STR Sub Inc. - Quarter Report: 2018 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2018

Or

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

For the transition period from              to             

Commission File Number: 001-38158

FALCON MINERALS CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (215) 832-4161

Osprey Energy Acquisition Corp.

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes  þ    No  ¨

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

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 pursuant to Section 7(a)(2)(B) of the Securities Act. ¨

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

As of November 6, 2018, there were 45,855,000 shares of the Company’s Class A common stock, par value of $0.0001, issued and outstanding and there were 40,000,000 shares of the Company’s Class C common stock, par value of $0.0001, issued and outstanding.

FALCON MINERALS CORPORATION

TABLE OF CONTENTS

GLOSSARY OF TERMS

Adjusted EBITDA:    Represents net income before interest expense, income taxes and depreciation and amortization expense, as further adjusted for other non-cash charges and other charges that are not reflective of our ongoing operations. Adjusted EBITDA is not a presentation made in accordance with GAAP. Please see the reconciliation of Adjusted EBITDA to net income in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Overview of Our Results of Operations—Adjusted EBITDA.”

barrel or bbl:    Stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.

BOE:    Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

BOE/d:  BOE per day.

British Thermal Unit or Btu:    The quantity of heat required to raise the temperature of one pound of water by one-degree Fahrenheit.

Completion: The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Crude oil:   Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

GAAP:    Generally accepted accounting principles in the United States.

Gross acres or gross wells:    The total acres or wells, as the case may be, in which a working interest is owned.

MBOE:    One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mcf:    Thousand cubic feet of natural gas.

MMBtu:    Million British Thermal Units.

NGLs: Natural gas liquids.

Prospect: A specific geographic area which, based on supporting geological, geophysical or other data and preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved Reserves: The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Reserves: The estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reservoir: A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty Interest: An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

SEC:    U.S. Securities and Exchange Commission.

Working Interest:     An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

FALCON MINERALS CORPORATION (formerly known as Osprey Energy Acquisition Corp.)

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

(Unaudited)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

FALCON MINERALS CORPORATION (formerly known as Osprey Energy Acquisition Corp.)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

FALCON MINERALS CORPORATION (formerly known as Osprey Energy Acquisition Corp.)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

FALCON MINERALS CORPORATION (formerly known as Osprey Energy Acquisition Corp.)

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDER’S EQUITY AND PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.

FALCON MINERALS CORPORATION (formerly known as Osprey Energy Acquisition Corp.)

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1—Organization and Presentation

Organization and Description of Business

Falcon Minerals Corporation (the “Company” or “Falcon” and formerly named Osprey Energy Acquisition Corp.) was a blank check company, incorporated in Delaware in June 2016. The Company was formed for the purpose of acquiring, through a merger, capital stock exchange, asset acquisition, stock purchase, reorganization, recapitalization, or other similar business transaction, one or more operating businesses or assets (a “Business Combination”).

On August 23, 2018 (the “Closing Date”), the Company completed the acquisition of the equity interests ( the “Equity Interests”) in certain of the subsidiaries (the “Royal Entities”) of Noble Royalties Acquisition Co., LP, (“NRAC”), Hooks Ranch Holdings LP (“Hooks Holdings”), DGK ORRI Holdings, LP (“DGK”), DGK ORRI GP LLC (“DGK GP”) and Hooks Holding Company GP, LLC (“Hooks GP”, and collectively with NRAC, Hooks Holdings, DGK, and DGK GP, the “Contributors”). The acquisition was made pursuant to the Contribution Agreement, dated as of June 3, 2018 (the “Contribution Agreement”), by and among the Company, Royal Resources L.P. (“Royal”), Royal Resources GP L.L.C. (“Royal GP”) and the Contributors. The acquisition of the Royal Entities pursuant to the Contribution Agreement is referred to in this Form 10-Q as the “Business Combination” and the Business Combination together with the other transactions contemplated by the Contribution Agreement are referred to herein as the “Transactions.”

Pursuant to the Contribution Agreement, on the Closing Date, the Company contributed cash to Falcon Minerals Operating Partnership, LP, a Delaware limited partnership and wholly owned subsidiary of the Company (“Opco”), in exchange for (a) a number of OpCo Common Units representing limited partnership interests in Opco (the “OpCo Common Units”) equal to the number of shares of the Company’s Class A common stock, par value $0.0001 per share (the “Class A Common Stock”), outstanding as of the Closing Date and (b) a number of Opco warrants exercisable for OpCo Common Units equal to the number of the Company’s warrants outstanding as of the Closing Date. The Company controls Opco through Falcon Minerals GP, LLC, a Delaware limited liability company, wholly owned subsidiary of the Company and the sole general partner of Opco (“Opco GP”).

On the Closing Date, Falcon completed the acquisition of the Equity Interests and in return the Contributors received (i) $400 million of cash and (ii) 40 million units OpCo Common Units. The Company also issued to the Contributors 40 million shares of non-economic Class C common stock of the Company, which entitles each holder to one vote per share. The OpCo Common Units are redeemable on a one-for-one basis for shares of Class A Common Stock at the option of the Contributors. Upon the redemption by any Contributor of OpCo Common Units for Class A Common Stock, a corresponding number of shares of Class C Common Stock held by such Contributor will be cancelled.  

In connection with the closing of the Business Combination (the “Closing”), the Company changed its name from “Osprey Energy Acquisition Corp.” to “Falcon Minerals Corporation”. The Company is now structured as an “Up-C,” meaning that substantially all the assets of the Company are held by Opco, and the Company’s only operating asset is its equity interest in Opco. Each OpCo Common Unit, together with one share of Class C Common Stock, is exchangeable for one share of Class A Common Stock at the option of the holder pursuant to the terms of the Company’s and Opco’s organizational documents, subject to certain restrictions.

The Company’s assets, via its controlling interest in OpCo, consist of royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests, or ORRIs, (“Royalties) underlying approximately 250,000 gross unit acres that are concentrated in what the Company believes is the “core-of-the-core” of liquids-rich condensate region of the Eagle Ford Share in Karnes, DeWitt and Gonzales Counties, Texas. The company owns additional assets of approximately 58,000 gross acres in Pennsylvania, Ohio and West Virginia that is prospective for Marcellus Shale.

These royalties entitle the holder to a portion of the production of oil and natural gas from the underlying acreage at the sales price received by the operator, net of any applicable post-production expenses and taxes. The holder of these interests has no obligation to fund exploration and development costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life.

Note 2—Summary of Significant Accounting Policies

Basis of Presentation

The acquisition of the Royal Entities has been accounted for as a reverse recapitalization in accordance with GAAP. Under this method of accounting, Falcon will be treated as the acquired company and Royal will be treated as the acquirer for financial reporting purposes. Therefore, the consolidated financial results include information regarding Royal as the Company’s predecessor entity, which includes certain interests in subsidiary companies which were not acquired by the Company in the Transactions. Thus, the financial statements included in this report reflect (i) the historical operating results of Royal prior to the Transactions: (ii) the combined results of the Company, OpCo and Royal following the Transactions; (iii) the assets, liabilities and partners’ capital of Royal at their historical costs; and (iv) the Company’s equity and earnings per share presented for the period from the Closing Date of the Business Combination. The Royal subsidiaries that were contributed in the Transaction are VickiCristina, LP, DGK ORRI Company, L.P., Noble EF DLG LP, Noble EF LP and Noble Marcellus LP. The interests in Riverbend Natural Resources, L.P (‘RNR”) and KGD ORRI, L.P. were not contributed in the Transactions (the “Non-Contributed Entities”). The RNR interests that were not contributed in the Transactions are classified as held for sale and are presented separately in the December 31, 2017 consolidated balance sheet of the Company. In addition, the amounts attributed to RNR interests related to the Transaction are included in discontinued operations in the consolidated statements of operations.

