shares of Class A common stock. After the issuance of shares of Class A common stock upon exercise of the warrants, each holder will be entitled to one vote for each share held of record on all matters to be voted on by stockholders.

Warrants may be exercised only for a whole number of shares of Class A common stock. No fractional shares will be issued upon exercise of the warrants. If, upon exercise of the warrants, a holder would be entitled to receive a fractional interest in a share, we will, upon exercise, round down to the nearest whole number the number of shares of Class A common stock to be issued to the warrant holder.

The public warrants were issued in registered form under a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and us. The warrant agreement provides that the terms of the warrants may be amended without the consent of any holder to cure any ambiguity or correct any defective provision, but requires the approval by the holders of at least 65% of the then outstanding public warrants to make any change that adversely affects the interests of the registered holders of public warrants.

 

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Private Placement Warrants

The private placement warrants (including the Class A common stock issuable upon exercise of the private placement warrants) will not be transferable, assignable or salable until 30 days after the completion of the Business Combination and they will not be redeemable by us and will be exercisable on a cashless basis so long as they are held by the initial holders or their permitted transferees. Our Sponsor agreed to additional transfer restrictions relating to its common stock in connection with its entry into the SHRRA. Otherwise, the private placement warrants have terms and provisions that are identical to those of the warrants being sold as part of the units in our IPO. If the private placement warrants are held by holders other than the initial holders or their permitted transferees, the private placement warrants will be redeemable by us and exercisable by the holders on the same basis as the warrants included in the units being sold in our IPO.

If holders of the private placement warrants elect to exercise them on a cashless basis, they will pay the exercise price by surrendering his, her or its warrants for that number of shares of Class A common stock equal to the quotient obtained by dividing (x) the product of the number of shares of Class A common stock underlying the warrants, multiplied by the difference between the exercise price of the warrants and the “fair market value” (defined below) by (y) the fair market value. The “fair market value” shall mean the average reported last sale price of the Class A common stock for the 10 trading days ending on the third trading day prior to the date on which the notice of warrant exercise is sent to the warrant agent. The reason that we agreed that these warrants will be exercisable on a cashless basis so long as they are held by our Sponsor and permitted transferees is because it was not known at the time whether they will be affiliated with us following a business combination. If they remain affiliated with us, their ability to sell our securities in the open market will be significantly limited. We have policies in place that prohibit insiders from selling our securities except during specific periods of time. Even during such periods of time when insiders will be permitted to sell our securities, an insider cannot trade in our securities if he or she is in possession of material non-public information. Accordingly, unlike public stockholders who could exercise their warrants and sell the shares of Class A common stock received upon such exercise freely in the open market in order to recoup the cost of such exercise, the insiders could be significantly restricted from selling such securities.

Warrants Issued in Connection with Business Combination

In connection with the closing of the Business Combination, we issued 5,000,000 Warrants to PIPE Investors and 4,000,000 Warrants to Tema. These Warrants were issued on the same terms, and are subject to the same rights and obligations, as our registered Warrants.

Our Transfer Agent and Warrant Agent

The transfer agent for our common stock and warrant agent for our Warrants is Continental Stock Transfer & Trust Company. We have agreed to indemnify Continental Stock Transfer & Trust Company in its roles as transfer agent and warrant agent, its agents and each of its stockholders, directors, officers and employees against all liabilities, including judgments, costs and reasonable counsel fees that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence, willful misconduct or bad faith of the indemnified person or entity.

Certain Anti-Takeover Provisions of Delaware Law, our Amended and Restated Certificate of Incorporation, and our Bylaws

We are currently subject to the provisions of Section 203 of the DGCL, which we refer to as “Section 203”, regulating corporate takeovers.

Section 203 prevents certain Delaware corporations, under certain circumstances, from engaging in a “business combination” with:

 

•

a stockholder who owns 15% or more of our outstanding voting stock (otherwise known as an “interested stockholder”);

 

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•

an affiliate of an interested stockholder; or

 

•

an associate of an interested stockholder, for three years following the date that the stockholder became an interested stockholder.

 

•

A “business combination” includes a merger or sale of more than 10% of our assets. However, the above provisions of Section 203 do not apply if:

 

•

our board of directors approves the transaction that made the stockholder an “interested stockholder”, prior to the date of the transaction;

 

•

after the completion of the transaction that resulted in the stockholder becoming an interested stockholder, that stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, other than statutorily excluded shares of common stock; or

 

•

on or subsequent to the date of the transaction, the business combination is approved by our board of directors and authorized at a meeting of our stockholders, and not by written consent, by an affirmative vote of at least two-thirds of the outstanding voting stock not owned by the interested stockholder.

Our amended and restated certificate of incorporation provides that our board of directors is classified into three classes of directors. As a result, in most circumstances, a person can gain control of our board only by successfully engaging in a proxy contest at three or more annual meetings.

Further, our amended and restated certificate of incorporation only allows stockholders to call a special meeting until the first date on which Tema and our Sponsor and their successors and affiliates cease collectively to beneficially own (directly or indirectly) more than 30% of the outstanding shares of our common stock (the “Trigger Date”).

The amended and restated certificate of incorporation provides that after the Trigger Date directors may be removed prior to the expiration of their terms by stockholders only for cause or upon the affirmative vote of 75% of the voting power of all outstanding shares of the combined company.

The amended and restated certificate of incorporation requires that changes or amendments to the certificate of incorporation or the bylaws must be approved (i) before the Trigger Date, by a majority of the voting power of our outstanding common stock, which such majority includes at least 80% of the shares held by our Sponsor, and (ii) thereafter, certain changes or amendments must be approved by at least 75% of the voting power of our outstanding common stock.

In addition, our amended and restated certificate of incorporation does not provide for cumulative voting in the election of directors; our board of directors is empowered to elect a director to fill a vacancy created by the expansion of the board of directors or the resignation, death, or removal of a director in certain circumstances; and our advance notice procedures require that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders’ meeting.

Our authorized but unissued common stock and preferred stock are available for future issuances without stockholder approval and could be utilized for a variety of corporate purposes, including future offerings to raise additional capital, acquisitions and employee benefit plans. The existence of authorized but unissued and unreserved common stock and preferred stock could render more difficult or discourage an attempt to obtain control of us by means of a proxy contest, tender offer, merger or otherwise.

Rule 144

Pursuant to Rule 144 of the Securities Act, which we refer to as “Rule 144”, a person who has beneficially owned restricted shares of our common stock or warrants for at least six months would be entitled to sell their

 

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securities provided that (i) such person is not deemed to have been one of our affiliates at the time of, or at any time during the three months preceding, a sale and (ii) we are subject to the Exchange Act periodic reporting requirements for at least three months before the sale and have filed all required reports under Section 13 or 15(d) of the Exchange Act during the 12 months (or such shorter period as we were required to file reports) preceding the sale.

Persons who have beneficially owned restricted shares of our common stock or warrants for at least six months but who are our affiliates at the time of, or at any time during the three months preceding, a sale, would be subject to additional restrictions, by which such person would be entitled to sell within any three-month period only a number of securities that does not exceed the greater of:

 

•

1% of the total number of shares of common stock then outstanding; or

 

•

the average weekly reported trading volume of the common stock during the four calendar weeks preceding the filing of a notice on Form 144 with respect to the sale.

Sales by our affiliates under Rule 144 are also limited by manner of sale provisions and notice requirements and to the availability of current public information about us.

Restrictions on the Use of Rule 144 by Shell Companies or Former Shell Companies

Rule 144 is not available for the resale of securities initially issued by shell companies (other than business combination related shell companies) or issuers that have been at any time previously a shell company. However, Rule 144 also includes an important exception to this prohibition if the following conditions are met:

 

•

the issuer of the securities that was formerly a shell company has ceased to be a shell company;

 

•

the issuer of the securities is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act;

 

•

the issuer of the securities has filed all Exchange Act reports and material required to be filed, as applicable, during the preceding 12 months (or such shorter period that the issuer was required to file such reports and materials), other than Form 8-K reports; and

 

•

at least one year has elapsed from the time that the issuer filed current Form 10 type information with the SEC reflecting its status as an entity that is not a shell company.

As a result, if we have filed all Exchange Act reports and materials as set forth in the third bullet of the preceding paragraph, then any holder of the above noted restricted securities will be able to sell such securities, as applicable, pursuant to Rule 144 without registration one year following the closing of the Business Combination.

Listing of Securities

Our Class A Common Stock and the Public Warrants trade separately on The NASDAQ Capital Market under the symbols “ROSE” and “ROSEW,” respectively. Through April 27, 2017, our Class A Common Stock and Warrants were listed on The NASDAQ Capital Market under the symbols “KLRE” and “KLREW,” respectively. There has been no established market for our Series A Preferred Stock and a public market may not develop, or if any market does develop, it may not be sustained. We do not intend to apply to list the Series A Preferred Stock on any securities exchange or automated dealer quotation system.

 

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CERTAIN ERISA CONSIDERATIONS

The following is a summary of certain considerations associated with the acquisition and holding of the Securities by employee benefit plans that are subject to Title I of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), plans, individual retirement accounts and other arrangements that are subject to Section 4975 of the Internal Revenue Code of 1986, as amended (the “Code”) or employee benefit plans that are governmental plans (as defined in Section 3(32) of ERISA), certain church plans (as defined in Section 3(33) of ERISA), non-U.S. plans (as described in Section 4(b)(4) of ERISA) or other plans that are not subject to the foregoing but may be subject to provisions under any other federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of ERISA or the Code (collectively, “Similar Laws”), and entities whose underlying assets are considered to include “plan assets” of any such plan, account or arrangement (each, a “Plan”).

This summary is based on the provisions of ERISA and the Code (and related regulations and administrative and judicial interpretations) as of the date of this prospectus. This summary does not purport to be complete, and no assurance can be given that future legislation, court decisions, regulations, rulings or pronouncements will not significantly modify the requirements summarized below. Any of these changes may be retroactive and may thereby apply to transactions entered into prior to the date of their enactment or release. This discussion is general in nature and is not intended to be all inclusive, nor should it be construed as investment or legal advice.

General Fiduciary Matters

ERISA and the Code impose certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or Section 4975 of the Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of an ERISA Plan or the management or disposition of the assets of an ERISA Plan, or who renders investment advice for a fee or other compensation to an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

In considering an investment in the Securities with a portion of the assets of any Plan, a fiduciary should consider the Plan’s particular circumstances and all of the facts and circumstances of the investment and determine whether the acquisition and holding of the Securities is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code, or any Similar Law relating to the fiduciary’s duties to the Plan, including, without limitation:

 

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

 

•

whether, in making the investment, the ERISA Plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

 

•

whether the investment is permitted under the terms of the applicable documents governing the Plan;

 

•

whether the acquisition or holding of the Securities will constitute a “prohibited transaction” under Section 406 of ERISA or Section 4975 of the Code (please see discussion under “—Prohibited Transaction Issues” below); and

 

•

whether the Plan will be considered to hold, as plan assets, (i) only the Securities or (ii) an undivided interest in our underlying assets (please see the discussion under “—Plan Asset Issues” below).

Prohibited Transaction Issues

Section 406 of ERISA and Section 4975 of the Code prohibit ERISA Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of ERISA, or “disqualified persons,” within the meaning of Section 4975 of the Code, unless an exemption is

 

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available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA Plan that engages in such a non-exempt prohibited transaction may be subject to excise taxes, penalties and liabilities under ERISA and the Code. The acquisition and/or holding of the Securities by an ERISA Plan with respect to which the issuer, the initial purchaser, or a guarantor is considered a party in interest or a disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption.

Because of the foregoing, the Securities should not be acquired or held by any person investing “plan assets” of any Plan, unless such acquisition and holding will not constitute a non-exempt prohibited transaction under ERISA and the Code or a similar violation of any applicable Similar Laws.

Plan Asset Issues

Additionally, a fiduciary of a Plan should consider whether the Plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that we would become a fiduciary of the Plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code and any other applicable Similar Laws.

The Department of Labor (the “DOL”) regulations provide guidance with respect to whether the assets of an entity in which ERISA Plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets generally would not be considered to be “plan assets” if, among other things:

(a) the equity interests acquired by ERISA Plans are publicly offered securities i.e., the equity interests are part of a class of securities that is widely held by 100 or more investors independent of the issuer and each other, are “freely transferable” (as defined in the DOL regulations), and are either registered under certain provisions of the federal securities laws or sold to the ERISA Plan as part of a public offering under certain conditions;

(b) the entity is an “operating company” i.e., it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

(c) there is no significant investment by benefit plan investors, which is defined to mean that immediately after the most recent acquisition by an ERISA Plan of any equity interest in the entity, less than 25% of the total value of each class of equity interest (disregarding certain interests held by persons (other than benefit plan investors) with discretionary authority or control over the assets of the entity or who provide investment advice for a fee (direct or indirect) with respect to such assets, and any affiliates thereof) is held by ERISA Plans, IRAs and certain other Plans (but not including governmental plans, foreign plans and certain church plans), and entities whose underlying assets are deemed to include plan assets by reason of a Plan’s investment in the entity.

Due to the complexity of these rules and the excise taxes, penalties and liabilities that may be imposed upon persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries, or other persons considering acquiring and/or holding the Securities on behalf of, or with the assets of, any Plan, consult with their counsel regarding the potential applicability of ERISA, Section 4975 of the Code and any Similar Laws to such investment and whether an exemption would be applicable to the acquisition and holding of the Securities. Purchasers of the Securities have the exclusive responsibility for ensuring that their acquisition and holding of the Securities complies with the fiduciary responsibility rules of ERISA and does not violate the prohibited transaction rules of ERISA, the Code or applicable Similar Laws. The sale of the Securities to a Plan is in no respect a representation by us or any of our affiliates or representatives that such an investment meets all relevant legal requirements with respect to investments by any such Plan or that such investment is appropriate for any such Plan.

 

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of the material U.S. federal income tax considerations relevant to the purchase, ownership, conversion and disposition of our Series A Preferred Stock purchased pursuant to this prospectus and to the ownership and disposition of any Class A Common Stock received in respect thereof. This summary is based upon the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations promulgated thereunder (“Treasury Regulations”), administrative rulings and judicial decisions, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought any ruling from the Internal Revenue Service (“IRS”) with respect to the statements made and the conclusions reached in the following summary, and there can be no assurance that the IRS or a court will agree with such statements and conclusions.