The accompanying interim statements of the Company have been prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X issued by the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments, consisting only of normal recurring adjustments and disclosures necessary for a fair statement of these interim statements have been included. The results reported in these interim statements are not necessarily indicative of the results that may be reported for the entire year or for any other period. These interim statements should be read in conjunction with Royal’s audited financial statements for the year ended December 31, 2017 included in the proxy statement of the Company filed with the SEC on August 3, 2018 (the “Proxy Statement”) and incorporated by reference in the Current Report on Form 8-K filed with the SEC on August 29, 2018.

Use of Estimates

The preparation of unaudited condensed consolidated financial statements in conformity with 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 natural gas liquids (“NGLs”) 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, related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, fair value of the Company’s warrants, estimates of current and deferred income taxes, and deferred income tax valuation allowances. While management believes these estimates are reasonable, changes in facts and assumptions or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and it is reasonably possible these estimates could be revised in the near term, and these revisions could be material.

Royalty Interests in Oil and Natural Gas Properties 

The Company follows the successful efforts method of accounting for oil and natural gas operations. Under this method, costs to acquire mineral and royalty interests in oil and natural gas properties are capitalized when incurred. Acquisitions of royalty interests of oil and natural gas properties are considered asset acquisitions and are recorded at cost.

Acquisition costs of proven royalty interests are amortized using the units of production method over the life of the property, which is estimated using proven reserves. Acquisition costs of royalty interests on exploration stage properties, where there are no proven reserves, are not amortized. When the associated exploration stage interests are converted to proven reserves, the cost basis is amortized using the units of production methodology over the life of the property, using proven reserves. For purposes of amortization, interests in oil and natural gas properties are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic condition.

Fair Value of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value measurements are derived using inputs and assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. GAAP establishes a valuation hierarchy for disclosure of the inputs used to measure fair value. This three-tier hierarchy classifies fair value amounts recognized or disclosed in the condensed consolidated financial statements based on the observability of inputs used to estimate such fair values. The classification within the hierarchy of an asset or liability is determined based on the lowest level input that is significant to the fair value measurement. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). At each balance sheet reporting date, the Company categorizes its assets and liabilities recorded at fair value using this hierarchy.

The amounts reported in the balance sheet for cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their fair value because of the short-term maturities of these instruments (Level 1). Because the Credit Facility (as defined in “Note 5 – Debt – Falcon Credit Facility” below) has a market rate of interest, its carrying amount approximated fair value (Level 2).

Revenue Recognition

The Company’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Company owns a royalty interest sells the Company’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Company collects its percentage royalty based upon the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the wellhead or at the gas processing facility based on the Company’s percentage ownership share of the revenue.

The Company uses the entitlement method of accounting for revenues. Under this method, revenues are recognized based on actual production. However, settlement statements for certain oil, natural gas and natural gas liquids sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of royalty income to be received based upon the Company’s interest. The Company records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. To the extent actual volumes and prices of oil and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to the expected sales volume and prices for those properties are estimated and recorded.

Income Taxes

The Company under ASC 740 uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense. No amounts were accrued for the payment of interest and penalties at September 30, 2018. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material deviation from its position. The Company is subject to income tax examinations by major taxing authorities since inception.

Royal was historically treated as a partnership for federal income tax purposes, with each partner being separately taxed on its share of taxable income; therefore, there is no federal income tax expense reflected in Royal’s financial statements.

Derivative Financial Instruments

Royal used derivative financial instruments to reduce exposure to fluctuations in commodity prices. The transactions were in the form of crude swaps. Royal’s derivative instruments were not designated as cash flow hedges for accounting purposes for any of periods presented. Accordingly, the changes in fair value are recognized in the consolidated statements of operations in the period of change. Gains and losses from derivatives are included in the cash flows from operating activities. Royal’s derivative financial instruments were extinguished in connection with the Transaction.

Segment Reporting

The Company derives revenue from royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests, or ORRIs, (“Royalties”) in oil and natural gas properties in North America. The Company operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker (“CODM”) in deciding how to allocate resources and assess performance. The Company’s chief executive officer has been determined to be the CODM and allocates resources and assesses performance based upon financial information at the consolidated level.

Recently Issued Accounting Pronouncements

In May 2014, the FASB issued updated guidance on the reporting and disclosure of revenue recognition. The update requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update also requires new qualitative and quantitative disclosures about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts, including significant judgments and changes in judgments, information about contract balances and performance obligations, and assets recognized from costs incurred to obtain or fulfill a contract. In April 2015, the FASB proposed a one-year deferral of the effective date, and therefore, this guidance will be effective for the Company beginning in the first quarter of 2019, with early adoption optional but not before the original effective date of December 15, 2016. In May and December 2016, the FASB issued certain narrow-scope improvements and practical expedients to the guidance. The Company plans to adopt this effective January 1, 2019 using the modified retrospective method. To date, the Company has not identified changes to its revenue recognition policies that would result in a material adjustment to the opening balance of shareholder’s equity on January 1, 2019; however, it is continuing to evaluate the effect, if any, adopting this guidance will have on its financial position, results of operations, cash flows and related disclosures. Adopting this guidance will result in increased disclosures related to revenue recognition policies and disaggregation of revenue.

In February 2016, the FASB issued new guidance which amends various aspects of existing guidance for leases. The new guidance requires an entity to recognize assets and liabilities arising from a lease for both financing and operating leases, along with additional qualitative and quantitative disclosures. The main difference between previous GAAP and the new standard is the recognition of lease assets and lease liabilities by lessees on the balance sheet for those leases classified as operating leases under previous GAAP. As a result, the Company will have to recognize a liability representing its lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term on the balance sheet. The new guidance is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company is currently evaluating the effect this standard will have on its consolidated financial position or results of operations.

In August 2016, the FASB issued new guidance which makes eight targeted changes to how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update provides specific guidance on cash flow classification issues that are not currently addressed by GAAP and thereby reduces the current diversity in practice. The standard is effective for the Company’s financial statements issued for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years. Early adoption is permitted. The Company does not expect this requirement to have a significant impact on its financial condition, results of operations, cash flows and related disclosures.

In January 2017, the FASB issued new guidance which provides clarifications to evaluating when a set of transferred assets and activities (collectively, the “set”) is a business and provides a screen to determine when a set is not a business. Under the new guidance, when substantially all of the fair value of gross assets acquired (or disposed of) is concentrated in a single identifiable asset, or group of similar assets, the assets acquired would not represent a business. Also, to be considered a business, an acquisition would have to include an input and a substantive process that together significantly contribute to the ability to produce outputs. The new standard is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, and should be applied on a prospective basis to any transactions occurring within the period of adoption. Early adoption is permitted for interim or annual periods in which the financial statements have not been issued. The Company does not expect this requirement to have a significant impact on its financial condition, results of operations, cash flows and related disclosures.

Note 3 – Transaction

On the Closing Date, Falcon completed the acquisition of the equity interests in the Royal Entities and in return the Contributors received (i) $400 million of cash and (ii) 40 million units Op Co Common Units. The Company also issued to the Contributors 40 million shares of non-economic Class C common stock of the Company, which entitles each holder to one vote per share. The OpCo Common Units are redeemable on a one-for-one basis for shares of Class A Common Stock at the option of the Contributors. Upon the redemption by any Contributor of OpCo Common Units for Class A Common Stock, a corresponding number of shares of Class C Common Stock held by such Contributor will be cancelled.

In addition to the above, pursuant to the Contribution Agreement, Royal is entitled to receive earn-out consideration to be paid in the form of OpCo Common Units (and a corresponding number of shares of Class C Common Stock) if the 30-day volume-weighted average price (“30-Day VWAP”) of the Class A Common Stock equals or exceeds certain hurdles set forth in the Contribution Agreement. Royal can potentially receive up to an additional 20.0 million OpCo Common Units as a part of the earn-out consideration. As of the September 30, 2018, none of these hurdles have been met. Royal is also entitled to the earn-out consideration described above in connection with certain liquidity events of the Company, including a merger or sale of all or substantially all of the Company’s assets, if the consideration paid to holders of the Class A Common Stock in connection with such liquidity event is greater than any of the 30-Day VWAP hurdles.

In connection with the Company’s entry into the Contribution Agreement, the Company agreed to issue and sell in a private placement an aggregate of 11,480,000 shares of Class A Common Stock for a purchase price of $10.00 per share, and aggregate consideration of $114.8 million (the “Private Placement”). The Private Placement was consummated concurrently with the Closing Date and the proceeds of the Private Placement were used to fund a portion of the cash consideration paid to the Contributors.

Because Royal has effective control of the combined company after the Transaction through its majority voting interests in both the Company and, accordingly, Opco, this Transaction was accounted for as a reverse recapitalization. Although the Company was the legal acquirer, Royal was the accounting acquirer. As a result, the reports filed by the Company subsequent to the Transaction are prepared “as if” Royal is the predecessor and legal successor to the Company. The historical operations of Royal are deemed to be those of the Company. Thus, the financial statements included in this report reflect (i) the historical operating results of Royal prior to the Transaction; (ii) the combined results of the Company, OpCo and Royal following the Transaction; (iii) the assets, liabilities and partners’ capital of Royal at their historical cost; and (iv) the Company’s equity and earnings per share for the period from the Closing Date of the Business Combination.

The RNR assets, liabilities and operations are considered discontinued operations prior to the Closing Date of the Transactions. Below is a reconciliation of the carrying amounts of the major classes of assets and liabilities of the discontinued operations that are classified as held for sale and are presented separately in the December 31, 2017 consolidated balance sheet of the Company (in thousands):

Below are amounts attributed to the disposition of the RNR interests included in discontinued operations in the consolidated statements of operations (in thousands):

Below are the amounts attributed to the disposition of the RNR interests included in the consolidated cash flow statements (in thousands):

Note 4—Oil and Natural Gas Interests

Oil and natural gas interest include the following (in thousands):

In February 2018, Royal completed the sale of its interests in a portion of its oil and natural gas properties to an unaffiliated third part for cash proceeds of $121.0 million. The sale resulted in a realized gain of $41.3 million.

Note 5—Debt

Royal Credit Facilities

Royal’s historical primary sources of indebtedness are its first lien credit facility, which it entered into in October 2012, and Royal Natural Resources, LP (“RNR”) credit facility:

The availability under each facility was subject to Royal’s compliance with certain customary contractual financial and non-financial covenants and non-financial covenants and each facility was secured by Royal’s assets.

Falcon Credit Facility

On the Closing Date, we entered into a credit facility with Citibank, N.A., as administrative agent and collateral agent for the lenders from time to time party thereto (the “Credit Facility”). The Credit Facility initially provides for aggregate revolving borrowings of up to $500.0 million with an initial $115.0 million borrowing base and expires on the fifth anniversary of the Closing Date. On the Closing Date, $38.0 million was drawn under the Credit Agreement to fund a portion of the purchase price of the Business Combination, to pay transaction expenses, to fund any original issue discount or upfront fees in connection with the “market flex” provisions previously agreed upon and to finance working capital needs and other general corporate purposes. As of September 30, 2018, the Company had borrowings of $38.0 million under the Credit Facility at an interest rate of 4.62%. The Company incurred $3.2 million in connection with the closing of the Credit Facility. These amounts have been recorded as a deferred asset and will be amortized over the term of the credit facility.

 Principal amounts borrowed are payable on the maturity date. We have a choice of borrowing at the base rate or LIBOR, with such borrowings bearing interest, payable quarterly in arrears for base rate loans and one month, two-month, three month or six-month periods for LIBOR loans. LIBOR loans bear interest at a rate per annum equal to the rate appearing on the Reuters Reference LIBOR01 or LIBOR02 page as the LIBOR, for deposits in dollars at 12:00 noon (London, England time) for one, two, three, or six months plus an applicable margin ranging from 200 to 300 basis points. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one-month LIBOR loans plus 1%, plus an applicable margin ranging from 100 to 200 basis points. The next scheduled redetermination of our borrowing base is on April 1, 2019. Based upon the current borrowing base, the Company has $77.0 million of available capacity under the Credit Facility.

 Obligations under the Credit Facility are guaranteed by us and each of our existing and future, direct and indirect domestic subsidiaries (the “Credit Parties”) and are secured by all the present and future assets of the Credit Parties, subject to customary carve-outs.

The Credit Facility contains certain customary representations and warranties, affirmative covenants, negative covenants and events of default. As of September 30, 2018, the Company was in compliance with such covenants. The negative covenants include restrictions on the Company’s ability to incur additional indebtedness, acquire and sell assets, create liens, enter into certain lease agreements, make investments and make distributions.

Note 6—Shareholder’s Equity and Dividends

Shares Outstanding

Prior to the Transaction, Falcon was a shell company with no operations, formed as a vehicle to affect a business combination with one or more operating businesses. After the Closing of the Transaction, the Company became a holding company whose sole material operating asset consists of its interest in Royal through its interest in Opco. The following table summarizes the changes in the outstanding stock and warrants through September 30, 2018.

Preferred stock - At September 30, 2018 and December 31, 2017, there were no shares of preferred stock issued or outstanding. The Company is authorized to issue 1,000,000 shares of preferred stock with a par value of $0.0001 per share with such designation, rights and preferences as may be determined from time to time by the Company’s Board of Directors.

Class A Common Stock - At September 30, 2018 and December 31, 2017, there were 45,855,000 and 1,359,246 shares of Class A Common Stock issued and outstanding (excluding 0 and 26,140,754 shares of common stock subject to possible redemption), respectively. Holders of the Company’s Class A Common Stock are entitled to one vote for each share. The Company is authorized to issue 240,000,000 shares of Class A Common Stock with a par value of $0.0001 per share.

Class B Common Stock - At September 30, 2018 and December 31, 2017, there were 0 and 6,875,000 shares of Class B Common Stock issued and outstanding, respectively. The shares of Class B Common Stock automatically converted into shares of Class A Common Stock at the time of the Transaction on a one-for-one basis. The Company is authorized to issue 0 shares of Class B Common Stock with a par value of $0.0001 per share. Holders of the Company’s Class B Common Stock are entitled to one vote for each share.

Class C Common Stock – At September 30, 2018 and December 31, 2017, there were 40,000,000 and 0 shares of Class C Common Stock issued and outstanding, respectively. Class C common stock was issued to the Contributors in connection with the Transaction and are non-economic but entitled the holder to one vote per share. The Company is authorized to issue 120,000,000 shares of Class C Common Stock with a par value of $0.0001 per share.