This summary is limited to holders that will hold our Series A Preferred Stock and Class A Common Stock received in respect thereof as “capital assets” (generally, property held for investment). This summary does not address the Medicare tax on net investment income, U.S. federal estate or gift tax laws, any state, local or non-U.S. tax laws or any tax treaties. This summary also does not address all tax considerations that may be important to a particular investor in light of the investor’s circumstances, or to certain categories of investors that may be subject to special treatment under the U.S. federal income tax laws, such as:

 

•

banks, insurance companies or other financial institutions;

 

•

tax-exempt or governmental organizations;

 

•

qualified foreign pension funds (or any entities all of the interests which are held by a qualified foreign pension fund);

 

•

dealers in securities or foreign currencies;

 

•

traders in securities that use the mark-to-market method of accounting for U.S. federal income tax purposes;

 

•

persons subject to the alternative minimum tax;

 

•

U.S. persons whose functional currency is not the U.S. dollar;

 

•

partnerships or other pass-through entities for U.S. federal income tax purposes and holders of interests therein;

 

•

persons deemed to sell our Series A Preferred Stock or Class A Common Stock received in respect thereof under the constructive sale provisions of the Code;

 

•

persons that acquired our Series A Preferred Stock through the exercise of employee stock options or otherwise as compensation or through a tax-qualified retirement plan;

 

•

certain former U.S. citizens or long-term residents of the United States; and

 

•

persons that hold our Series A Preferred Stock or Class A Common Stock received in respect thereof as part of a straddle, appreciated financial position, synthetic security, hedge, conversion transaction, wash sale or other integrated investment or risk reduction transaction.

If a partnership (including an entity or arrangement treated as a partnership for U.S. federal income tax purposes) holds our Series A Preferred Stock or Class A Common Stock received in respect thereof, the tax treatment of a partner of the partnership generally will depend upon the status of the partner, the activities of the partnership and upon certain determinations made at the partner level. Accordingly, we urge partners in partnerships (including entities or arrangements treated as partnerships for U.S. federal income tax purposes) considering the purchase of our Series A Preferred Stock to consult their tax advisors regarding the U.S. federal income tax considerations of the purchase, ownership, conversion and disposition of our Series A Preferred Stock purchased pursuant to this prospectus and of the ownership and disposition of any Class A Common Stock received in respect thereof.

 

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PROSPECTIVE INVESTORS ARE ENCOURAGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE APPLICATION OF THE U.S. FEDERAL INCOME TAX LAWS TO THEIR PARTICULAR SITUATION.

Tax Consequences to U.S. Holders

The discussion in this section is addressed to holders of our Series A Preferred Stock and Class A Common Stock received in respect thereof that are U.S. holders. A “U.S. holder” is a beneficial owner of Series A Preferred Stock or Class A Common Stock received in respect thereof that is, for U.S. federal income tax purposes:

 

•

an individual who is a citizen or resident of the United States;

 

•

a corporation (or other entity taxable as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

 

•

an estate the income of which is subject to U.S. federal income tax regardless of its source; or

 

•

a trust (i) the administration of which is subject to the primary supervision of a U.S. court and which has one or more United States persons who have the authority to control all substantial decisions of the trust or (ii) which has made a valid election under applicable Treasury Regulations to be treated as a United States person.

Distributions on Series A Preferred Stock and Class A Common Stock

Distributions of cash or other property with respect to our Series A Preferred Stock or our Class A Common Stock generally will be characterized as dividend income when paid, to the extent of our current or accumulated earnings and profits, as determined for U.S. federal income tax purposes. To the extent that the amount of a distribution with respect to our Series A Preferred Stock or Class A Common Stock exceeds our current and accumulated earnings and profits, such distribution will be treated first as a tax-free return of capital to the extent of a U.S. holder’s adjusted tax basis in such Series A Preferred Stock or Class A Common Stock, as the case may be, which reduces such basis dollar-for-dollar, and thereafter as capital gain. Such gain will be long-term capital gain provided that the U.S. holder’s holding period for such Series A Preferred Stock or Class A Common Stock, as the case may be, is more than one year as of the time of the distribution. For a discussion of a U.S. holder’s tax basis and holding period in respect of Series A Preferred Stock received in respect of our Series A Preferred Stock, see below under “—Tax Consequences to U.S. Holders—Series A Preferred Stock Distributions on Series A Preferred Stock” and “—Tax Consequences to U.S. Holders—Conversion of Series A Preferred Stock.”

Distributions treated as dividends that are received by non-corporate holders of our Series A Preferred Stock or Class A Common Stock generally will be subject to a reduced U.S. federal income tax rate if such holders meet certain holding period and other applicable requirements. If a dividend received by a non-corporate holder that qualifies for the rate reduction is an “extraordinary dividend” within the meaning of Section 1059 of the Code, any loss recognized by such non-corporate holder on a subsequent disposition of the stock will be treated as long-term capital loss to the extent of such “extraordinary dividend,” irrespective of such holder’s holding period for the stock.

Subject to certain limitations (including holding period requirements), distributions on our Series A Preferred Stock and our Class A Common Stock constituting dividends paid out of earnings and profits to U.S. holders that are corporations generally will qualify for the dividends received deduction. Any distribution (or the portion of any distribution) that exceeds our current and accumulated earnings and profits will not be eligible for the dividends received deduction. If a corporate U.S. holder receives a dividend that is an “extraordinary dividend” within the meaning of Section 1059 of the Code, the holder, in certain instances, must reduce its tax basis (but not below zero) in its stock by the amount of the “nontaxed portion” of such “extraordinary dividend” that results from the application of the dividends received deduction. If the “nontaxed portion” of such “extraordinary dividend” exceeds such corporate holder’s tax basis in the stock, any excess will be taxed as gain as if such holder had disposed of its shares in the year the “extraordinary dividend” is paid.

 

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Series A Preferred Stock Distributions on Series A Preferred Stock

If we pay a distribution on our Series A Preferred Stock in the form of our Series A Preferred Stock, such distribution will be taxable for U.S. federal income tax purposes in the same manner as distributions described above under “—Tax Consequences to U.S. Holders—Distributions on Series A Preferred Stock and Common Stock.” The amount of such distribution will equal the fair market value of the Series A Preferred Stock on the distribution date. A U.S. holder’s tax basis in such distributed Series A Preferred Stock will equal the fair market value of such Series A Preferred Stock on the distribution date, and the holding period for such Series A Preferred Stock will begin on the day following the distribution date.

Adjustment of Conversion Rate

The conversion rate at which our Series A Preferred Stock is converted to shares of Class A Common Stock is subject to adjustments in certain circumstances. Section 305 of the Code and Treasury Regulations promulgated thereunder would treat a U.S. holder of our Series A Preferred Stock as having received a constructive distribution includable in such U.S. holder’s income in the manner described under “—Tax Consequences to U.S. Holders—Distributions on Series A Preferred Stock and Class A Common Stock,” above, if and to the extent that certain adjustments (or failures to make adjustments) in the conversion rate increase the proportionate interest of the U.S. holder in our assets or earnings and profits. For example, a change in the conversion rate to reflect a taxable dividend to holders of our Class A Common Stock will generally give rise to a deemed taxable dividend to the holders of our Series A Preferred Stock to the extent of an allocable portion of our current or accumulated earnings and profits. Thus, under certain circumstances, a U.S. holder may recognize income in the event of a constructive distribution even though such holder may not receive any cash or property. Adjustments to the conversion rate made pursuant to a bona fide reasonable adjustment formula which has the effect of preventing the dilution of the interest of the holders of our Series A Preferred Stock (other than an adjustment in respect of a taxable dividend on the Class A Common Stock), however, will generally not be considered a constructive distribution.

On April 12, 2016, the IRS proposed Treasury Regulations addressing the amount and timing of such deemed distributions and certain obligations of withholding agents and filing and notice obligations of issuers with respect to such deemed distributions. If adopted as proposed, the regulations would generally provide that (i) the amount of a deemed distribution is the excess of the fair market value of the option element of the Series A Preferred Stock immediately after the conversion rate adjustment over the fair market value of the option element without the conversion rate adjustment, (ii) the deemed distribution occurs at the earlier of the date the conversion rate adjustment occurs under the terms of the Series A Preferred Stock and the date of the actual distribution of cash or property that results in the deemed distribution and (iii) we may be required to report the amount of any deemed distributions on our website or to the IRS and all U.S. holders of our Series A Preferred Stock (including holders that would otherwise be exempt from reporting). The final regulations will be effective for deemed distributions occurring on or after the date of adoption, but U.S. holders of Series A Preferred Stock may rely on them prior to that date under certain circumstances. U.S. holders are urged to consult their tax advisors regarding the potential effects of the proposed regulations on an investment in our Series A Preferred Stock.

Conversion of Series A Preferred Stock

U.S. holders generally will not recognize (i.e., take into account for U.S. federal income tax purposes) income, gain or loss upon the conversion of our Series A Preferred Stock into shares of our Class A Common Stock, except that any cash or Class A Common Stock treated as received in respect of dividends in arrears generally will be treated as a taxable distribution, as described above in “—Tax Consequences to U.S. Holders—Distributions on Series A Preferred Stock and Class A Common Stock.” A U.S. holder’s basis and holding period in the Class A Common Stock received upon conversion (other than Class A Common Stock treated as received in payment of dividends in arrears) generally will be the same as such holder’s basis and holding period in the

 

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converted Series A Preferred Stock. Any Class A Common Stock treated as received in payment of dividends in arrears and taxed as a dividend upon receipt will have a basis equal to its fair market value on the date of conversion, and a new holding period which will begin on the day after the conversion.

The treatment of any cash or Class A Common Stock treated as received in respect of any other accumulated but unpaid dividends (i.e., including those attributable to any portion of the dividend period containing the date of conversion) is uncertain, and such cash or Class A Common Stock may be treated as additional consideration or as a payment in respect of dividends in arrears (the treatment of which is discussed in the paragraph above). If we choose to pay such accumulated but unpaid dividends in cash and such cash is treated as additional consideration, such cash would be taxable to the extent of any gain realized by the U.S. holder. To the extent the amount of cash received in respect of such accumulated but unpaid dividends exceeds the gain realized by a U.S. holder the excess amount would not be taxable to such U.S. holder but would reduce its basis in our Class A Common Stock received.

In the event that a U.S. holder’s Series A Preferred Stock is converted pursuant to certain fundamental changes (see “Description of Securities—Preferred Stock—8.0% Series A Cumulative Perpetual Preferred Stock”), the tax treatment of such a conversion (including any additional “make-whole” shares received following such a fundamental change) will depend upon the facts underlying the particular transaction giving rise to such a conversion. U.S. holders are urged to consult their tax advisor to determine the specific tax treatment of a conversion under such circumstances.

Sale or Other Disposition of Series A Preferred Stock and Class A Common Stock

A U.S. holder generally will recognize capital gain or loss on a sale or other disposition of our Series A Preferred Stock (other than pursuant to a conversion into Class A Common Stock) or our Class A Common Stock equal to the difference between the amount realized upon the sale or other disposition (not including any proceeds attributable to any dividends in arrears, which generally will be taxable as described above under “—Tax Consequences to U.S. Holders—Distributions on Series A Preferred Stock and Class A Common Stock”) and such U.S. holder’s adjusted tax basis in the shares sold or exchanged. Such capital gain or loss generally will be long-term capital gain or loss if the U.S. holder’s holding period for the shares sold or exchanged is more than one year. Long-term capital gains of individuals generally are subject to a reduced rate of taxation. The deductibility of net capital losses is subject to limitations.

Information Reporting and Backup Withholding

The amount of dividends paid to a U.S. holder on shares of our Series A Preferred Stock and our Class A Common Stock and the proceeds received from the disposition of our Series A Preferred Stock or our Class A Common Stock generally must be reported annually to the IRS and to such U.S. holder. A U.S. holder may be subject to backup withholding on the payment of dividends with respect to our Series A Preferred Stock or our Class A Common Stock and on certain payments of proceeds on the sale or other disposition of our Series A Preferred Stock or Class A Common Stock unless it furnishes the applicable withholding agent with a taxpayer identification number, certified under penalties of perjury, and certain other information, or otherwise establishes in the manner prescribed by law, an exemption from backup withholding. Because dividends of Class A Common Stock will not give rise to any cash from which any applicable backup withholding could be satisfied, an applicable withholding agent may satisfy such liability through sales of a portion of the Class A Common Stock or from subsequent cash payments to a U.S. holder. Any amount withheld under the backup withholding rules from a payment to a U.S. holder is allowable as a credit against such holder’s U.S. federal income tax liability, and may entitle such holder to a refund, provided that the holder timely provides the required information to the IRS. U.S. holders are urged to consult their tax advisors regarding the application of backup withholding in their particular circumstances and the availability of, and procedure for, obtaining an exemption from backup withholding.

 

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Tax Consequences to Non-U.S. Holders

The discussion in this section is addressed to holders of our Series A Preferred Stock and Class A Common Stock received in respect thereof that are non-U.S. holders. Such a holder is a “non-U.S. holder” if it is a beneficial owner of Series A Preferred Stock or Class A Common Stock received in respect thereof that is not for U.S. federal income tax purposes a partnership or a U.S. holder.

Distributions and Constructive Distributions on Series A Preferred Stock and Common Stock

In general, distributions with respect to our Series A Preferred Stock or our Class A Common Stock (including distributions on our Series A Preferred Stock made in the form of Series A Preferred Stock) will generally be subject to U.S. withholding tax at a 30% rate, unless such rate is reduced by an applicable income tax treaty. To receive the benefit of a reduced treaty rate, a non-U.S. holder must provide the applicable withholding agent with an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) certifying qualification for the reduced rate. The amount of a distribution made in the form of our Series A Preferred Stock will equal the fair market value of the distributed Series A Preferred Stock on the distribution date. Any required withholding tax might be satisfied by the withholding agent through a sale of a portion of the shares received by the non-U.S. holder as a dividend or might be withheld from cash dividends or sales proceeds subsequently paid or credited to such non-U.S. holder.

Distributions treated as dividends paid to a non-U.S. holder that are effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, are treated as attributable to a permanent establishment maintained by the non-U.S. holder in the United States) generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code). Such effectively connected dividends will not be subject to U.S. withholding tax if the non-U.S. holder satisfies certain certification requirements by providing the applicable withholding agent with a properly executed IRS Form W-8ECI certifying eligibility for exemption. If the non-U.S. holder is a corporation for U.S. federal income tax purposes, it may also be subject to a branch profits tax (at a 30% rate or such lower rate as may be specified by an applicable income tax treaty) on its effectively connected earnings and profits (as adjusted for certain items), which will include effectively connected dividends.