Warrants – At September 30, 2018 and December 31, 2017, there were 21,250,000 outstanding during each period. Each warrant entitles the holder to purchase one share of Class A Common Stock at an exercise price of $11.50 per share, subject to adjustment pursuant to the terms of the warrant agreement. The warrants become exercisable on the later of (a) 30 days after the completion of a business combination or (b) 12 months from the closing of the Initial Public Offering; provided in each case that the Company has an effective registration statement under the Securities Act covering the shares of common stock issuable upon of the warrants and a current prospectus relating to them is available. The exercise price and number of shares of Class A common stock issuable upon exercise of the warrants may be adjusted in certain circumstances including in the event of a stock dividend, or recapitalization, reorganization, merger or consolidation. The warrants expire five years from August 23, 2018, the date upon with the Transaction was closed, or earlier upon redemption or liquidation.

In connection with the Transaction, the Company issued 40,000,000 OpCo Common Units to the Contributors. The OpCo Common Units are redeemable on a one-for-one basis for shares of Class A Common Stock at the option of the holder. Upon the redemption by any Contributor of OpCo Common Units for shares of Class A Common Stock, a corresponding number of shares of Class C Common Stock held by such Contributor will be cancelled.

In addition to the above, the Contributors will be entitled to receive earn-out consideration to be paid in the form of OpCo Common Units (with a corresponding number of shares of Class C common stock) if the volume-weighted average price of the trading days during any thirty (30) calendar days (the “30-Day VWAP”) of the Class A common stock equals or exceeds certain hurdles set forth in the Contribution Agreement. If the 30-Day VWAP of the Class A common stock is $12.50 or more per share at any time within the seven years following the closing, Royal LP will receive (i) an additional 10 million Op Co Common Units (and an equivalent number of shares of Class C common stock), plus (ii) an amount of OpCo Common Units (and an equivalent number of shares of Class C common stock) equal to (x) the amount by which annual cash dividends paid on each share of Class A common stock exceeds $0.50 in each year between the closing and the date the first earn-out is achieved (with any dividends paid in the stub year in which the first earn-out is achieved annualized for purposes of determining what portion of such dividends would have, on an annual basis, exceeded $0.50), multiplied by 10 million, (y) divided by $12.50. If the 30-Day VWAP of the Class A common stock is $15.00 or more per share at any time within the seven years following the closing (which $15.00 threshold will be reduced by the amount by which annual cash dividends paid on each share of Class A common stock exceeds $0.50 in each year between the closing and the date the earn-out is achieved, but not below $12.50), the Contributors will receive an additional 10 million OpCo Common Units (and an equivalent number of Class C common stock).

Noncontrolling Interest

The Company’s non-controlling ownership interest in consolidated subsidiaries are presented in the consolidated balance sheet within shareholder’s equity as a separate component. In addition, consolidated net income includes earnings attributable to both the shareholders and the non-controlling interests. For the nine months ended September 30, 2018 and 2017, less than $0.1 million of distributions for each period have been made to non-controlling interest holders of the consolidated subsidiaries.

Long-Term Incentive Plan

In connection with the Closing, the Falcon Board of Directors adopted the Falcon Minerals Corporation 2018 Long-Term Incentive Plan (the “Plan”). An aggregate of 8.6 million shares of Class A Common Stock are available for issuance under the Plan. As of September 30, 2018, no grants have been made under the Plan.

Cash Dividends

The table below summarizes the quarterly dividends related to the Company’s quarterly financial results (in thousands, except per unit data):

(1)        Initial pro rata dividend, prorated for the period from August 23, 2018 to September 30, 2018.

Note 7—Earnings Per Share

The Transaction was structured as a reverse capitalization by which the Company issued stock for the net assets of Royal accompanied by a recapitalization. Earnings per share is calculated for the Company only for periods after the Transaction due to the reverse recapitalization.

Diluted net income per share includes the effects of potentially dilutive shares of the Class C Common Stock. Diluted net income per share excludes the effects of warrants to purchase 21,250,000 shares of common stock because there are no assurances that the stock price will exceed the exercise price.

The following table sets forth the calculation of basic and diluted earnings per share for the periods indicated (in thousands, except per share data):

Note 8—Income Taxes

The Company uses an estimated annual effective tax rate, which is based on expected annual income, statutory tax rates and tax planning opportunities available in the various jurisdictions in which the Company operates, to determine its quarterly provision for income taxes. Certain significant or unusual items are separately recognized in the quarter in which they occur and can be a source of variability in the effective tax rates from quarter to quarter.

As of September 30, 2018, the Company recorded an income tax expense of $810,231 and $0 for the three months ended September 30, 2018 and 2017, and income tax expense of $810,231 and $0 for the nine months ended September 30, 2018 and 2017, respectively. Royal was historically treated as a partnership for federal income tax purposes, with each partner being separately taxed on its share of taxable income; therefore, there is no federal income tax expense reflected in Royal’s financial statements for the three and nine months ending September 30, 2017 or any period prior to the business combination on August 23, 2018.

As of September 30, 2018, the Company had $60.6 million of net deferred tax assets net of valuation allowances. Deferred tax assets of $61.1M net of valuation allowances were recorded as of the August 23, 2018 transaction date. These net deferred tax assets relate to oil & gas assets and other temporary items where the tax basis differs from the GAAP carrying amounts.

At September 30, 2018 and December 31, 2017, the Company had recorded a prepayment of income taxes of $355,983 and $0 respectively.

The Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense. No amounts were accrued for the payment of interest and penalties at September 30, 2018. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material deviation from its position. The Company is subject to income tax examinations by major taxing authorities since inception.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”). The Tax Act makes broad and complex changes to the U.S. tax code that will affect our calendar year tax filings for the period ending December 31, 2018, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35 percent to 21 percent; (2) eliminating the corporate alternative minimum tax (AMT) and changing how existing AMT credits can be realized; (3) creating a new limitation on deductible interest expense; and (4) changing rules related to uses and limitations of NOL carryforwards created in tax years beginning after December 31, 2017. The impact of the Tax Act on the Company’s financial statements are recorded in the amounts reported in our income tax provision.

Note 9—Related Party Transactions

Founder Shares

In June 2016, the Company issued an aggregate of 125,000 shares of Class B Common Stock to Osprey Sponsor, LLC (the “Sponsor”) for an aggregate purchase price of $25,000 (the “Founder Shares”). In March 2017, the Company effectuated a 57.5-for-1 stock split resulting in an aggregate of 7,187,500 Founders Shares outstanding and held by the Sponsor. The Founder Shares automatically converted into Class A Common Stock upon the consummation of the Transaction on a one-for-one basis. Due to the underwriter’s election not to exercise the remaining portion of the over-allotment option related to the Initial Public Offering, 312,500 Founder Shares were forfeited resulting in an aggregate of 6,875,000 Founders Shares held by the Sponsor prior to the Transaction.

Promissory Note

Prior to the closing of the Initial Public Offering, the Sponsor loaned the Company a total of $0.2 million under a promissory note (the “Promissory Note”) to be used for the payment of costs related to the Initial Public Offering. The Promissory Note was non-interest bearing, unsecured and due on the earlier of December 31, 2017 or the closing of the Initial Public Offering. The Promissory Note was repaid upon the consummation of the Initial Public Offering.

Atlas Energy Group, LLC

Atlas Energy Group, LLC, which Company officers and directors Edward Cohen, Jonathan Cohen and Daniel Herz are also directors and officers of, and its affiliates provide the Company with advisory services in connection with potential business opportunities and prospective targets. For the nine months ended September 30, 2018 and 2017, the Company paid less than $0.1 million and $0 in expenses in connection with such services. In October 2018, Daniel Herz resigned from any and all director and officer positions within Atlas Energy Group, LLC and its affiliates.