In general, the rules applicable to distributions to non-U.S. holders discussed above are also applicable to deemed distributions to non-U.S. holders resulting from adjustments to or failure to adjust the conversion rate of the Series A Preferred Stock. See “—Tax Consequences to U.S. Holders—Adjustment of Conversion Rate.” Because deemed distributions would not give rise to any cash from which any applicable withholding tax could be satisfied, the applicable withholding agent may withhold the U.S. federal tax from subsequent cash payments to a non-U.S. holder on our Series A Preferred Stock or our Class A Common Stock, including cash proceeds from a sale of such holder’s on the holder’s behalf to satisfy the withholding obligation.

In addition, as described above, on April 12, 2016, the IRS proposed Treasury Regulations addressing the amount and timing of such deemed distributions and certain obligations of withholding agents and filing and notice obligations of issuers with respect to such deemed distributions. See “—Tax Consequences to U.S. Holders—Adjustment of Conversion Rate.” If adopted as proposed, the regulations would generally provide that, subject to certain limited exceptions, a withholding agent is required to impose any applicable withholding on deemed distributions to a non-U.S. holder and, if there is no associated cash payment, may satisfy such withholding obligations by withholding on other cash payments made to the same beneficial owner or by liquidating other property held in custody for the beneficial owner or over which it has control. If the proposed Treasury Regulations are adopted as final regulations, the final regulations will be effective for deemed distributions occurring on or after the date of such adoption, but holders of Series A Preferred Stock and withholding agents may rely on the proposed Treasury Regulations prior to that date under certain circumstances.

 

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Sale or Other Disposition of Series A Preferred Stock and Class A Common Stock

Subject to the discussions below under “—Tax Consequences to Non-U.S. Holders—Information Reporting and Backup Withholding” and “—Tax Consequences to Non-U.S. Holders—Additional Withholding Requirements under FATCA,” a non-U.S. holder generally will not be subject to U.S. federal income or withholding tax on any gain realized upon the sale or other disposition of our Series A Preferred Stock or our Class A Common Stock (other than, in certain cases, upon a conversion of Series A Preferred Stock, which is discussed below under “—Tax Consequences to Non-U.S. Holders—Conversion of Series A Preferred Stock”) unless:

 

•

the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met;

 

•

the gain is effectively connected with a trade or business conducted by the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States); or

 

•

our Series A Preferred Stock or Class A Common Stock constitutes a United States real property interest by reason of our status as a United States real property holding corporation (“USRPHC”) for U.S. federal income tax purposes.

A non-U.S. holder described in the first bullet point above will be subject to U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty) on the amount of such gain, which generally may be offset by U.S. source capital losses.

A non-U.S. holder whose gain is described in the second bullet point above or, subject to the exceptions described in the next paragraph, the third bullet point above, generally will be taxed on a net income basis at the rates and in the manner generally applicable to United States persons (as defined under the Code) unless an applicable income tax treaty provides otherwise. If the non-U.S. holder is a corporation for U.S. federal income tax purposes whose gain is described in the second bullet point above, then such gain would also be included in its effectively connected earnings and profits (as adjusted for certain items), which may be subject to a branch profits tax (at a 30% rate or such lower rate as specified by an applicable income tax treaty).

Generally, a corporation is a USRPHC if the fair market value of its U.S. real property interests equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. We believe that we currently are, and expect to remain for the foreseeable future, a USRPHC for U.S. federal income tax purposes. However, as long as our Class A Common Stock continues to be “regularly traded on an established securities market” (within the meaning of the Treasury Regulations):

 

•

with respect to the disposition of our Series A Preferred Stock, if (as expected) our Series A Preferred Stock is not “regularly traded on an established securities market” at the time of the disposition, a non-U.S. holder will be subject to U.S. tax on any gain from such disposition if, on any date such Series A Preferred Stock was acquired, all such Series A Preferred Stock actually or constructively owned by the non-U.S. holder had a fair market value greater than 5% of the fair market value of all of our outstanding Class A Common Stock as of such date; and

 

•

with respect to the disposition of our Class A Common Stock, a non-U.S. holder will be subject to U.S. tax on any gain from such disposition only if such non-U.S. holder actually or constructively owns, or owned at any time during the shorter of the five-year period ending on the date of the disposition or the non-U.S. holder’s holding period, more than 5% of our Class A Common Stock.

If our Class A Common Stock were not considered to be “regularly traded on an established securities market”, a non-U.S. holder (regardless of the percentage of stock owned) would be subject to U.S. federal income tax on a taxable disposition of our Series A Preferred Stock or Class A Common Stock, as the case may be (as described in the preceding paragraph), and a 15% withholding tax would apply to the gross proceeds from such disposition.

 

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Non-U.S. holders are strongly encouraged to consult their tax advisors with respect to the application of the foregoing rules to their ownership and disposition of our Series A Preferred Stock and Class A Common Stock.

Conversion of Series A Preferred Stock

Subject to the discussion in the next paragraph, non-U.S. holders generally will not recognize any gain or loss by reason of receiving Class A Common Stock upon conversion of the Series A Preferred Stock, except that any cash or Class A Common Stock treated as received in respect of dividends in arrears generally will be treated as a taxable distribution subject to withholding, as described above in “—Tax Consequences to Non-U.S. Holders—Distributions and Constructive Distributions on Series A Preferred Stock and Class A Common Stock.” In addition, the treatment of any cash or Class A Common Stock deemed received in respect of any other accumulated but unpaid dividends (i.e., including those attributable to any portion of the dividend period containing the date of conversion) is uncertain, and such cash or Class A Common Stock may be treated as additional consideration or as a payment in respect of dividends in arrears because of the uncertainty, we, or an applicable withholding agent, will withhold U.S. federal income tax at a rate of 30% (or such lower rate as specified by an applicable income tax treaty), as described above in “—Tax Consequences to Non-U.S. Holders—Distributions and Constructive Distributions on Series A Preferred Stock and Class A Common Stock.” Any required withholding tax might be satisfied by the withholding agent through a sale of a portion of the shares received by the non-U.S. holder or might be withheld from cash dividends or sales proceeds subsequently paid or credited to such non-U.S. holder.

Notwithstanding these general rules, if a non-U.S. holder is subject to tax under the special rules governing USRPHCs as described above under “—Tax Consequences to Non-U.S. Holders—Sale or Other Disposition of Series A Preferred Stock and Class A Common Stock” with respect to its Series A Preferred Stock but not the Class A Common Stock into which the Series A Preferred Stock is convertible, then the conversion of the Series A Preferred Stock into Class A Common Stock would be a taxable event and such non-U.S. holder would be subject to U.S. tax in the same manner as described in “—Tax Consequences to Non-U.S. Holders—Sale or Other Disposition of Series A Preferred Stock and Class A Common Stock.” This situation could arise, for example, if the Series A Preferred Stock were not “regularly traded” and if on any date the Series A Preferred Stock held by such non-U.S. holder was acquired such Series A Preferred Stock had a fair market value greater than 5% of the fair market value of all of our outstanding Class A Common Stock as of such date and such Series A Preferred Stock was convertible into 5% or less of our outstanding Class A Common Stock. If, as to a non-U.S. holder, both the Series A Preferred Stock and the Class A Common Stock into which the Series A Preferred Stock is convertible would be subject to U.S. federal income taxation under rules governing USRPHCs described above, then, although the conversion of the Series A Preferred Stock solely into the Class A Common Stock generally would not be taxable, the non-U.S. holder may be required to file a U.S. federal income tax return for the taxable year of the conversion and satisfy certain procedural requirements in accordance with the applicable Treasury Regulations.

Non-U.S. holders are strongly encouraged to consult their tax advisors with respect to the application of the foregoing rules to the conversion of their Series Preferred Stock into Class A Common Stock.

In the event that a non-U.S. holder’s Series A Preferred Stock is converted pursuant to certain fundamental changes (see “Description of Securities—Preferred Stock—8.0% Series A Cumulative Perpetual Preferred Stock”), the tax treatment of such a conversion (including any additional “make-whole” shares received following such a fundamental change) will depend upon the facts underlying the particular transaction giving rise to such a conversion. Non-U.S. holders are urged to consult their tax advisors to determine the specific tax treatment of a conversion under such circumstances.

 

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Information Reporting and Backup Withholding

Any dividends paid to a non-U.S. holder must be reported annually to the IRS and to the non-U.S. holder. Copies of these information returns may be made available to the tax authorities in the country in which the non-U.S. holder resides or is established. Payments of dividends to a non-U.S. holder generally will not be subject to backup withholding if the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form).

Payments of the proceeds from a sale or other disposition by a non-U.S. holder of our Series A Preferred Stock or Class A Common Stock effected by or through a U.S. office of a broker generally will be subject to information reporting and backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption by properly certifying its non-U.S. status on an IRS Form W-8BEN or IRS Form W-8BEN-E (or other applicable or successor form) and certain other conditions are met. Information reporting and backup withholding generally will not apply to any payment of the proceeds from a sale or other disposition of our Series A Preferred Stock or Class A Common Stock effected outside the United States by a non-U.S. office of a broker. However, unless such broker has documentary evidence in its records that the non-U.S. holder is not a United States person and certain other conditions are met, or the non-U.S. holder otherwise establishes an exemption, information reporting will apply to a payment of the proceeds of the disposition of our Series A Preferred Stock or Class A Common Stock effected outside the United States by such a broker if it has certain relationships within the United States.

Backup withholding is not an additional tax. Rather, the U.S. federal income tax liability (if any) of persons subject to backup withholding will be reduced by the amount of tax withheld. If backup withholding results in an overpayment of taxes, a refund may be obtained, provided that the required information is timely furnished to the IRS.

Additional Withholding Requirements under FATCA

Sections 1471 through 1474 of the Code, and the Treasury Regulations and administrative guidance issued thereunder (“FATCA”), impose a 30% withholding tax on any dividends paid (including constructive dividends) on our Series A Preferred Stock or Class A Common Stock and on the gross proceeds from a disposition of our Series A Preferred Stock or Class A Common Stock (if such disposition occurs after December 31, 2018), in each case if paid to a “foreign financial institution” or a “non-financial foreign entity” (each as defined in the Code) (including, in some cases, when such foreign financial institution or non-financial foreign entity is acting as an intermediary), unless (i) in the case of a foreign financial institution, such institution enters into an agreement with the U.S. government to withhold on certain payments, and to collect and provide to the U.S. tax authorities substantial information regarding U.S. account holders of such institution (which includes certain equity and debt holders of such institution, as well as certain account holders that are foreign entities with U.S. owners), (ii) in the case of a non-financial foreign entity, such entity certifies that it does not have any “substantial United States owners” (as defined in the Code) or provides the applicable withholding agent with a certification (generally on an IRS Form W-8BEN-E) identifying the direct and indirect substantial United States owners of the entity, or (iii) the foreign financial institution or non-financial foreign entity otherwise qualifies for an exemption from these rules and provides appropriate documentation (such as an IRS Form W-8BEN-E). Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing these rules may be subject to different rules. Under certain circumstances, a holder might be eligible for refunds or credits of such taxes. Non-U.S. holders are encouraged to consult their own tax advisors regarding the effects of FATCA on an investment in our stock.

INVESTORS CONSIDERING THE PURCHASE OF OUR SERIES A PREFERRED STOCK ARE URGED TO CONSULT THEIR OWN TAX ADVISORS REGARDING THE APPLICATION OF THE U.S. FEDERAL INCOME, ESTATE AND GIFT TAX LAWS TO THEIR PARTICULAR SITUATIONS AND THE APPLICABILITY AND EFFECT OF STATE, LOCAL OR FOREIGN TAX LAWS AND TREATIES.

 

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LEGAL MATTERS

The validity of the securities offered hereby will be passed upon for us by Vinson & Elkins LLP of Houston, Texas. Any underwriters or agents will be advised about other issues relating to the offering by counsel to be named in the applicable prospectus supplement.

EXPERTS

The audited carve-out financial statements of the assets and liabilities of the business to be contributed by Tema Oil and Gas Company to Rosehill Operating Company, LLC as of December 31, 2016 and 2015 and for the three years ended December 31, 2016, have been included herein in reliance on the report of BDO USA, LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

Estimates of our oil and natural gas reserves and related future net cash flows related to our properties as of December 31, 2016 included herein and elsewhere in the registration statement were based upon a reserve report prepared by our independent petroleum engineer, Ryder Scott Company, L.P. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the Securities offered by this prospectus. This prospectus does not contain all of the information included in the registration statement. For further information pertaining to us and the Securities you should refer to the registration statement and its exhibits. Statements contained in this prospectus concerning any of our contracts, agreements or other documents are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed. Each statement in this prospectus relating to a contract or document filed as an exhibit is qualified in all respects by the filed exhibit.

We are subject to the informational requirements of the Securities Exchange Act of 1934, as amended, and file annual, quarterly and current reports and other information with the SEC. Our filings with the SEC are available to the public on the SEC’s website at http://www.sec.gov. Those filings are also available to the public on, or accessible through, our website under the heading “Investors” at www.rosehillresources.com. The information we file with the SEC or contained on or accessible through our corporate website or any other website that we may maintain is not part of this prospectus or the registration statement of which this prospectus is a part. You may also read and copy, at SEC prescribed rates, any document we file with the SEC, including the registration statement (and its exhibits) of which this prospectus is a part, at the SEC’s Public Reference Room located at 100 F Street, N.E., Washington D.C. 20549. You can call the SEC at 1-800-SEC-0330 to obtain information on the operation of the Public Reference Room.

 

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INDEX TO FINANCIAL STATEMENTS

 

ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED BY TEMA OIL & GAS COMPANY TO ROSEHILL OPERATING COMPANY, LLC
Audited Financial Statements
Report of Independent Registered Public Accounting Firm			F-2
Balance Sheets as of December 31, 2016 and 2015			F-3
Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014			F-4
Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014			F-6
Notes to the Financial Statements			F-7

 

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Report of Independent Registered Public Accounting Firm

Board of Directors

Tema Oil and Gas Company

Houston, Texas

We have audited the accompanying carve-out balance sheets of the assets and liabilities of the business to be contributed by Tema Oil and Gas Company (“Tema”) to Rosehill Operating Company, LLC (the “Contributed Assets”) as of December 31, 2016 and 2015 and the related carve-out statements of operations, changes in parent net investment and cash flows for each of the three years in the period ended December 31, 2016. These carve-out financial statements are the responsibility of management of the Contributed Assets. Our responsibility is to express an opinion on these carve-out financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the carve-out financial statements are free of material misstatement. The Contributed Assets are not required to have, nor were we engaged to perform, an audit of its 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 internal control over financial reporting of the Contributed Assets. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the carve-out financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the carve-out financial statements referred to above present fairly, in all material respects, the financial position of the Contributed Assets at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1, the Contributed Assets are a group of related assets and liabilities owned by Tema, including oil and natural gas properties in the Delaware Basin and Barnett Shale and certain related assets and liabilities. The carve-out financial statements reflect the assets, liabilities, revenues and expenses directly attributable to the Contributed Assets, as well as allocations deemed reasonable by management, to present the financial position, results of operations, changes in parent net investment, and cash flows of the Contributed Assets on a stand-alone basis and do not necessarily reflect the financial position, results of operations, changes in parent net investment, and cash flows of the Contributed Assets in the future or what they would have been had the Contributed Assets been a separate, standalone entity during the periods presented.

/s/ BDO USA, LLP

Houston, TX

March 6, 2017

 

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ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

BALANCE SHEETS

 

		As of December 31,
		2016				2015
(In thousands)
ASSETS
Current Assets
Cash and cash equivalents		$	8,434			$	27,734
Accounts receivable			1,928				2,102
Accounts receivable, related party			4,837				1,274
Inventory			280				494
Derivative assets			247				1,533
Prepaid and other current assets			617				559
Total current assets			16,343				33,696
Property and Equipment
Oil and natural gas properties (successful efforts method of accounting), net			122,267				121,621
Other property and equipment, net			1,106				1,252
Total property and equipment, net			123,373				122,873
Other assets, net			110				334
Total Assets		$	139,826			$	156,903
LIABILITIES AND PARENT NET INVESTMENT
Current Liabilities
Accounts payable		$	4,658			$	5,084
Accounts payable, related parties			612				528
Accrued liabilities and other			7,205				3,403
Derivative liabilities			1,856				120
Current portion, capital lease obligation			30				30
Current portion, long term debt			—				20,000
Total current liabilities			14,361				29,165
Noncurrent Liabilities
Long term debt, net of current portion			55,000				45,000
Capital lease obligation, net of current portion			65				94
Asset retirement obligations			5,180				3,667
Total liabilities			74,606				77,926
Commitments and contingencies (Note 13)
Parent Net Investment			65,220				78,977
Total Liabilities and Parent Net Investment		$	139,826			$	156,903

The accompanying notes are an integral part of these financial statements.

 

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ROSEHILL OPERATING COMPANY, LLC

STATEMENTS OF OPERATIONS

 

		For the Years Ended December 31,
		2016				2015				2014
(In thousands)
Revenues
Oil sales		$	24,807			$	20,601			$	28,444
Natural gas sales			5,304				4,909				7,445
Natural gas liquids sales			4,534				3,977				7,674
Gain (loss) on commodity derivatives, net			(4,169	)			3,735				2,404
Total revenues			30,476				33,222				45,967
Operating expenses
Lease operating expenses			4,800				4,582				6,103
Production taxes			1,541				1,311				1,861
Gathering and transportation			2,398				2,094				2,462
Depreciation, depletion and amortization			24,789				23,244				15,842
Accretion expense			176				120				125
Impairment of oil and natural gas properties			—				8,131				27,595
Exploration costs			794				960				960
General and administrative expenses			9,000				4,234				5,151
Gain on sale of oil and natural gas properties			—				—				(6	)
(Gain) loss on sale of other assets			(50	)			18				(26	)
Total operating expenses			43,448				44,694				60,067
Operating loss			(12,972	)			(11,472	)			(14,100	)
Other income (expense)
Interest expense, net			(1,822	)			(3,247	)			(5,469	)
Other income (expense), net			(247	)			7				316
Total other expense			(2,069	)			(3,240	)			(5,153	)
Loss before income taxes			(15,041	)			(14,712	)			(19,253	)
Income tax expense			148				108				—
Net loss		$	(15,189	)		$	(14,820	)		$	(19,253	)

 

The accompanying notes are an integral part of these financial statements.

 

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STATEMENTS OF CHANGES IN PARENT NET INVESTMENT

 

		Parent Net Investment
(In thousands)
Balances at December 31, 2013			76,905
Net loss			(19,253	)
Net distribution to Parent			(1,474	)
Balances at December 31, 2014			56,178
Net loss			(14,820	)
Contribution from Parent in exchange for note payable			11,750
Net investment from Parent			25,869
Balances at December 31, 2015			78,977
Net loss			(15,189	)
Net investment from Parent			1,432
Balances at December 31, 2016		$	65,220

 

 

The accompanying notes are an integral part of these financial statements.

 

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ROSEHILL OPERATING COMPANY, LLC

STATEMENTS OF CASH FLOWS

 

		For the Years Ended December 31,
		2016				2015				2014
(In thousands)
Cash flows from operating activities
Net loss		$	(15,189	)		$	(14,820	)		$	(19,253	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Accretion expense			176				120				125
Depreciation, depletion, and amortization			24,789				23,244				15,842
Impairment of oil and natural gas properties			—				8,131				27,595
Gain on sale of oil and natural gas properties			—				—				(6	)
(Gain) loss on sale of other assets			(50	)			18				(26	)
(Gain) loss on derivative instruments			4,630				(1,893	)			2,074
Gain on investments			—				—				(128	)
Net cash received (paid) in settlement of derivative instruments			(1,608	)			3,305				(1,140	)
Amortization of debt issuance costs			113				98				66
Settlement of asset retirement obligations			(53	)			(10	)			(190	)
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable and net accounts receivable, related party			(3,305	)			597				(182	)
(Increase) decrease in inventory			214				(47	)			(275	)
(Increase) decrease in prepaid and other current assets			(58	)			743				(1,019	)
(Increase) decrease in other assets			111				(109	)			(84	)
Increase (decrease) in accounts payable and accrued liabilities and other			1,691				(1,133	)			2,126
Net cash provided by operating activities			11,461				18,244				25,525
Cash flows from investing activities
Additions to oil and natural gas properties			(22,004	)			(17,176	)			(76,726	)
Purchases of investments			—				—				(239	)
Proceeds from sale of investments			—				—				24,586
Purchases of other property and equipment			(263	)			(167	)			(1,057	)
Proceeds from sales of oil and natural gas properties and other property and equipment			103				350				44
Net cash used in investing activities			(22,164	)			(16,993	)			(53,392	)
Cash flows from financing activities
Proceeds from long term debt			10,000				—				15,000
Payments on long term debt			(20,000	)			(10,000	)			—
Net investment from (distribution to) Parent			1,432				25,869				(1,474	)
Proceeds from note payable, related party			—				1,750				10,000
Payments on capital lease obligation			(29	)			(28	)			(2	)
Debt issuance costs			—				(72	)			(67	)
Net cash provided by (used in) financing activities			(8,597	)			17,519				23,457
Net increase (decrease) in cash and cash equivalents			(19,300	)			18,770				(4,410	)
Cash and cash equivalents, beginning of year			27,734				8,964				13,374
Cash and cash equivalents, end of year		$	8,434			$	27,734			$	8,964
Supplemental disclosures of non cash activity:
Non-cash investing activities:
Asset retirement obligations incurred and revisions in estimated costs, net		$	1,641			$	515			$	226
Changes in accrued capital expenditures		$	(1,434	)		$	1,090			$	974
Non-cash financing activities:
Contribution from Parent in exchange for note payable		$	—			$	11,750			$	—
Capital lease obligations		$	—			$	—			$	94
Supplemental disclosures of cash flow information:
Cash paid for interest		$	1,794			$	2,371			$	2,039

The accompanying notes are an integral part of these financial statements.

 

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ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

Note 1—Nature of Operations

Tema Oil and Gas Company (“Tema” or “Parent”) has identified certain oil and natural gas assets and related liabilities that will be contributed to Rosehill Operating Company, LLC (“Rosehill Operating”). Rosehill Operating is expected to incorporate as a Delaware limited liability company immediately prior to the completion of a Business Combination (as defined in Note 4—“Business Combination” below) with KLR Energy Acquisition Corp. (“KLRE”), a publicly traded special purpose acquisition company (“SPAC”). Tema is a wholly-owned subsidiary of Rosemore, Inc. (“Rosemore”).

The accompanying financial statements reflect the assets and liabilities of the business to be contributed to Rosehill Operating by the Parent (“Contributed Assets”). The Contributed Assets include all of the Parent’s oil and natural gas properties located in the Delaware and Barnett Basins and certain other assets, including equipment, contracts, rights-of-way, and related liabilities.

All drilling completed on the Contributed Assets during the periods presented in the accompanying financial statements occurred in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas and New Mexico.

Note 2—Basis of Presentation

The accompanying financial statements have been prepared on a “carve-out” basis and are derived from the financial statements and accounting records of the Parent. The financial statements have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). These financial statements may not be indicative of the future performance of the Contributed Assets and do not necessarily reflect what the results of operations, financial position and cash flows would have been had the Contributed Assets been operated as an independent company during the periods presented.

The accompanying financial statements include direct expenses related to the Contributed Assets and expense allocations for certain functions of the Parent including, but not limited to, general corporate expenses related to finance, legal, information technology, human resources, communications, insurance, utilities, and compensation. These expenses have been allocated on the basis of direct usage when identifiable, actual volumes and revenues, with the remainder allocated proportionately on a barrel of oil equivalent (“BOE”) basis. Management considers the basis on which the expenses have been allocated to reasonably reflect the utilization of services provided to or the benefit received by the Contributed Assets during the periods presented. The allocations may not, however, reflect the expenses that would have been incurred as an independent company for the periods presented. Actual costs that may have been incurred if the Contributed Assets had been a stand-alone entity would depend on a number of factors, including the organizational structure, whether functions were outsourced or performed by employees and strategic decisions made in areas such as information technology and infrastructure. The allocations and related estimates and assumptions are described more fully in Note 12—“Transactions with Related Parties.”

Subsequent events have been evaluated through the issuance date of these financial statements. Any material subsequent events that occurred prior to such date have been properly recognized or disclosed in the accompanying financial statements.

Note 3—Summary of Significant Accounting Policies

Risks and Uncertainties

Revenue, profitability and future rate of growth related to the Contributed Assets are substantially dependent on prevailing prices for oil, natural gas, and natural gas liquids (“NGLs”). Historically, the energy

 

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NOTES TO THE FINANCIAL STATEMENTS

 

markets have been very volatile, and there can be no assurance that commodity prices will not be subject to wide fluctuations in the future. A substantial or extended decline in commodity prices could have a material effect on the financial position, results of operations, cash flows, access to capital and on the quantities of oil, natural gas, and NGL reserves that can be economically produced from the Contributed Assets. It is possible for any of these effects to occur in the near term, given the recent volatility in commodity pricing.

Use of Estimates

The preparation of financial statements in accordance with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting periods; and the quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of oil and natural gas properties. Actual results could differ significantly from these estimates. Significant estimates made by management include the quantities of proved oil, natural gas, and NGL reserves and the fair value of its commodity derivative positions.

While management believes these estimates are reasonable, changes in facts and assumptions of the discovery of new information may result in revised estimates. Actual results could differ from these estimates and it is at lease reasonably possible these estimates could be revised in the near term, and these revisions could be material.

Revenue Recognition

Substantially all of the oil, natural gas and NGLs are sold at market-based prices to a variety of purchasers. For operated properties, revenue from the production of oil, natural gas, and NGLs is recognized when the product is delivered to the customer and collectability is reasonable assured. For non-operated properties, revenue from the production of oil, natural gas, and NGLs is recognized under the sales method. Under the sales method, should excess sales exceed the share of estimated remaining recoverable reserves related to the Contributed Assets, a liability would be recorded. Differences between sales and entitled share of production are not material.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash and short-term, highly liquid investments with maturities of three months or less when acquired and are stated at cost, which approximates fair value.

Concentration of Credit Risk

Financial instruments with potential credit risk consist principally of cash and cash equivalents, accounts receivable, commodity derivative financial instruments and debt. Cash and cash equivalent balances with major financial institutions, at times, may exceed federally insured limits; however, management believes there is no significant credit risk related to cash and cash equivalents.

As the operator of a property, full payment for costs associated with the property is made and reimbursement is sought from the other working interest partners in the property for their share of those costs. The joint interest partners consist primarily of independent oil and natural gas producers. If the oil and natural gas exploration and production industry in general was adversely affected, the ability to collect reimbursements from the joint interest partners could also be adversely affected.

 

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ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

The purchasers of oil, natural gas and NGL production consist primarily of marketers, major oil and gas companies, and oil and gas pipeline companies. Credit evaluations on the purchasers of the production are performed and their financial condition is monitored on an ongoing basis.

The commodity derivative transactions related to the Contributed Assets are carried out in the over-the-counter market and some are subject to margin-deposit requirements. The use of commodity derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties for all of the commodity derivative transactions have an “investment grade” credit rating. Credit ratings of hedging counterparties are monitored on an ongoing basis. Although the commodity derivative contracts were entered into with three counterparties to mitigate the exposure to any individual counterparty, if any of the counterparties were to default on its obligations under the commodity derivative contracts or seek bankruptcy protection, it could have a material adverse effect on the ability to fund planned activities related to the Contributed Assets and could result in a larger percentage of future production being subject to commodity price volatility. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in commodity derivative transactions, which could result in greater concentration of the exposure to any one counterparty or a larger percentage of the future production being subject to commodity price changes.

Major Customers

Gateway Gathering and Marketing Company (“Gateway”, a wholly-owned subsidiary of Rosemore), ETC Field Services, LLC (“ETC”) and Enlink Midstream Services, LLC (“Enlink”) accounted for 70%, 17% and 10%, respectively, of total revenues related to the Contributed Assets for the year ended December 31, 2016. For the year ended December 31, 2015, Gateway, Sunoco Inc. (“Sunoco”), Enlink and Regency Energy Partners LP (“Regency”) accounted for 54%, 13%, 11% and 11%, respectively, of total revenues related to the Contributed Assets. For the year ended December 31, 2014, Enterprise Crude Pipeline, LLC, Sunoco, Devon Gas Services, LP and Regency accounted for 33%, 32%, 18% and 11%, respectively, of total revenues related to the Contributed Assets. If any significant customers are lost, such loss could adversely affect revenue derived from the oil and natural gas properties related to the Contributed Assets.

At December 31, 2016, Gateway and ETC accounted for 78% and 14% of accounts receivable, including related party amounts, respectively. At December 31, 2015, Gateway and Enlink accounted for 69% and 21% of accounts receivable, including related party amounts, respectively.