Hepco Capital Management, LLC

Hepco Capital Management, LLC (“Hepco Capital”), which Company officers and directors Edward Cohen, Jonathan Cohen and Jeffrey Brotman are also directors and officers of, and its affiliates share certain employees and office space and reimburses the Company for a proportionate amount of the shared expenses on a monthly basis. For the nine months ended September 30, 2018 and 2017, the Company incurred less than $0.1 million and $0 million, respectively.

Note 10—Major Operators

The following table presents the percentage of revenues with the Company’s significant operators (those that have accounted for 10% or more of the Company’s revenues in a given period) for the periods indicated:

Note 11—Commitments and Contingencies

The Company could be subject to various possible loss contingencies which arise primarily from interpretation of federal and state laws and regulations affecting the natural gas and crude oil industry. Such contingencies include differing interpretations as to the prices at which natural gas and crude oil sales may be made, the prices at which royalty owners may be paid for production from their leases, environmental issues and other matters. Management believes it has complied with the various laws and regulations, administrative rulings and interpretations.

Commitments and Contractual Obligations

Future non-cancelable commitments related to certain contractual obligations as of September 30, 2018 are presented below (in thousands):

Note 12—Subsequent Events

Cash Dividends

In October 2018, the Company declared a partial quarterly cash dividend of $0.095 per share of Class A common stock totaling approximately $4.4 million for all shares Class A common stock outstanding. The dividend is for the period from August 23, 2018 through September 30, 2018. The dividend is payable on November 15, 2018 to all Class A shareholders of record on November 8, 2018.

OpCo Distribution

In November 2018, OpCo made distributions totaling $8.8 million to its unitholders. Of the $8.8 million distributed by OpCo, the Company received $4.7 million.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of present or historical fact, included in this prospectus regarding our strategy, future operations, financial position, estimated revenues, and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “should,” “will,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” the negative of such terms and other similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. 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. We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil, natural gas and natural gas liquids. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

For additional information regarding known material factors that could affect our operating results and performance, please read the section entitled “Risk Factors” in our proxy statement filed with the SEC on August 3, 2018, as well as all risk factors described in the documents incorporated by reference herein. Should one or more of the risks or uncertainties described in or incorporated into this report occur, or should underlying assumptions prove incorrect, actual results and plans could different materially from those expressed in any forward-looking statements.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and natural gas liquids (“NGLs”) that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and the price and cost assumptions made by reserve engineers. In addition, the results of drilling, completion and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless otherwise noted, references to “we,” “us,” “our” and the “Company” refer to Royal and its consolidated subsidiaries, which is our accounting predecessor for financial reporting purposes. Royal includes VickiCristina, L.P., a Delaware limited partnership, DGK ORRI Company, L.P a Delaware limited partnership, Noble EF DLG LP, a Texas limited partnership, Noble EF DLG GP LLC, a Texas limited liability company, Noble EF LP, a Texas limited partnership, Noble EF GP LLC, a Texas limited liability company, Noble Marcellus LP, a Delaware limited partnership, and Noble Marcellus GP, LLC, a Delaware limited liability company as the contributed entities.

You should read the following discussion of our historical performance, financial condition and future prospects in conjunction with “Selected Historical Financial Information of Royal,” “Unaudited Pro Forma Condensed Consolidated Combined Financial Information” and the accompanying financial statements and related notes incorporated by reference to the Proxy Statement or included in the Current Report on Form 8-K filed with the SEC on August 29, 2018. The information provided below supplements, but does not form part of, our financial statements. This discussion contains forward-looking statements that are based on the views and beliefs of Royal’s management, as well as assumptions and estimates made by our management. Actual results could differ materially from such forward-looking statements as a result of various risk factors, including those that may not be in the control of management. For further information on items that could impact our future operating performance or financial condition, see the section entitled “Risk Factors” beginning on page 40 of the definitive proxy statement filed with the SEC on August 3, 2018 (the “Proxy Statement”).

Overview

On August 23, 2018, we consummated the previously announced business combination pursuant to that certain Contribution Agreement, dated as of June 3, 2018 (the “Contribution Agreement”), by and among Royal Resources L.P. (“Royal LP”), Royal Resources GP L.L.C. (“Royal GP” and collectively with Royal LP, “Royal”), Noble Royalties Acquisition Co., LP (“NRAC”), Hooks Ranch Holdings LP (“Hooks Holdings”), DGK ORRI Holdings, LP (“DGK”), DGK ORRI GP LLC (“DGK GP”), Hooks Holding Company GP, LLC (“Hooks GP,” and collectively with NRAC, Hooks Holdings, DGK, and DGK GP, the “Contributors”), and Osprey, pursuant to which Osprey acquired from the Contributors all of their equity interests in certain of their subsidiaries named in the Contribution Agreement. Upon closing we changed our name from “Osprey Energy Acquisition Corp.” to “Falcon Minerals Corporation” (“Falcon”).

We were formed to own and acquire royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests, or ORRIs, (“Royalties”) in oil and natural gas properties in North America, substantially all of which are located in the Eagle Ford Shale. These Royalties entitle the holder to a portion of the production of oil and natural gas from the underlying acreage at the sales price received by the operator, net of any applicable post-production expenses and taxes. The holder of these interests has no obligation to fund exploration and development costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life, which we believe results in low breakeven costs.

Sources of Our Revenue

Our revenues were derived from royalty payments we received from our operators based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. As of September 30, 2018, our Royalties represented the right to receive an average of 1.38% from the producing wells on the underlying acreage at the sales price received by our operators net of any applicable post-production expenses and taxes. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile, and at December 31, 2017, and September 30, 2018, we did not hedge any of our exposure to changes in commodity prices. During the twelve months ended December 31, 2017, West Texas Intermediate posted prices that ranged from $42.53 to $60.42 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On September 30, 2018, the West Texas Intermediate posted price for crude oil was $73.16 per Bbl and the Henry Hub spot market price of natural gas was $3.00 per MMBtu. 

The following table presents the breakdown of our revenue for the following periods:

Commodity prices are inherently volatile, and changes in such prices have historically had an impact on our revenue. The following table sets forth the average realized prices for oil, natural gas and natural gas liquids for the three months ended September 30, 2018, nine months ended September 30, 2018, three months ended September 30, 2017, nine months ended September 30, 2017 and for the years ended December 31, 2017, 2016 and 2015:

Principal Components of Our Cost Structure

Production and Ad Valorem Taxes 

The operators of the properties underlying our Royalties have historically allocated a portion of their production taxes to us based on the volumes of production attributable to our Royalties. Production taxes are paid at fixed rates on produced oil and natural gas based on a percentage of revenues from products sold, established by federal, state or local taxing authorities. Where available, we have historically benefited from tax credits and exemptions in our various taxing jurisdictions. We also directly paid ad valorem taxes in the counties where our production was located. Ad valorem taxes were generally based on the state government’s appraisal of our oil and natural gas properties. 

Marketing and Transportation

The operators of the properties underlying our Royalties have historically allocated a portion of their post-production costs, if contractually allowed under the Royalty agreement, to us based on the volumes of production attributable to our Royalties. These are costs incurred to bring natural gas, natural gas liquids, and oil to the market. Such costs include our operators’ costs to operate and maintain low- and high-pressure gathering and compression systems as well as fees paid to third parties who operate low- and high-pressure gathering systems that transported our gas. They also include costs to process and extract natural gas liquids from our produced gas and to transport our natural gas liquids and oil to market. 