Any concentration of customers may impact overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions impacting the oil and natural gas industry.

Accounts Receivable

Accounts receivable are accounted for at the contractual amounts less allowance for doubtful accounts. Provisions for losses on accounts receivable are established if it is determined that collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific identification method. There was no allowance for doubtful accounts as of December 31, 2016 and 2015.

Inventory

Inventories related to the Contributed Assets primarily consist of tubular goods and well equipment held for use in oil and natural gas operations. Inventories are carried at the lower of cost or market.

 

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ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

Derivative Financial Instruments

Commodity derivative instruments are recorded on the balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. While commodity derivative instruments are utilized to manage the price risk attributable to expected oil and natural gas production, commodity derivative instruments are not designated as accounting hedges under the accounting guidance. The related cash flow impact of the commodity derivative activities is reflected as cash flows from operating activities unless they are determined to have a significant financing element at inception, in which case they are classified within financing activities.

In order to manage the interest rate risk associated with long term debt, an interest rate swap agreement was entered into in 2012. Hedge accounting was not applied to the interest rate derivative contract; therefore, changes in fair value are recorded in earnings through interest expense. Cash settlements related to current interest rate swap contracts are reflected as cash flows from operating activities unless they are determined to have a significant financing element at inception, in which case they are classified within financing activities.

Oil and Natural Gas Properties

Oil and natural gas properties are accounted for under the successful efforts method of accounting. Under the successful efforts method, costs to acquire interests in oil and natural gas properties, property acquisitions, successful exploratory costs, development costs, and support equipment and facilities are capitalized when incurred. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for natural gas and oil leases, costs associated with unsuccessful lease acquisitions and carrying and retaining unproved properties, and exploratory dry hole drilling costs are charged to expense as incurred. Costs of drilling exploratory wells are initially capitalized, but are charged to expense if the well is determined to be unsuccessful. In order for exploratory well costs to be capitalized, a sufficient quantity of reserves must be discovered to justify its completion as a producing well and that sufficient progress must be made in assessing the well’s economic and operating feasibility. If both of these requirements are not met, the costs are expensed. There were no exploratory well costs pending determination of proved reserves at December 31, 2016 or 2015, nor any unsuccessful exploratory dry hole costs during the years ended December 31, 2016, 2015 or 2014.

The costs of unproved leaseholds and mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts, at which time the costs are transferred to proved oil and natural gas properties if those efforts are deemed successful.

The cost of normal maintenance and repairs is charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the shorter of the estimated remaining useful life of the asset or the term of the lease, if applicable.

Acquisition costs and development costs of proved oil and natural gas properties, including estimated dismantlement, restoration and abandonment costs, are depreciated and depleted on a field-by-field basis by the units-of-production method using proved reserves and proved developed reserves, respectively. Depreciation, depletion and amortization (“DD&A”) expense related to oil and natural gas properties was $24.4 million, $22.8 million and $15.4 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated DD&A, unless doing so significantly affects the units-of-production amortization rate, in which case a gain or loss is recognized in income. As such, gain or loss, if any, is recognized only when a group of proved properties (entire field) that constitute an amortization base has been retired, sold or abandoned.

 

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ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

Other Property and Equipment

Other property and equipment, including office furniture, computer hardware and software, equipment and buildings, is recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets. Buildings are depreciated on a straight-line basis over five years. Compression equipment is depreciated on a straight-line basis over 15 years. Certain other property and equipment are depreciated on a straight-line basis over three to seven years. Depreciation and amortization expense was $0.4 million for each of the years ended December 31, 2016, 2015 and 2014.

Impairment of Long-Lived Assets

Long-lived assets are reviewed each reporting period for possible impairment, or whenever changes in circumstances indicate that the carrying amount of assets may not be fully recoverable. Possible indicators of impairment include lower expected future oil and natural gas prices, actual or expected future development or operating costs significantly higher than previously anticipated, significant downward oil and natural gas reserve revisions, or when changes in other circumstances indicate the carrying amount of an asset may not be recoverable. An impairment loss is recognized for proved properties when the estimated undiscounted future cash flows expected to result from the long-lived asset are less than its carrying amount. The undiscounted future cash flows of the long-lived assets are estimated to assess the recoverability of carrying amounts, and such cash flows are determined on the basis of reasonable and documented assumptions that represent the best estimate of the future economic conditions during the remaining useful life of the asset. If the carrying amount exceeds the estimated undiscounted future cash flows, the carrying amount of the long-lived asset will be written down to its fair value.

Unproved leasehold costs are assessed for impairment at the end of each reporting period and transferred to proved oil and natural gas properties to the extent they are associated with successful exploration activities. Significant unevaluated leasehold costs are individually assessed for impairment based on current exploration plans, and any impairment is charged to expense.

Asset Retirement Obligations

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, a liability (asset retirement obligation or “ARO”) is recorded on the balance sheet and the present value of the asset retirement cost (“ARC”) is capitalized in oil and natural gas properties in the period in which the ARO is incurred. Settlements include payments made to satisfy the AROs. Transfers of AROs to purchasers of divested properties are recorded as part of the gain or loss on sale.

In general, the amount of the initial ARO and ARC will equal the estimated future costs to satisfy the abandonment obligation assuming normal operation of the assets, using current prices that are escalated by an estimated inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using the appropriate credit adjusted risk-free rate. After recording these amounts, ARO is accreted to its future estimated value and the original ARC is depreciated on a units-of-production basis with the related asset.

Capitalized Interest

Significant oil and natural gas investments in unproved properties and significant exploration and development projects that have not commenced production that are undergoing the construction of assets which

 

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NOTES TO THE FINANCIAL STATEMENTS

 

have not commenced principle operations qualify for interest capitalization. For such significant projects, interest is capitalized as part of the historical cost of developing and constructing assets until the asset is ready for service. Capitalized interest is determined by multiplying the weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Once the qualifying asset is completed and placed in service, the associated capitalized interest is expensed through depreciation or impairment. No capitalized interest was recorded during the years ended December 31, 2016, 2015 or 2014, respectively, because the drilling of exploration and development wells generally lasts less than three months and the capitalized interest on these wells would be inconsequential.

Income Taxes

The Contributed Assets are owned by Tema which is treated as a partnership for U.S. federal income tax purposes and for purposes of certain state and local income taxes. For such purposes, Tema’s net taxable income and any related tax credits are passed through to the members of Tema and are included in the member’s tax returns, even though such net taxable income or tax credits may not have actually been distributed. Accordingly, no provision has been made in the financial statements for such income taxes paid at the shareholder level.

Income tax expense on the Statements of Operations relate to the Texas franchise tax, at a statutory rate of 0.75% of taxable margin. Deferred tax assets and liabilities are recognized for future Texas franchise tax consequences attributable to differences between the financial statement carrying amount of existing assets and liabilities and their respective Texas franchise tax bases. For each of the years ended December 31, 2016 and 2015, the Texas franchise tax expenses incurred was $0.1 million. For the year ended December 31, 2014, no Texas franchise tax expense was incurred.

The effects of uncertain tax positions are recognized in the financial statements if these positions meet a “more-likely-than-not” threshold. For those uncertain tax positions that are recognized in the financial statements, liabilities are established to reflect the portion of those positions it cannot conclude “more-likely-than-not” to be realized upon ultimate settlement. As of December 31, 2016 and 2015, no uncertain tax positions were recognized as liabilities in the financial statements.

Investments

The accompanying financial statements of the Contributed Assets includes short term investments consisting of mutual funds which were accounted for as marketable securities and recorded at fair value based on quoted market prices. Dividends received from these short term investments were $0.3 million during the year ended December 31, 2014, and were recorded in “Other income (expense), net” in the accompanying Statements of Operations. During the year ended December 31, 2014, proceeds of $24.6 million were received from the sale of the short term investments and a gain of $0.1 million was recorded in “Other income (expense), net” in the accompanying Statements of Operations.

Fair Value of Financial Instruments

The carrying values of the current financial instruments, which include cash and cash equivalents, accounts receivable, other assets, accounts payable, and accrued and other liabilities approximate their fair value as of December 31, 2016 and 2015 due to the short-term nature of those instruments. Refer to Note 7— “Fair Value Measurements” for a discussion on the fair values of the commodity derivatives and the Credit Agreement.

 

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ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

Recently Issued Accounting Standards

In April 2015, the FASB issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. ASU 2015-03 is effective for fiscal years beginning after December 15, 2015, including interim periods therein, and is applied retrospectively. Early adoption is permitted for financial statements that have not been previously issued. In August 2015, ASU 2015-15, Presentation and Subsequent Measurement of Debt Issue Costs Associated with Line of Credit Arrangements, was subsequently issued to address the absence of authoritative guidance for debt issuance costs related to line-of-credit arrangements and states that an entity may continue to present debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. Given the debt issuance costs relate to the Credit Agreement, the current accounting and disclosure for such costs was not impacted.

In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, which requires that inventory is measured at the lower of cost or net realizable value (“NRV”), with the latter defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This ASU eliminates the need to determine market or replacement cost and evaluate whether it is above the ceiling at NRV or below the floor (NRV less a normal profit margin). The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted. The adoption of this ASU is not expected to have a material impact on the financial statements.

In August 2015, the FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of Effective Date, which defers the effective date of ASU 2014-09 by one year to be effective for annual reporting periods beginning after December 15, 2018 and the interim periods therein. ASU 2014-09, Revenue from Contracts with Customers, supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities—Oil and Gas—Revenue Recognition and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Subsequently, in April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing as further clarification on identifying performance obligations and the licensing implementation guidance. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow—Scope Improvements and Practical Expedients, as clarifying guidance to improve the operability and understandability of the implementation guidance on principal versus agent considerations. In December 2016, the FASB further issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers, to increase stakeholders’ awareness of the proposals and to expedite improvements to ASU 2014-09. The method of adoption and impact these standards will have on the financial statements and related disclosures is currently being evaluated.

In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 704): Balance Sheet Classification of Deferred Taxes, which eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and non-current in a classified balance sheet. Instead, companies are required to classify all deferred tax assets and liabilities as non-current. ASU 2015-17 is effective for interim and annual periods beginning after December 15, 2016. The adoption of this ASU is not expected to have a material impact on the financial statements given the pass-through nature of the Parent for tax purposes.

 

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Index to Financial Statements

ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under previous U.S. GAAP. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The method of adoption and impact this standard will have on the financial statements and related disclosures is currently being evaluated.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments requiring the measurement of all expected credit losses for financial assets, which include trade receivables, held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. The method of adoption and impact this standard will have on the financial statements and related disclosures is currently being evaluated.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 320): Classification of Cash Receipts and Cash Payments, which addresses eight specific cash flow issues with the objective of reducing the existing diversity of presentation and classification in the statement of cash flows. The new standard applies to cash flows associated with debt payment or debt extinguishment costs, settlement of zero-coupon debt or other debt instruments with coupon rates that are insignificant in relation to effective interest rate of borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal periods. Early adoption is permitted, but only if all amendments are adopted in the same period. The impact this standard will have on the financial statements and related disclosures is currently being evaluated.

In January 2017, the FASB issued ASU 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within these fiscal years. The impact this standard will have on the financial statements and related disclosures is currently being evaluated.

In February 2017, the FASB issued ASU 2017-05, Other Income—Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets, which clarifies the scope of Subtopic 610-20 and provides further guidance for partial sales of nonfinancial assets. Subtopic 610-20, which was issued in May 2014 as part of ASU 2014-09, provides guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with noncustomers. An entity is required to apply the amendments in ASU 2017-05 at the same time it applies the amendments in ASU 2014-09. An entity may elect to apply the amendments in ASU 2017-05 either retrospectively to each period presented in the financial statements in accordance with the guidance on accounting changes in FASB’s Accounting Standards Codification (“ASC”) Topic 250, Accounting Changes and Error Corrections, paragraphs 10-45-5 through 10-45-10 (i.e. the retrospective approach) or retrospectively with a cumulative-effect adjustment to retained earnings as of the beginning of the fiscal year of adoption (i.e. the modified retrospective approach). An entity may elect to apply all of the amendments in ASU 2017-05 and ASU 2014-09 using the same transition method, and alternatively

 

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Index to Financial Statements

ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

may elect to use different transition methods. The impact ASU 2017-05 will have on the financial statements and related disclosures is currently being evaluated.

Note 4—Business Combination

On December 20, 2016, Tema entered into a Business Combination Agreement with KLRE, pursuant to which, and subject to the terms and adjustments set forth therein, KLRE will acquire a portion of the equity of Rosehill Operating, to which Tema will contribute and transfer certain assets and liabilities, for (i) the contribution to Rosehill Operating by KLRE of a certain cash consideration and for the issuance to Rosehill Operating by KLRE of 29,807,692 shares of its Class B common stock (which cash and shares of Class B common stock will immediately be distributed by Rosehill Operating to Tema), (ii) the assumption by Rosehill Operating of $55.0 million in Tema indebtedness and (iii) the contribution to Rosehill Operating by KLRE of the remaining cash proceeds of its initial public offering (the “Business Combination”).

In connection with the closing of the Business Combination, (i) KLRE will issue to Rosehill Operating 4.0 million warrants exercisable for shares of Class A common stock (the “Tema warrants”) in exchange for 4.0 million warrants exercisable for Rosehill Operating common units (the “Rosehill warrants”) deemed equal to the Tema warrants and (ii) the Tema warrants and $35.0 million will immediately be distributed to Tema. In addition, KLRE will contribute the proceeds of a certain PIPE Investment to Rosehill Operating in exchange for Rosehill Operating Series A Preferred Units and additional 5.0 million Rosehill warrants. The Business Combination is expected to close in the second quarter of 2017, subject to certain closing conditions, including receipt of KLRE shareholder approval.

Note 5—Accounts Receivable

Accounts receivable is comprised of the following as of December 31, 2016 and 2015:

 

		2016				2015
(In thousands)
Revenue receivable		$	1,291			$	337
Joint interest billings			557				1,765
Other			80				—
Accounts receivable		$	1,928			$	2,102

 

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NOTES TO THE FINANCIAL STATEMENTS

 

Note 6 —Derivative Instruments

Various commodity derivative instruments have been entered into to mitigate a portion of the exposure to potentially adverse market changes in commodity prices, market interest rates and associated impact on cash flows. All contracts are entered into for other-than-trading purposes. The derivative contracts include commodity options and swaps, and an interest rate swap.

The fair value of the derivative assets and liabilities as of December 31, 2016 and 2015, respectively, is as follows:

 

		2016				2015
(In thousands)
Derivative assets
Commodity derivative options		$	21			$	1,533
Interest rate swap			226				—
Total		$	247			$	1,533
Derivative liabilities
Commodity derivative options		$	—			$	4
Commodity derivative swaps			1,856				18
Interest rate swap			—				98
Total		$	1,856			$	120

As of December 31, 2016, the open commodity derivative positions with respect to future production were as follows:

 

		2017
(In unit of measure specified)
Commodity derivative swaps
Oil:
Notional volume (Barrels)			273,000
Weighted average price ($/Barrel)		$	51.56
Natural Gas:
Notional volume (MMBtu)			1,480,000
Weighted average price ($/MBtu)		$	3.15
Commodity derivative options
Oil:
Notional volume (Barrels)			406,000
Weighted average price ($/Barrel)		$	46.89
Natural Gas:
Notional volume (MMBtu)			2,550,000
Weighted average price ($/MBtu)		$	3.15

 

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ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

For the years ended December 31, 2016, 2015 and 2014, the effect of the derivative activity on the Statements of Operations is as follows:

 

		2016				2015				2014
(In thousands)
Realized gain (loss) on derivatives
Commodity derivative options		$	511			$	4,340			$	20
Commodity derivative swaps			(1,334	)			130				26
Total			(823	)			4,470				46
Interest rate swap			(785	)			(1,165	)			(1,186	)
Total realized gain (loss) on derivatives			(1,608	)			3,305				(1,140	)
Unrealized gain (loss) on derivatives
Commodity derivative options		$	(1,508	)		$	(735	)		$	2,358
Commodity derivative swaps			(1,838	)			—				—
Total			(3,346	)			(735	)			2,358
Interest rate swap			324				(677	)			(3,292	)
Total unrealized loss on derivatives		$	(3,022	)		$	(1,412	)		$	(934	)

The gains and losses resulting from the cash settlement and mark-to-market of the commodity derivatives are included within “Revenues” in the Statements of Operations. The gains and losses resulting from the cash settlement and mark-to-market of the interest rate swap are included in “Interest expense” in the Statements of Operations.

Note 7—Fair Value Measurements

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 at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:

Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis, such as commodity options.

Level 2—Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset of liability. This category includes those derivative instruments that are valued using observable market data, such as derivatives related to interest rate swaps.

Level 3—Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources. Pricing inputs are unobservable for the investment and includes situations where there is little, if any, market activity for the investment, such as commodity swaps.

Observable data is considered to be market data if it is readily available, regularly distributed or updated, reliable and verifiable, not proprietary, provided by multiple, independent sources that are actively involved in the relevant market. In certain cases, the inputs used to measure fair value may fall into different levels of the fair

 

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ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

value hierarchy. In such cases, an investment’s level with the fair value hierarchy is based on lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the investment. However, the determination of what constitutes “observable” requires significant judgment. The categorization of an investment within the hierarchy is based upon the pricing transparency of the investment and does not necessarily correspond to the perceived risk of that investment.

Fair Value of Financial Instruments

The financial instruments measured at fair value on a recurring basis consist of the following as of December 31, 2016 and 2015:

 

		2016				2015
(In thousands)
Derivative instruments:
Derivative assets			247				1,533
Derivative liabilities			(1,856	)			(120	)
Total recurring fair value measurement		$	(1,609	)		$	1,413

Derivative instruments represent unrealized amounts related to the derivative positions, including swaps and options, within current assets and current liabilities on the Balance Sheets.

The tables below set forth by level within the fair value hierarchy the gross components of the assets and liabilities that were measured at fair value on a recurring basis as of December 31, 2016 and 2015. These gross balances are intended solely to provide information on sources of inputs to fair value and proportions of fair value involving objective versus subjective valuations and do not represent either the actual credit exposure or net economic exposure.

 

		2016
		Level 1				Level 2				Level 3				Total
(In thousands)
Derivative assets			21				226				—				247
Commodity derivative liabilities			(1,856	)			—				—				(1,856	)
Total derivative assets (liabilities)		$	(1,835	)		$	226			$	—			$	(1,609	)
		2015
		Level 1				Level 2				Level 3				Total
(In thousands)
Commodity derivative assets			1,533				—				—				1,533
Derivative liabilities			(4	)			(98	)			(18	)			(120	)
Total derivative assets (liabilities)		$	1,529			$	(98	)		$	(18	)		$	1,413

 

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NOTES TO THE FINANCIAL STATEMENTS

 

The following table summarizes the changes in the fair value of the Level 3 assets (liabilities) measured on a recurring basis for the years ended December 31, 2016 and 2015:

 

		2016				2015
(In thousands)
Balances at beginning of year		$	(18	)		$	40
Sales			—				(18	)
Settlements			18				(40	)
Net purchases, sales and settlements			18				(58	)
Transfers into and out of Level 3			—				—
Balances at end of year		$	—			$	(18	)

Financing Arrangements

The fair value measurements for the Credit Agreement represent Level 2 inputs. Based on the average of certain imputed interest rates, the fair value of the Credit Agreement is estimated to be $51.6 million and $59.3 million as of December 31, 2016 and 2015, respectively.

Non-Financial Assets and Liabilities

Non-financial assets and liabilities that are initially measured at fair value on a recurring basis are comprised primarily of ARO and ARC, which are recorded at fair value when acquired or incurred and not re-measured at fair value in subsequent periods. Such initial measurements are classified as Level 3 since certain significant unobservable inputs are utilized in their determination. The fair value of additions to ARO liability and certain changes in the estimated fair value of the liability are measured using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs to the valuation include (i) estimated plug and abandonment cost per well based on historical experience and information from third-party vendors; (ii) estimated remaining life per well; (iii) future inflation factors; and (iv) average credit-adjusted risk-free rate. These inputs require significant judgments and estimates by management at the time of the valuation and are the most sensitive and subject to change.

If the carrying amount of oil and natural gas properties exceeds the estimated undiscounted future cash flows, the carrying amount of the oil and natural gas properties will be adjusted to the fair value. The fair value of oil and natural gas properties is determined using valuation techniques consistent with the income and market approach. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, (i) recent sales prices of comparable properties; (ii) the present value of future cash flows, net of estimated operating and development costs using estimates of proved oil and natural gas reserves; (iii) future commodity prices; (iv) future production estimates; (v) anticipated capital expenditures; and (vi) various discount rates commensurate with the risk and current market conditions associated with the projected cash flows. These assumptions represent “Level 3” inputs.

 

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NOTES TO THE FINANCIAL STATEMENTS

 

Note 8—Property and equipment

Property and equipment is comprised of the following as of December 31, 2016 and 2015:

 

		2016				2015
(In thousands)
Proved oil and natural gas properties		$	258,530			$	235,541
Unproved oil and natural gas properties			1,942				1,376
Land			1,561				—
Other property and equipment			3,808				3,818
Total property and equipment			265,841				240,735
Less: accumulated DD&A(1)			(142,468	)			(117,862	)
Property and equipment, net		$	123,373			$	122,873

 

(1)	Accumulated DD&A of oil and natural gas properties, including impairment, is $139.8 million and $115.3 million as of December 31, 2016 and 2015, respectively.

There were no impairment charges attributable to proved oil and natural gas properties recorded during the year ended December 31, 2016. During 2015 and 2014, significant declines in oil and natural gas market prices indicated that the carrying values of certain oil and natural gas properties were impaired. At December 31, 2015 and 2014, the estimated undiscounted future cash flows of various oil and natural gas properties were less than their respective carrying values, and as a result, impairment charges were recorded attributable to proved oil and natural gas properties of $8.1 million and $27.6 million, respectively, for the years ended December 31, 2015 and 2014. Further declines in commodity prices could potentially result in future impairments of oil and natural gas properties.

Note 9—Asset Retirement Obligations

The change in ARO related to the Contributed Assets for the years ended December 31, 2016 and 2015 is set forth below:

 

		2016				2015
(In thousands)
Carrying amount of ARO at January 1		$	3,667			$	3,042
Liabilities incurred			164				56
Liabilities settled			(53	)			(10	)
Accretion expense			176				120
Revisions of estimated liabilities			1,477				459
Carrying amount of ARO at December 31			5,431				3,667
Less: current portion of ARO			(251	)			—
Long term ARO		$	5,180			$	3,667

 

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NOTES TO THE FINANCIAL STATEMENTS

 

Note 10—Accrued Liabilities and Other

Accrued liabilities and other is comprised of the following as of December 31, 2016 and 2015:

 

		2016				2015
(In thousands)
Accrued payroll		$	948			$	532
Accrued professional fees			223				—
Production taxes			120				134
Royalties payable			2,494				1,005
Advances from joint owners			219				395
Deferred rent			138				132
Current portion of ARO			251				—
Accrued capital expenditures			2,443				1,009
Other			369				196
Total		$	7,205			$	3,403

Note 11—Debt and Note Payable to Related Party

A summary of changes in amounts due under the Credit Agreement is as follows for the years ended December 31, 2016 and 2015:

 

		2016				2015
(In thousands)
Beginning balance at January 1		$	65,000			$	75,000
Borrowings			10,000				—
Repayments			(20,000	)			(10,000	)
Ending balance at December 31			55,000				65,000
Less: current portion of long-term debt			—				(20,000	)
Long term debt		$	55,000			$	45,000

Credit Agreement

In December 2012, a secured line of credit was entered into with a bank for $60.0 million (the “Credit Agreement”), with an optional expansion to $75.0 million, subject to satisfactory credit underwriting. Borrowings under the Credit Agreement bear interest at floating London Interbank Offered Rate (“LIBOR”) plus 1.00% (the Applicable Margin), and are collateralized by the existing producing oil and natural gas properties. There is no principal amortization required until the expiration of the Credit Agreement, when all outstanding amounts become due. The Credit Agreement expires December 28, 2017, unless otherwise amended. The Credit Agreement is subject to periodic, but no less than semi-annual, redeterminations of the borrowing base. Redeterminations are based on the mid-year and year-end oil and gas reserve reports.

In 2013, the option to expand the Credit Agreement to $75.0 million was exercised and as of January 1, 2015, the Credit Agreement was fully drawn. In September 2015, the borrowing base was reduced to $68.0 million as a result of the regular semi-annual redetermination process. The decrease in borrowing base was primarily due to the impact of declining oil and natural gas commodity prices. The debt was paid down as required, and as of December 31, 2015, the outstanding balance on the Credit Agreement was $65.0 million.

 

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NOTES TO THE FINANCIAL STATEMENTS

 

In March 2016, the borrowing base was reduced to $45.0 million as a result of the semi-annual redetermination process. The second reduction was again primarily due to the impact of declining oil and natural gas commodity prices. The debt was paid down as required. In September 2016, the borrowing base was increased to $55.0 million as a result of the regular semi-annual redetermination process. The increase in borrowing base was due in part to an increase in reserves and an increase in oil and natural gas commodity prices. The additional borrowing base was drawn on November 18, 2016. As of December 31, 2016, the outstanding balance on the Credit Agreement was $55.0 million.

In December 2014, the Credit Agreement was amended for a modification to the indebtedness covenant to permit certain subordinated debt (the “First Amendment to the Credit Agreement”). Please refer to “Note Payable to Related Party” below.

In September 2016, the Credit Agreement was amended to modify certain definitions, certain covenants, increasing the Applicable Commitment Fee Rate and Applicable Margin, and Applicable Letter of Credit fee, and waiving certain defaults (the “Second Amendment to the Credit Agreement”). The Applicable Commitment Fee Rate under the Credit Agreement was increased from 0.15% to 0.50% to be calculated on the borrowing base limit rather than the undrawn Credit Agreement and paid quarterly. The Applicable Margin was increased from 1.00% to 2.00%. The Applicable Letter of Credit Fee was increased from 1.00% to 2.00%. As of December 31, 2016, Tema was in compliance with all covenants in relation to the Credit Agreement.

On March 6, 2017, the Credit Agreement was amended to extend the original expiration date to June 30, 2018 (the “Third Amendment to the Credit Agreement”).

The aggregate interest expense under the Credit Agreement was $1.4 million, $1.2 million and $1.0 million during the years ended December 31, 2016, 2015 and 2014, respectively.

The Credit Agreement will not be transferred to Rosehill Operating at the closing of the Business Combination as discussed in Note 4—“Business Combination”. The financial covenants contained in the Credit Agreement are determined based on the net worth and operating results of Tema, which include the Contributed Assets. In connection with the Business Combination, the Credit Agreement is expected to be refinanced and will include covenants specific to Rosehill Operating and the Contributed Assets.

Interest Rate Swap

Concurrent with the initial $60.0 million drawdown of the Credit Agreement, an interest rate swap was entered into with a bank to fix the interest rate of the Credit Agreement. The interest rate swap expires in 2022 and includes an option that expires on December 28, 2017, which allows the swap to unwind at par. The cost of the option was financed into the swap, resulting in a slightly higher interest rate for the 10-year period. The notional amount of the interest rate swap is $60.0 million with a fixed rate of 2.11%. The fair value of the interest rate swap as of December 31, 2016 and 2015 was an asset of $0.2 million and a liability of $0.1 million, respectively. The additional $15.0 million expansion of the Credit Agreement in 2013 was not swapped. Consequently, the outstanding portion of the note payable over $60.0 million bore interest at floating LIBOR based rates. In conjunction with the March 2016 Credit Agreement redetermination to the new borrowing base of $45.0 million, the notional amount of the interest rate swap was reduced from $60.0 million to $45.0 million and an expense of $0.2 million was recognized for the fee paid to the bank related to the reduction of the interest rate swap.

Interest expense related to realized losses on the interest rate swap was $0.8 million for the year ended December 31, 2016, and $1.2 million for each of the years ended December 31, 2015 and 2014. Interest expense

 

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NOTES TO THE FINANCIAL STATEMENTS

 

related to unrealized gain on the interest rate swap was $0.3 million for the year ended December 31, 2016. Interest expense related to unrealized losses on the interest rate swap was $0.7 million and $3.3 million for the years ended December 31, 2015 and 2014, respectively.

Debt Issuance Costs

Debt issuance costs consist of certain costs paid in the process of securing the Credit Agreement and are capitalized and subsequently charged to interest expense over the term of the related debt, using the effective interest rate method. As of December 31, 2016 and 2015, unamortized debt issuance costs were $0.1 million and $0.2 million, respectively, and are included in “Prepaid and other current assets” and “Other assets, net” for the respective periods on the accompanying Balance Sheets.