Amortization

Our Royalties are recorded at cost and capitalized as tangible assets. Acquisition costs related to proved properties are amortized on a units of production basis over the life of the proved reserves.

General and Administrative

These are costs incurred for overhead, including the allocation of a portion of the historical cost of management, operating and administrative services provided under a master services agreement (the “MSA”) between Royal and Riverbend Oil & Gas, L.L.C. (“Riverbend”), which owned a portion of Royal through an affiliate and whose employees historically managed Royal’s predecessor and Royal, audit and other fees for professional services and legal compliance. On the Closing Date, Royal assigned to the Company its rights and responsibilities under the existing MSA. Riverbend will perform substantially the same services to the Company as those Riverbend performed for Royal prior to the Closing Date for the duration of the term of the MSA, which is set to expire on December 10, 2018. The Company anticipates that the day-to-day management of the Company will have transitioned to the Company’s Employees as of such date.

Interest Expense

Borrowings under Royal’s first lien credit facility and RNR credit facility have historically served to fund distributions to its equity owners. As a result, Royal incurred substantial interest expense that was affected by both fluctuations in interest rates and Royal’s financing decisions. These facilities will not be our obligations after closing, however we are now party to a new revolving credit facility. Please read “—Liquidity and Capital Resources—Indebtedness.”

Income Tax Expense

Income taxes reflect the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying current tax rates to the differences between financial statement and income tax reporting. In assessing the realization of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. We will continue to evaluate whether the valuation allowance is needed in future reporting periods. We are subject to taxation in many jurisdictions, and the calculation of our income tax liabilities involves dealing with uncertainties in the application of complex income tax laws and regulations in various taxing jurisdictions. We recognize certain income tax positions that meet a more-likely-than not recognition threshold. If we ultimately determine that the payment of these liabilities will be unnecessary, we will reverse the liability and recognize an income tax benefit during the period in which we determine the liability no longer applies.

Royal was historically treated as a partnership for federal income tax purposes, with each partner being separately taxed on its share of taxable income; therefore, there is no federal income tax expense reflected in Royal’s financial statements for the three and nine months ending September 30, 2017 or any period prior to the business combination on August 23, 2018.

Overview of Our Results of Operations

Basis of Presentation

The following financial statements include information regarding Royal Resources L.P. as Falcon’s predecessor entity, which includes certain interests in subsidiary companies which were not acquired by Osprey in the Transactions. The Royal Resources L.P. subsidiaries that were contributed in the Transaction are VickiCristina, LP, DGK ORRI Company, L.P., Noble EF DLG LP, Noble EF LP and Noble Marcellus LP. The interests in Riverbend Natural Resources, L.P (“RNR”) and KGD ORRI, L.P. were not contributed in the Transactions. Thus, the financial results included in this report reflect (i) the historical operating results of Royal prior to the Transactions: (ii) the combined results of the Company, OpCo and Royal following the Transactions; (iii) the assets, liabilities and partners’ capital of Royal at their historical costs; (iv) RNR’s financial results for all periods presented have been reclassified to discontinued operations; and (iv) the Company’s equity and earnings per share presented for all periods following the Transactions. For additional information, please see the historical audited financial statements in the Proxy Statement as well as the pro forma financial information included in the section entitled “Unaudited Pro Forma Condensed Consolidated Combined Financial Information” included in the Current Report on Form 8-K filed with the SEC on August 29, 2018 in Exhibit 99.6.

The following table summarizes our revenue and expenses and production data for the periods indicated (in thousands, except production data).

Comparison of the three months ended September 30, 2018 to the three months ended September 30, 2017:

Oil and Gas Revenues

Oil and gas revenues increased $4.7 million, or 24%, to $23.8 million for the three months ended September 30, 2018, from $19.1 million for the three months ended September 30, 2017. The increase in oil and gas revenues was attributable to a net increase in realized commodity prices offset by a decrease in oil, natural gas liquids and natural gas production caused by the sale of a proportion of our interests in certain oil and natural gas properties in January 2018.

Production and Ad Valorem Taxes

Production and ad valorem taxes increased $0.2 million, or 16%, to $1.3 million for the three months ended September 30, 2018, from $1.2 million for the three months ended September 30, 2017. The increase in production and ad valorem taxes was attributable to the increase in oil and gas revenues.

Marketing and Transportation Expense

Marketing and transportation expense decreased $0.9 million, or 64%, to $0.5 million for the three months ended September 30, 2018, from $1.4 million for the three months ended September 30, 2017. The decrease in marketing and transportation expense was attributable to a net change in the production from leases that are burdened by marketing and transportation costs to leases that are not burdened by marketing and transportation costs. This change was caused by a sale of a portion of our interests in certain oil and natural gas properties in January 2018 and new production from existing properties.

Amortization of Royalty and Working Interests in Oil and Natural Gas Properties Expense

Amortization of royalty and working interests in oil and natural gas properties expense decreased $3.3 million, or 37%, to $4.5 million for the three months ended September 30, 2018, from $7.8 million for the three months ended September 30, 2017. The decrease in amortization of royalty interests in oil and natural gas properties expense was attributable to decreased production and net reserves attributable to the sale of a portion of our interests in certain oil and natural gas properties.

General, Administrative and Other Expense

General, administrative and other expense decreased by less than $0.1 million, or 2%, to $1.1 million for the three months ended September 30, 2018, from $1.2 million for the three months ended September 30, 2017. The decrease in general, administrative and other expense was attributable to the change in management related to the Transaction as the Company is in the process of building its employee base to support the business.

Income Taxes

Income tax expense increased by $0.8 million to $0.8 million for the three months ended September 30, 2018, from $0.0 million for the three months ended September 30, 2017. The increase in income taxes was attributable to Royal historically being treated as a Partnership which changed as a part of the Transaction.

Comparison of the nine months ended September 30, 2018 to the nine months ended September 30, 2017:

Oil and Gas Revenues

Oil and gas revenues increased $2.7 million, or 4%, to $72.4 million for the nine months ended September 30, 2018, from $69.6 million for the nine months ended September 30, 2017. The increase in oil and gas revenues was attributable to a net increase in realized commodity prices offset by a decrease in oil, natural gas liquids and natural gas production primarily due to the sale of a portion of our interests in certain oil and natural gas properties.

Production and Ad Valorem Taxes

Production and ad valorem taxes decreased $0.2 million, or 4%, to $3.9 million for the nine months ended September 30, 2018, from $4.0 million for the nine months ended September 30, 2017. The decrease in production and ad valorem taxes was attributable to a change in the contributions to revenue by our properties and the related tax jurisdictions.

Marketing and Transportation Expense

Marketing and transportation expense decreased $3.6 million, or 71%, to $1.5 million for the nine months ended September 30, 2018, from $5.1 million for the nine months ended September 30, 2017. The decrease in marketing and transportation expense was attributable to a net change in the production from leases that are burdened by marketing and transportation costs to leases that are not burdened by marketing and transportation costs. This change was caused by a sale of a portion of our interests in certain oil and natural gas properties and new production from existing properties.

Amortization of Royalty and Working Interests in Oil and Natural Gas Properties Expense

Amortization of royalty and working interests in oil and natural gas properties expense decreased $14.4 million, or 45%, to $13.1 million for the nine months ended September 30, 2018, from $27.6 million for the nine months ended September 30, 2017. The decrease in amortization of royalty interests in oil and natural gas properties expense was attributable to decreased production and net reserves attributable to the pre-Transaction sale of a portion of Royal’s interests in certain oil and natural gas properties.

General, Administrative and Other Expense

General, administrative and other expense increased $2.8 million, or 68%, to $7.0 million for the nine months ended September 30, 2018, from $4.2 million for the nine months ended September 30, 2017. The increase in general, administrative and other expense was attributable to the expenses related to the pre-Transaction sale of a portion of Royal’s interests in certain oil and natural gas properties and the Transaction which was completed in August 2018.

Income Taxes

Income tax expense increased by $0.8 million to $0.8 million for the nine months ended September 30, 2018, from $0.0 million for the nine months ended September 30, 2017. The increase in income tax expense was attributable to Royal historically being treated as a Partnership which changed as a part of the Transaction.

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to evaluate our performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay dividends to our common shareholders.

We define Adjusted EBITDA as net income from continuing operations plus interest expense, net, depletion expense and provision for (benefit from) income taxes less gain (loss) on the sale of assets which related to a pre-Transaction sale of certain oil and gas interests by Royal. Adjusted EBITDA is not a measure of net income as determined by GAAP. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA 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 historic costs of depreciable assets, none of which are components of Adjusted EBITDA.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, royalty income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.

The following table presents a reconciliation of net income from continuing operations to Adjusted EBITDA, our most directly comparable GAAP financial measure for the periods indicated (in thousands).

Liquidity and Capital Resources

Overview

Our primary sources of liquidity have historically been cash flows from operations and equity and debt financings, and our primary uses of cash are for dividends and for growth capital expenditures, including the acquisition of oil and natural gas properties.  We intend to finance potential future acquisitions through a combination of cash on hand, borrowings under our Credit Facility and, subject to market conditions and other factors, proceeds from one or more capital market transactions, which may include debt or equity offerings. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including commodity prices and general economic, financial, competitive, legislative, regulatory and other factors, including weather.

Cash Flows

The following table presents our cash flows for the periods indicated (in thousands).

Operating activities

Our operating cash flow has historically been sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas for which we receive royalty revenue. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict.

The decrease in cash flow provided by operating activities for the nine months ended September 30, 2018 as compared to the nine months ended September 30, 2017 was attributable to an increase in net income of $55.9 million, non-cash changes of $2.2 million related to hedging activities and $1.1 million related to deferred income taxes offset by non-cash changes of $41.4 million associated with the gain on sale of assets and a decrease in depletion of $16.0 million. In addition, the operating cash flows had a decrease in working capital of $3.2 million. The net changes in working capital were primarily driven by the timing of collection of accounts receivables and the timing of payments of accounts payable and accrued expenses.

Investing activities

Investing activities are primarily related to the acquisition and disposition of oil and natural gas interests. Cash provided by investing activities for the nine months ended September 30, 2018 was $120.6 million and the majority was related to the sale of a portion of our interests in certain oil and natural gas properties in January 2018. Cash used in investing activities for the nine months ended September 30, 2017 was $3.0 million and was related to acquisitions of certain oil and natural gas properties.

Financing activities

Cash used in financing activities for the nine months ended September 30, 2018 was $177.9 million, primarily related to distributions of $150.9 million and debt repayments of $27.0 million. Cash used in financing activities for the nine months ended September 30, 2017 was $31.0 million, primarily attributed to $30.0 million of distributions.

Indebtedness

New Credit Facility

On the Closing Date, we entered into a credit facility with Citibank, N.A., as administrative agent and collateral agent for the lenders from time to time party thereto (the “Credit Agreement”). The Credit Agreement initially provides for aggregate revolving borrowings of up to $500.0 million with an initial $115.0 million borrowing base. On the Closing Date, $38.0 million was drawn under the Credit Agreement to fund a portion of the purchase price of the Business Combination, to pay transaction expenses, to fund any original issue discount or upfront fees in connection with the “market flex” provisions previously agreed upon and to finance working capital needs and other general corporate purposes. 

Principal amounts borrowed are payable on the maturity date. We have a choice of borrowing at the base rate or LIBOR, with such borrowings bearing interest, payable quarterly in arrears for base rate loans and one month, two-month, three month or six-month periods for LIBOR loans. LIBOR loans bear interest at a rate per annum equal to the rate appearing on the Reuters Reference LIBOR01 or LIBOR02 page as the LIBOR, for deposits in dollars at 12:00 noon (London, England time) for one, two, three, or six months plus an applicable margin ranging from 200 to 300 basis points. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one-month LIBOR loans plus 1%, plus an applicable margin ranging from 100 to 200 basis points. The next scheduled redetermination of our borrowing base as of April 1, 2019. 

Obligations under the Credit Agreement are guaranteed by us and each of our existing and future, direct and indirect domestic subsidiaries (the “Credit Parties”) and are secured by all of the present and future assets of the Credit Parties, subject to customary carve-outs.

Prior to the Transaction, Royal had other credit facilities in place which were extinguished at the closing of the Transaction. For a full description of these credit facilities please see “Note 5 – Debt – Royal Credit Facilities.”

Contractual Obligations

We have contractual obligations that are required to be settled in cash. Our contractual obligations as of September 30, 2018 were as follows (in thousands):

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Critical Accounting Policies and Estimates

Management Estimates

The preparation of the consolidated financial statements in conformity with 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 consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of management estimates and assumptions relate to amortization calculations, and estimates of fair value for long-lived assets, and reserves for contingencies and litigation. Management based its estimates on historical experience and on various other assumptions that were believed to be reasonable under the circumstances. Actual results could differ from these estimates.

Royalty in Oil and Natural Gas Properties

 Royalty interests include acquired interests in production, development, and exploration stage properties. We follow the successful efforts method of accounting. Under this method, costs to acquire mineral and royalty interests in oil and natural gas properties are capitalized when incurred.

Acquisition costs of proven royalty interests are amortized using the units of production method over the life of the property, which is estimated using proven reserves. Acquisition costs of royalty interests on exploration stage properties, where there are no proven reserves, are not amortized. At such time as the associated exploration stage interests are converted to proven reserves, the cost basis is amortized using the units of production methodology over the life of the property, using proven reserves. For purposes of amortization, interests in oil and natural gas properties are grouped in a reasonable aggregation of properties with common geological structural features or stratigraphic condition.

Impairment of Royalty Interests in Oil and Natural Gas Properties

We review and evaluate our royalty interests in oil and natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Our estimates of recoverability and fair value are based on numerous assumptions and it is possible that actual results will be significantly different than the estimates, as actual future quantities of recoverable oil and natural gas, commodity prices, production levels, operating costs, and taxes associated with production of oil and natural gas reserves are each subject to significant risks and uncertainties. The carrying value of exploration stage interests are evaluated for impairment when information becomes available indicating that production will not occur in the future. When required, impairment losses are recognized based on the fair value of the assets. No such impairment expense was recorded for the nine months ended September 30, 2018 or 2017.

Revenue Recognition

Revenues from the sale of oil and natural gas are recognized when the product is delivered at a fixed or determinable price, title has transferred, and collectability is reasonably assured and evidenced by a contract. We follow the “entitlement method” of accounting for our oil and natural gas revenue, so it recognizes revenue on all crude oil, natural gas, and natural gas liquids based on our proportionate share of production. Royalty revenue is recognized when management can reliably estimate the royalty receivable, pursuant to the terms of the royalty agreements, and collection is reasonably assured. Differences between estimates of royalty revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk 

Our major market risk exposure is in the pricing applicable to the oil and natural gas production of our operators. Realized pricing was primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil and natural gas production has been volatile and unpredictable for several years, we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control. Historically, we did not enter into hedging arrangements to manage commodity price risks. 