Note Payable to Related Party

In December 2014, a $30.0 million unsecured credit agreement bearing an interest rate of 2.0% was entered into with Rosemore (the “Unsecured Credit Agreement”). The agreement required interest only payments until the maturity date, March 29, 2018, at which time the entire principal and unpaid interest will become due. As of December 31, 2014, $10.0 million was outstanding under the Unsecured Credit Agreement and during 2015, an additional $1.8 million was borrowed under the Unsecured Credit Agreement. In December 2015, Rosemore elected to convert the aggregate outstanding principal amount of $11.8 million to contributed capital. No amounts were outstanding under the Unsecured Credit Agreement as of December 31, 2016 and 2015. During the year ended December 31, 2015, $0.2 million of interest related to the Unsecured Credit Agreement was incurred. No related interest was incurred during the year ended December 31, 2016.

Note 12—Transactions with Related Parties

The Unsecured Credit Agreement with Rosemore is discussed in Note 11—“Debt and Note Payable to Related Party—Note Payable to Related Party.”

Rosemore provides employee benefits and other administrative services to Tema. During the years ended December 31, 2016, 2015 and 2014, Rosemore incurred and billed to Tema approximately $6.0 million, $5.7 million and $7.9 million, respectively, related to these services. A portion of these amounts have been allocated on the Statements of Operations related to the Contributed Assets—please refer to “Cost Allocations” below. As of December 31, 2016 and 2015, the payable due to Rosemore related to these expenses was approximately $0.3 million as of each year end.

A portion of oil, natural gas and NGLs related to the Contributed Assets is sold to Gateway. During the years ended December 31, 2016, 2015 and 2014, revenues from production sold to Gateway were approximately $24.3 million, $16.8 million and less than $0.1 million, respectively. As of December 31, 2016 and 2015, the related receivable due from Gateway was approximately $4.5 million and $1.1 million, respectively.

During the years ended December 31, 2016, 2015 and 2014, approximately $1.4 million, $0.8 million and $0.6 million, respectively, were incurred related to a marketing and gathering agreement with Gateway. As of December 31, 2016 and 2015, the payable due to Gateway related to this agreement was approximately $0.3 million and $0.2 million, respectively.

Certain consulting services are provided to Gateway, and for each of the years ended December 31, 2016, 2015 and 2014, Gateway was invoiced approximately $0.1 million annually related to these services. Certain general and administrative services are also provided to Gateway, for which Gateway was invoiced

 

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Index to Financial Statements

ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

approximately $0.3 million, $0.3 million and $0.4 million, respectively, during the years ended December 31, 2016, 2015 and 2014. As of December 31, 2016 and 2015, the receivable due from Gateway related to these services was approximately $0.3 million and $0.2 million, respectively.

Transaction expenses of $3.0 million have been incurred through December 31, 2016 in connection with the Business Combination and have been included as general and administrative expenses. Under the terms of the Business Combination Agreement, the Parent will be reimbursed for transaction expenses incurred through the closing of the transaction.

Cost Allocations

Tema allocated certain overhead costs associated with general and administrative services, including insurance, professional fees, facilities, information services, human resources and other support departments related to the Contributed Assets. Also included in the cost allocations are costs associated with employees covered under Rosemore’s defined benefit plan and long-term incentive compensation plan. In connection with the proposed reverse merger, employees who transfer to Rosehill Operating will no longer participate in either employee benefit plan.

Where costs incurred related to the Contributed Assets could not be determined by specific identification, the costs are primarily allocated proportionately on a BOE basis. Management believes these allocations are a reasonable reflection of the utilization of services provided. However, the allocations may not fully reflect the expense that would have been incurred had the Contributed Assets been a stand-alone company during the periods presented.

The total amount related to the Contributed Assets for overhead cost allocations for the years ended December 31, 2016, 2015 and 2014, which is recorded in general and administrative costs, was $6.0 million, $4.2 million and $5.2 million, respectively.

Note 13—Commitments and Contingencies

Leases

Noncancelable operating and capital lease commitments for office space and equipment related to the Contributed Assets expire in years 2019 through 2022. The effective interest rate for capital leases is 3.6%. Certain leases have renewal options.

The following is a noncancelable schedule of future minimum lease payments as of December 31, 2016:

 

(In thousands) Years Ending December 31,		Operating Leases				Capital Leases
2017			1,062				34
2018			1,104				34
2019			1,090				34
2020			1,076				—
2021			1,087				—
Thereafter			552				—
Total noncancelable future lease commitments		$	5,971			$	102
Less: imputed interest							(7	)
Present value of obligations under capital leases						$	95

 

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Index to Financial Statements

ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

Rent expense for operating leases is recognized on a straight-line basis over the lease term. Rent expense for the years ended December 31, 2016, 2015 and 2014 was $0.7 million, $0.6 million and $0.4 million, respectively. Amortization of assets acquired under capital leases for each of the years ended December 31, 2016, 2015 and 2014 was less than $0.1 million and is included within “Depreciation, depletion and amortization expense” in the Statements of Operations.

Legal

During 2013, operational difficulties related to the Contributed Assets were experienced, including directional drilling errors on one well and defective casing on two other wells. Lawsuits were filed against the directional drilling company and casing supply vendor to recover damages. The case against the directional drilling company and one case against a casing supply vendor were resolved in 2015 with approximately $2.2 million being recovered from the settlements during the year ended December 31, 2015. The recovered amounts in 2015 were applied against the cost of the related wells. No additional amounts were recovered during the year ended December 31, 2016. Currently, one case against a casing supply vendor is still pending for which mediation has been set for March 23, 2017.

The Parent has been named as a defendant in a personal injury claim related to the Contributed Assets. The Parent is indemnified on this claim through the drilling contractor. Although the outcome of this lawsuit cannot be predicted with certainty, a loss resulting from this claim is not expected.

In the opinion of management, there is no incidental litigation that will have a material adverse effect on the financial condition, results of operations and cash flows.

Environmental Matters

Environmental assessments and remediation efforts are conducted at multiple locations, primarily previously owned or operated facilities. Environmental and clean-up costs are accrued when it is both probable that a liability has been incurred and the amount can be reasonably estimated. Accruals for losses from environmental remediation obligations generally are recorded no later than completion of the remediation feasibility study. Estimated costs, which are based upon experience and assessments, are recorded at undiscounted amounts without considering the impact of inflation and are adjusted periodically as additional or new information is available. Environmental assessments and remediation costs for the years ended December 31, 2016, 2015 and 2014 did not have a material adverse effect on the financial condition, results of operations and cash flows.

Note 14—Supplementary Disclosures of Oil and Natural Gas Activities (Unaudited)

The unaudited supplemental information on oil and natural gas exploration and production activities for 2016, 2015, and 2014 has been presented in accordance with FASB’s ASC Topic 932, Extractive Activities—Oil and Gas and the SEC’s final rule, Modernization of Oil and Gas Reporting.

Capitalized Costs

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas

 

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ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion. For a summary of these costs, please refer to Note 8—“Property and Equipment.”

Costs Incurred for Property Acquisition, Exploration, and Development

Amounts reported as costs incurred include both capitalized costs and costs charged to expense when incurred for oil and natural gas property acquisition, exploration, and development activities. Costs incurred also include new AROs established in the current year as well as increases or decreases to ARO resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful and unsuccessful exploration wells during the year, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

The following table summarizes the costs incurred for oil and natural gas property acquisition, exploration, and development activities for the years ended December 31, 2016, 2015 and 2014:

 

		2016				2015				2014
(In thousands)
Property acquisition costs		$	572			$	1,382			$	3,595
Exploration costs			12,517				4,851				39,821
Development costs			11,143				9,347				33,352
Total costs incurred		$	24,232			$	15,580			$	76,768

Estimated Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2016 were prepared by Ryder Scott, Rosehill Operating’s independent petroleum engineer. Proved oil and natural gas reserve estimates as of December 31, 2015 and 2014 were prepared internally by management. The proved oil and natural gas reserve estimates were prepared in accordance with definitions and guidelines established by the SEC. Accordingly, the reserve estimates are based upon existing economic and operating conditions.

There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows (“Standardized Measure”) should not be construed as the current market value of the oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.

 

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ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

The following tables disclose changes in the estimated net quantities of oil, NGL, and natural gas reserves, all of which are located onshore within the continental United States, for the years ended December 31, 2016, 2015 and 2014:

 

		2016				2015				2014
Proved developed and undeveloped reserves:
Oil (MBbls)
Beginning of period			5,652				6,289				3,242
Revisions to previous estimates(1)			(1,221	)			(3,542	)			(282	)
Extensions and discoveries(2)			3,537				3,377				3,694
Production			(612	)			(472	)			(365	)
End of period			7,356				5,652				6,289
Natural Gas (MMcf)
Beginning of period			13,899				27,622				26,213
Revisions to previous estimates(1)			143				(15,983	)			(5,519	)
Extensions and discoveries(2)			5,694				4,334				8,762
Production			(2,381	)			(2,074	)			(1,834	)
End of period			17,355				13,899				27,622
NGL (MBbls)
Beginning of period			1,994				4,299				4,423
Revisions to previous estimates(1)			360				(2,581	)			(1,411	)
Extensions and discoveries(2)			993				588				1,572
Production			(358	)			(312	)			(285	)
End of period			2,985				1,994				4,299
Total proved reserves (MBoe)			13,234				9,963				15,192
Proved developed reserves
Oil (MBbls):
Beginning of period			2,698				3,200				1,570
End of period			3,068				2,698				3,200
Natural gas (MMcf):
Beginning of period			10,116				18,753				20,156
End of period			10,574				10,116				18,753
NGL (MBbls):
Beginning of period			1,481				2,798				3,101
End of period			1,802				1,481				2,798
Proved undeveloped reserves(3)
Oil (MBbls):
Beginning of period			2,954				3,089				1,672
End of period			4,288				2,954				3,089
Natural gas (MMcf):
Beginning of period			3,783				8,869				6,057
End of period			6,781				3,783				8,869
NGL (MBbls):
Beginning of period			513				1,501				1,322
End of period			1,183				513				1,501

 

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ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

 

(1)

For the years ended December 31, 2016, 2015 and 2014, revisions to previous estimates include technical revisions due to changes in commodity prices, historical and projected well performances, changes to lease operating expenses, differentials, transportation, shrink, BTU, NGL and condensate yields, and future development costs.

(2)	For the years ended December 31, 2016, 2015 and 2014, extensions and discoveries include discoveries and additions primarily related to active drilling in the Wolfcamp and Avalon benches in Loving County within the Delaware Basin.

(3)

The proved undeveloped reserves (“PUDs”) are reviewed annually to ensure an appropriate plan for development exists. Generally, reserves for the properties are not booked as PUDs unless there is a plan to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs. The current drilling schedule has all PUDs planned for development within five years from the date of the original booking of the PUD.

Standardized Measure

The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves and changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as an ARO liability on the balance sheet at December 31, 2016 and 2015. Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.

It should not be assumed that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of the estimated oil and natural gas reserves.

The standardized measure of future net cash flows related to estimated proved oil and natural gas reserves as of December 31, 2016, 2015 and 2014 is as follows:

 

		2016				2015				2014
(In thousands)
Future cash inflows		$	360,651			$	306,242			$	793,160
Future costs:
Production			(128,689	)			(108,968	)			(222,337	)
Development and net abandonment			(80,522	)			(48,647	)			(98,267	)
Future net inflows before income taxes			151,440				148,627				472,556
Future income taxes(1)			(1,885	)			(1,598	)			(4,129	)
Future net cash flows			149,555				147,029				468,427
10% discount factor			(69,492	)			(60,760	)			(262,952	)
Standardized measure of discounted future net cash flows		$	80,063			$	86,269			$	205,475

 

(1)	Attributable to Texas margin tax.

 

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ASSETS AND LIABILITIES OF THE BUSINESS TO BE CONTRIBUTED TO

ROSEHILL OPERATING COMPANY, LLC

NOTES TO THE FINANCIAL STATEMENTS

 

Prices for oil and natural gas reserves are based on the preceding 12-months’ average price in regards to closing prices on the first day of each month (the “average price”). As of December 31, 2016 and 2015, the price for NGLs is based on 27.5% of the average price for oil. As of December 31, 2014, the price for NGLs is based on the twelve month average of actual NGL prices received in 2014.

The following table summarizes the average prices used in the calculation of the Standardized Measure as of December 31 of each year.

 

		2016				2015				2014
Natural gas (per MMBtu)		$	2.49			$	2.58			$	4.43
Oil (per barrel)		$	42.75			$	50.28			$	91.61
NGL (per barrel)		$	11.73			$	13.83			$	30.67

Changes in Standardized Measure

The changes in standardized measure of future net cash flows related to estimated proved oil and natural gas reserves for the years ended December 31, 2016, 2015 and 2014 is as follows:

 

		2016				2015				2014
(In thousands)
Standardized measure at the beginning of the period		$	86,269			$	205,475			$	124,703
Sales and transfers of oil and natural gas produced			(25,210	)			(21,731	)			(33,785	)
Net change in prices and production costs			(21,705	)			(77,685	)			18,152
Extensions and discoveries			33,586				42,791				95,506
Changes in estimated future development cost			16				420				78
Revisions of previous quantity estimates			(7,857	)			(78,219	)			(20,224	)
Previously estimated development costs incurred			3,953				2,907				8,031
Accretion of discount			8,720				20,729				12,586
Net change in income taxes			(225	)			876				(657	)
Changes in production rates, timing and other			2,516				(9,294	)			1,085
Aggregate change			(6,206	)			(119,206	)			80,772
Standardized measure at the end of period		$	80,063			$	86,269			$	205,475

 

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ROSEHILL RESOURCES INC.

8.000% SERIES A CUMULATIVE PERPETUAL CONVERTIBLE PREFERRED STOCK

 

 

Prospectus

 

 

 

            , 2017

 

 

 

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PART II—INFORMATION NOT REQUIRED IN PROSPECTUS

 

Item 13.

Other Expenses of Issuance and Distribution

The following table sets forth the costs and expenses payable by the registrant in connection with this offering. All of the amounts shown are estimates except the SEC registration fee.

 

SEC Registration Fee		$	13,264
Legal Fees and Expenses			*
Accounting Fees and Expenses			*
Other			*
Total		$	*

 

*	The estimated expenses are presently undeterminable and will be set forth in the applicable prospectus supplement with respect to the Securities.

We will bear all costs, expenses and fees in connection with the registration of the shares of the Securities, including with regard to compliance with state securities or “blue sky” laws. The selling securityholders, however, will bear all commissions and discounts and transfer taxes, if any, attributable to their sale of the Securities.

 

Item 14.

Indemnification of Directors and Officers

Section 145 of the DGCL provides that a corporation may indemnify any person who was or is a party, or is threatened to be made a party, to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation by reason of the fact that the person is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise), against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by the person in connection with such action, suit or proceeding if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his or her conduct was unlawful. A similar standard is applicable in the case of derivative actions (i.e., actions by or in the right of the corporation), except that indemnification extends only to expenses, including attorneys’ fees, incurred in connection with the defense or settlement of such action and the statute requires court approval before there can be any indemnification where the person seeking indemnification has been found liable to the corporation.

Our amended and restated certificate of incorporation provides that we will, to the fullest extent authorized or permitted by applicable law, indemnify our current and former officers and directors, as well as those persons who, while directors or officers of our corporation, are or were serving as directors, officers, employees or agents of another entity, trust or other enterprise, including service with respect to an employee benefit plan, in connection with any threatened, pending or completed proceeding, whether civil, criminal, administrative or investigative, against all expense, liability and loss (including, without limitation, attorney’s fees, judgments, fines, ERISA excise taxes and penalties and amounts paid in settlement) reasonably incurred or suffered by any such person in connection with any such proceeding. Notwithstanding the foregoing, a person eligible for indemnification pursuant to our amended and restated certificate of incorporation will be indemnified by us in connection with a proceeding initiated by such person only if such proceeding was authorized by our board of directors, except for proceedings to enforce rights to indemnification.

 

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In accordance with Section 102(b)(7) of the DGCL, our amended and restated certificate of incorporation provides that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of their fiduciary duty as directors, except to the extent such limitation on or exemption from liability is not permitted under the DGCL. However, this provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.

Our bylaws also include provisions relating to advancement of expenses and indemnification rights consistent with those set forth in our amended and restated certificate of incorporation. In addition, our bylaws provide for a right of indemnity to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time. Our bylaws also permit us to purchase and maintain insurance, at our expense, to protect us and/or any director, officer, employee or agent of our corporation or another entity, trust or other enterprise against any expense, liability or loss, whether or not we would have the power to indemnify such person against such expense, liability or loss under the DGCL.

Any repeal or amendment of provisions of our amended and restated certificate of incorporation or our bylaws affecting indemnification rights, whether by our stockholders or by changes in law, or the adoption of any other provisions inconsistent therewith, will (unless otherwise required by law) be prospective only, except to the extent such amendment or change in law permits us to provide broader indemnification rights on a retroactive basis, and will not in any way diminish or adversely affect any right or protection existing at the time of such repeal or amendment or adoption of such inconsistent provision with respect to any act or omission occurring prior to such repeal or amendment or adoption of such inconsistent provision. Our amended and restated certificate of incorporation will also permit us, to the extent and in the manner authorized or permitted by law, to indemnify and to advance expenses to persons other that those specifically covered by our amended and restated certificate of incorporation.

We have entered into indemnification agreements with each of our officers and directors, a form of which is attached to this Registration Statement as Exhibit 10.7. These agreements will require us to indemnify these individuals to the fullest extent permitted under Delaware law against liabilities that may arise by reason of their service to us, and to advance expenses incurred as a result of any proceeding against them as to which they could be indemnified.

Pursuant to the Underwriting Agreement to be filed as Exhibit 1.1 to this Registration Statement, we have agreed to indemnify the underwriters and the underwriters have agreed to indemnify us against certain civil liabilities that may be incurred in connection with this offering, including certain liabilities under the Securities Act.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

 

Item 15.

Recent Sales of Unregistered Securities

Since our formation, we have sold the following securities without registration under the Securities Act:

Founder Shares

In November 2015, our Sponsor purchased an aggregate of 4,312,500 founder shares, for an aggregate offering price of $25,000 at an average purchase price of approximately $0.006 per share. In December 2015, our Sponsor returned to us, at no cost, an aggregate of 575,000 founder shares, which we cancelled. The number of founder shares issued was determined based on the expectation that such founder shares would represent 20.0%

 

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of the outstanding shares upon completion of this offering. Such securities were issued in connection with our organization pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act. Our Sponsor is an accredited investor for purposes of Rule 501 of Regulation D. Our Sponsor is an accredited investor for purposes of Rule 501 of Regulation D.

Simultaneously with the consummation of our initial public offering, we consummated the private placement of 8,310,000 Warrants at a price of $0.75 per Warrant, generating total proceeds of $6,232,500. The Warrants, which were purchased by our Sponsor and EarlyBirdCapital, Inc. (and its designees), are substantially similar to the Public Warrants, except that if held by the original holders or their permitted assigns, they (i) may be exercised for cash or on a cashless basis, (ii) are not subject to being called for redemption and (iii) subject to certain limited exceptions, will be subject to transfer restrictions until 30 days following the consummation of our initial business combination. EarlyBirdCapital, Inc. agreed that it will not be permitted to exercise any Warrants after the five year anniversary of the effective date of the initial public offering registration statement. In addition, the Warrants held by EarlyBirdCapital, Inc. (and its designees), and the shares of common stock underlying such Warrants, are subject to a 180-day lock-up commencing on the effective date of the initial public offering registration statement pursuant to which EarlyBirdCapital, Inc. (and its designees) may not sell, transfer, assign, pledge or hypothecate any Warrants except to an underwriter or selected dealer participating in the offering and the bona fide officers or partners of the underwriter and any such participating underwriter or selected dealer. If the Warrants are held by holders other than its initial holders, the Warrants will be redeemable by us and exercisable by holders on the same basis as the Public Warrants. This issuance was made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

Private Placement Warrants

In connection with our initial public offering, we issued 8,408,838 warrants to purchase our Class A Common Stock (originally sold as part of the units issued in our initial public offering) in a private placement, of which 7,863,150 warrants were sold to our Sponsor and 545,688 warrants were sold to EarlyBirdCapital, Inc., the representative of the underwriters in the initial public offering, and its designees. Each warrant entitles its holder to purchase one share of our Class A Common Stock at an exercise price of $11.50 per share, subject to adjustment as described in the prospectus. The warrants will become exercisable on the later of 30 days after the completion of the Business Combination and 12 months from the closing of the initial public offering, and will expire five years after the completion of the Business Combination or earlier upon redemption or liquidation.

Series A Preferred Stock and Warrant Issuance in Connection with Business Combination

In connection with the Business Combination, we issued in a private placement an aggregate 75,000 shares of Series A Preferred Stock and 5,000,000 warrants to Anchorage Illiquid Opportunities V, L.P. and AIO AIV 3 Holdings, L.P. (together, “Anchorage”), Geode Diversified Fund and The K2 Principal Fund, L.P., and received gross proceeds of $75.0 million, which proceeds were contributed to Rosehill Operating in exchange for Rosehill Operating Series A preferred units and additional Rosehill warrants. The Series A Preferred Stock and the Warrants sold in connection with the Business Combination were issued pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

Class B Common Stock Issuance in Connection with Business Combination

On the closing date of the Business Combination, we issued 29,807,692 shares of Class B Common Stock to Rosehill Operating, which shares of Class B Common Stock were immediately distributed by Rosehill Operating to Tema. The issuance of Class B Common Stock was made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

Side Letter

On the closing date of the Business Combination, the Company sold 2,200 shares of Series A Preferred Stock to our Sponsor and 17,800 shares of Series A Preferred Stock to Rosemore Holdings, Inc., an affiliate of

 

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Rosemore, Inc., pursuant to a side letter entered into among Rosemore, Inc., our Sponsor and the Company. These issuances were made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.    

Rosehill Operating Common Unit Exchange

On the closing date of the Business Combination, we issued to Rosehill Operating 4,000,000 Warrants exercisable for shares of Class A Common Stock in exchange for 4,000,000 Warrants exercisable for Rosehill Operating Common Units. The issuance of the Warrants was made pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

 

Item 16.

Exhibits

See the Exhibit Index, which follows the signature page and which is incorporated by reference herein.

 

Item 17.

Undertakings

The undersigned registrant hereby undertakes:

 

•

To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

 

•

To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933;

 

•

To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

 

•

To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

 

•

That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

•

To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

 

•

That, for purposes of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424 (b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness, provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

 

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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 SEC such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

 

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Index to Financial Statements

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 S-1 and has duly caused this Registration Statement on Form S-1 to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas on May 5, 2017.

 

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints J.A. (Alan) Townsend and Tiffany J. Thom and each of them acting alone, his true and lawful attorneys-in-fact, with full power of substitution and resubstitution for him and in his name, place and stead, in any and all capacities to sign any and all amendments including post-effective amendments to this registration statement, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the SEC, hereby ratifying and confirming all that said attorneys-in-fact or their substitutes, each acting alone, may lawfully do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

 

Name				Position				Date
				President, Chief Executive Officer and
/s/ J.A. (Alan) Townsend				Director				May 5, 2017
J.A. (Alan) Townsend				(Principal Executive Officer)
/s/ T.J. Thom				Interim Chief Financial Officer				May 5, 2017
T.J. Thom				(Principal Financial and Accounting Officer)
/s/ Gary C. Hanna				Chairman				May 5, 2017
Gary C. Hanna
/s/ Edward Kovalik				Director				May 5, 2017
Edward Kovalik
/s/ Frank Rosenberg				Director				May 5, 2017
Frank Rosenberg
/s/ William Mayer				Director				May 5, 2017
William Mayer
/s/ Harry Quarls				Director				May 5, 2017
Harry Quarls
/s/ Francis Contino				Director				May 5, 2017
Francis Contino

 

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Index to Financial Statements

EXHIBIT INDEX

 

Exhibit No.		Description
2.1		Business Combination Agreement, dated as of December 20, 2016, by and between KLR Energy Acquisition Corp. and Tema Oil and Gas Company.(2)
3.1		Second Amended and Restated Certificate of Incorporation of KLRE. (5)
3.2		Certificate of Designation of Series A Preferred Stock of KLRE. (5)
3.3		Amended and Restated Bylaws of Rosehill Resources Inc.(5)
4.1		Specimen Unit Certificate.(3)
4.2		Specimen Class A Common Stock Certificate.(3)
4.3		Specimen Warrant Certificate.(3)
4.4		Warrant agreement, dated March 10, 2016, between the Company and Continental Stock Transfer & Trust Company. (1)
4.5		Shareholders’ and Registration Rights Agreement, dated as of December 20, 2016, by and among Tema Oil and Gas Company, KLR Energy Sponsor, LLC, KLR Energy Acquisition Corp., Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P.(2)
5.1		Legal Opinion of Vinson & Elkins L.L.P. *
10.1		Securities Subscription Agreement, dated November 20, 2015, between the Registrant and KLR Energy Sponsor, LLC.(4)
10.2		Letter Agreement by and between the Company, the initial shareholder, officers and directors of the Company. (1)
10.3		Third Amended and Restated Sponsor Warrants Purchase Agreement between the Company and KLR Energy Sponsor, LLC.(1)
10.4		Amended and Restated Warrants Purchase Agreement between the Company and EarlyBird Capital, Inc.(1)
10.5		Form of Indemnification Agreement. (5)
10.6		Form of Employment Agreement. (5)
10.7		Subscription Agreement, dated as of December 20, 2016, by and between KLR Energy Acquisition Corp. and AIO V AIV 3 Holdings, L.P.(2)
10.8		Subscription Agreement, dated as of December 20, 2016, by and between KLR Energy Acquisition Corp. and Anchorage Illiquid Opportunities V, L.P.(2)
10.9		Subscription Agreement, dated as of December 20, 2016, by and between KLR Energy Acquisition Corp. and Geode Diversified Fund, a segregated account of Geode Capital Master Fund Ltd.(2)
10.10		Subscription Agreement, dated as of December 20, 2016, by and between KLR Energy Acquisition Corp. and The K2 Principal Fund, L.P.(2)
10.11		Side Letter, dated as of December 20, 2016, by and between KLR Energy Acquisition Corp., KLR Energy Sponsor, LLC and Rosemore, Inc.(2)
10.12		Waiver Agreement, dated as of December 20, 2016, by and between KLR Energy Acquisition Corp., and KLR Energy Sponsor, LLC.(2)
10.13		Tax Receivable Agreement, dated as of April 27, 2017, by and between the Company and Tema. (5)

 

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Exhibit No.		Description
10.14		First Amended and Restated Limited Liability Company Agreement of Rosehill Operating dated as of April 27, 2017. (5)
10.15		Rosehill Resources Inc. 2017 Long Term Incentive Plan. (5)
10.16		Crude Oil Gathering Agreement, dated April 27, 2017, by and between Rosehill Operating Company, LLC and Gateway Gathering and Marketing Company. (5)
10.17		Gas Gathering Agreement, dated April 27, 2017, by and between Rosehill Operating Company, LLC and Gateway Gathering and Marketing Company. (5)
10.18		Credit Agreement, dated as of April 27, 2017, among Rosehill Operating Company, LLC, PNC Bank, National Association and PNC Capital Markets LLC. (5)
10.19		Commitment Agreement, dated April 25, 2017, by and among the Company, KLR Energy Sponsor, LLC and The K2 Principal Fund, L.P. (7)
10.20		Registration Rights Agreement, dated March 10, 2016, between the Company and EarlyBirdCapital, Inc. and Chardan Capital Markets, LLC. (1)
12.1		Computation of Ratio of Earnings to Combined Fixed Charges and Preference Dividends.*
14		Financial Code of Ethics. (5)
21.1		Subsidiaries of the Registrant. (5)
23.1		Consent of Independent Registered Public Accounting Firm, BDO USA, LLP. *
23.2		Consent of Ryder Scott Company, LP. *
23.3		Consent of Vinson & Elkins L.L.P. (included as part of Exhibit 5.1).*
24.1		Power of Attorney (included on signature page of this Registration Statement).*
99.1		Ryder Scott Company, LP., Summary of Reserves at December 31, 2016.*

 

*	Filed herewith

(1)	Incorporated by reference to the Company’s Form 8-K, filed with the Commission on March 16, 2016.

(2)	Incorporated by reference to the Company’s Form 8-K, filed with the Commission on December 20, 2016.

(3)	Incorporated by reference to the Company’s Amendment No. 1 to the Registration Statement (File no. 333-209041) on Form S-1/A, filed with the Commission on February 5, 2016.

(4)	Incorporated by reference to the Company’s Registration Statement (File no. 333-209041) on Form S-1, filed with the Commission on January 19, 2016.

(5)	Incorporated by reference to the Company’s Form 8-K, filed with the Commission on May 3, 2017.

(6)	Incorporated by reference to the Company’s Form 8-K, filed with the Commission on April 28, 2017.

 

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