Revenue Concentration Risk 

We are subject to risk resulting from the concentration of oil and gas revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2017, we received approximately 28%, 18%, 18% and 15% of our revenue from Devon, EOG, BHP, and ConocoPhillips, respectively. For the nine months ended September 30, 2018, we received approximately 41%, 25%, and 18% of our revenue from ConocoPhillips, EOG, and Devon, respectively. We did not require collateral and did not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness. As of September 30, 2018, we had total borrowings under our Credit Facility of $38.0 million. The impact of a 1% increase in the interest rate on this amount of debt would result in an increase in interest expense of approximately $0.4 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.

Item 4. Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

Evaluation of Disclosure Controls and Procedures

As required by Rules 13a-15 and 15d-15 under the Exchange Act, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of September 30, 2018. Based upon their evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures (as defined in Rules 13a-15 (e) and 15d-15 (e) under the Exchange Act) were effective.

Changes in Internal Control Over Financial Reporting

During the most recently completed fiscal quarter, there has been no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Although we are, from time to time, involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters, including the matters described below, will have a material adverse impact on our financial condition or results of operations. Additionally, due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any claim or proceeding would not have a material adverse effect on our business, financial condition, results of operations and ability to make quarterly distributions to our shareholders.

Certain of the Company’s officers and directors are defendants in a lawsuit captioned Tomasulo v. Cohen, et al. (Court of Common Pleas, Philadelphia County, Philadelphia), which among other things challenges the adequacy of certain disclosures made in a preliminary proxy statement initially filed with the SEC on June 14, 2018 and subsequently amended on July 16, 2018 and July 30, 2018. The Company paid $0.4 million in September 2018 in full settlement of this litigation.

Item 1A. Risk Factors

Factors that could cause our actual results to differ materially from those in this Quarterly Report are any of the risks described in our definitive proxy statement which was filed with the SEC on August 3, 2018. Any of these factors could result in a significant or material adverse effect on our results of operations or financial condition. Additional risk factors not presently known to us or that we currently deem immaterial may also impair our business or results of operations.

As of the date of this Quarterly Report, there have been no material changes to the risk factors disclosed in our definitive proxy statement which was filed with the SEC on August 3, 2018, except we may disclose changes to such factors or disclose additional factors from time to time in our future filings with the SEC.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Unregistered Sales of Equity Securities 

In June 2016, we issued an aggregate of 125,000 Founder Shares to the Sponsor for an aggregate purchase price of $25,000 or $0.20 per share. In addition, in March 2017, we effected a 57.5-for-1 stock split resulting in an aggregate of 7,187,500 Founder Shares outstanding and held by the Sponsor. The Founder Shares were sold pursuant to an exemption from registration contained in Section 4(a)(2) of the Securities Act and 937,500 of the Founder Shares were subject to forfeiture to the extent the underwriters’ over-allotment option of 3,750,000 Units in connection with the Initial Public Offering was not exercised. On August 9, 2017, the underwriters elected to partially exercise their over-allotment option to purchase 2,500,000 Units at a purchase price of $10.00 per Unit. As a result of the underwriters’ determination not to fully exercise their overallotment option, the Sponsor forfeited 312,500 Founder Shares on August 9, 2017.  

Simultaneously with the consummation of the Initial Public Offering on July 26, 2017, we consummated a private placement of 7,000,000 Private Placement Warrants at a price of $1.00 per warrant, to the Sponsor, generating total proceeds of $7,000,000. In addition, in connection with the underwriters’ partial exercise of the over-allotment option on August 9, 2017, we consummated a private placement of an additional 500,000 Private Placement Warrants at a price of $1.00 per warrant, to the Sponsor, generating total proceeds of $500,000. The 7,500,000 Private Placement Warrants are the same as the warrants sold in the Initial Public Offering, except that the Private Placement Warrants (i) will be non-redeemable so long as they are held by the sponsor or its permitted transferees and (ii) may be exercisable on a cashless basis. In addition, the Private Placement Warrants and their underlying securities will not be transferable, assignable or salable until 30 days after the consummation of the Business Combination. Such securities were issued pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act. The sponsor, as purchaser, is an accredited investor for purposes of Rule 501 of Regulation D.  

Use of Proceeds  

On July 26, 2017, we consummated our Initial Public Offering (inclusive of 2,500,000 units sold pursuant to the underwriters partially exercising their over-allotment option on August 9, 2017), of 27,500,000 units with each unit consisting of one share of our Class A common stock, and one-half (1/2) of one warrant, each whole warrant entitling the holder to purchase one share of Class A common stock at a price of $11.50. 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 common stock to be issued to the warrant holder. Each warrant will become exercisable on the later of 30 days after the completion of our Business Combination or 12 months from the closing of the Initial Public Offering. However, if we do not complete a Business Combination within the period allotted to complete the Business Combination, the warrants will expire at the end of such period. If we are unable to deliver registered shares of Class A common stock to the holder upon exercise of warrants issued in connection with the 27,500,000 units during the exercise period, there will be no net cash settlement of these warrants and the warrants will expire worthless, unless they may be exercised on a cashless basis in the circumstances described in the warrant agreement. The warrants will expire five years after the completion of our initial Business Combination or earlier upon redemption or liquidation. Once the warrants issued in connection with the Initial Public Offering become exercisable, we may redeem those outstanding warrants in whole and not in part at a price of $0.01 per warrant upon a minimum of 30 days’ prior written notice of redemption, but if, and only if, the last sale price of our common stock equals or exceeds $18.00 per share for any 20 trading days within a 30-trading day period ending on the third trading day prior to the date on which we send the notice of redemption to the warrant holders. 

The units in the Initial Public Offering were sold at an offering price of $10.00 per unit, generating total gross proceeds of $275,000,000. Credit Suisse Securities (USA) LLC acted as the sole book running manager and I-Bankers Securities, Inc. acted as co-manager of the offering. The securities sold in the offering were registered under the Securities Act on registration statement on Form S-1 (No. 333-219025). The SEC declared the registration statements effective on July 20, 2017.  

We paid a total of $5,500,000 in underwriting discounts and commissions and $522,219 for other costs and expenses related to the offering. In addition, the underwriters agreed to defer $9,625,000 in underwriting discounts and commissions, and up to this amount will be payable upon consummation of the Business Combination. After deducting the underwriting discounts and commissions (excluding the deferred portion of $9,625,000 in underwriting discounts and commissions, which will be released from the Trust Account upon consummation of the Business Combination, if consummated) and the estimated offering expenses, the total net proceeds from our Initial Public Offering and the private placement was $276,477,781, of which $275,000,000 (or $10.00 per unit sold in the Initial Public Offering) was placed in the Trust Account.

In connection with the Company’s entry into the Contribution Agreement, the Company agreed to issue and sell in a private placement an aggregate of 11,480,000 shares of Class A Common Stock for a purchase price of $10.00 per share, and aggregate consideration of $114.8 million (the “Private Placement”). The Private Placement was consummated concurrently with the Closing and the proceeds of the Private Placement were used to fund a portion of the cash consideration paid to the Contributors. Such securities were issued pursuant to the exemption from registration contained in Section 4(a)(2) of the Securities Act.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 6. Exhibits

The information required by this Item 6 is set forth in the Index to Exhibits accompanying this Quarterly Report on Form 10-Q and is incorporated herein by reference.

EXHIBIT INDEX

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.