flmn-10q_20190930.htm

(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.

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

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

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 13(a) of the Exchange Act. ☐

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

As of November 6, 2019, there were 45,950,716 shares of the registrant’s Class A common stock, par value $0.0001 per share, issued and outstanding and there were 40,000,000 shares of the registrant’s Class C common stock, par value of $0.0001 per share, issued and outstanding.

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.

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.

Condensate: Liquid hydrocarbons associated with the production that is primarily natural gas.

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

Differential: An adjustment to the price of oil and natural gas from an established spot market price to reflect differences in the quality and/or location of oil or natural gas.

Gross acres or gross wells: The total acres or wells, as the case may be, in which an overriding, royalty or mineral 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.

Mineral interests: The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.

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.

Undeveloped acreage: Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Revenues:
Oil and gas sales	$	15,908		$	23,825		$	55,411		$	72,354
Gain (loss) on hedging activities		-			458			-			(1,456	)
Total revenue		15,908			24,283			55,411			70,898
Operating expenses:
Production and ad valorem taxes		891			1,326			2,940			3,854
Marketing and transportation		584			493			1,933			1,487
Amortization of royalty interests in oil and natural gas properties		3,184			4,494			9,624			13,179
General, administrative and other		3,168			1,132			8,728			7,013
Total operating expenses		7,827			7,445			23,225			25,533
Operating income		8,081			16,838			32,186			45,365
Other income (expense):
Gain on the sale of assets		-			-			-			41,382
Other income		58			38			134			39
Interest expense		(650	)		(557	)		(1,838	)		(1,600	)
Total other income (expense)		(592	)		(519	)		(1,704	)		39,821
Income before income taxes		7,489			16,319			30,482			85,186
Provision for income taxes		1,132			810			3,920			810
Income from continuing operations		6,357			15,509			26,562			84,376
Income from discontinued operations		-			91			-			2,139
Net income		6,357			15,600			26,562			86,515
Net income attributable to non-controlling interests		(3,473	)		(2,933	)		(14,540	)		(3,028	)
Net income attributable to common shareholders/unitholders	$	2,884		$	12,667		$	12,022		$	83,487
Earnings per common share:
Common shares (basic and diluted)	$	0.06		$	0.06		$	0.26		$	0.06
Weighted average number of shares outstanding:
Common shares (basic and diluted)		45,899			45,855			45,871			45,855

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

	September 30,
	2019			2018
Cash flow from operating activities:
Net income	$	26,562		$	86,515
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sale of assets		-			(41,382	)
Unrealized (gain) loss on hedging activities		-			1,151
Amortization of royalty interests in oil and natural gas properties		9,624			14,753
Depreciation of property and equipment		46			-
Accretion of asset retirement obligation		-			7
Amortization of debt issuance costs		482			296
Stock-based compensation		1,830			-
Deferred income taxes		2,302			1,061
Cash paid to settle derivatives		-			(1,151	)
Changes in operating assets and liabilities
Accounts receivable		3,242			1,067
Prepaid expenses		232			(616	)
Other assets		10			-
Accounts payable and accrued expenses		1,454			(4,752	)
Other liabilities		476			(147	)
Net cash provided by operating activities		46,260			56,802
Cash flows from investing activities:
Additions to oil and natural gas properties		-			(523	)
Purchase of property and equipment		(542	)		-
Cash acquired in the Transaction		-			2,920
Proceeds from the sale of assets		-			121,130
Acquisition of oil and natural gas properties		(20,903	)		-
Net cash provided by (used in) investing activities		(21,445	)		123,527
Cash flows from financing activities:
Distributions to partners		-			(143,788	)
Distribution of subsidiaries		-			(7,124	)
Proceeds from credit facility		30,000			-
Repayments of long-term debt		(13,000	)		(27,000	)
Deferred financing fees		-			(8	)
Dividends paid		(24,089	)		-
Distributions to non-controlling interests		(22,302	)		-
Distribution equivalent rights paid		(114	)		-
Net cash used in financing activities		(29,505	)		(177,920	)
Net increase (decrease) in cash and cash equivalents		(4,690	)		2,409
Cash and cash equivalents, beginning of period		7,317			10,497
Cash and cash equivalents, end of period	$	2,627		$	12,906
Supplemental disclosure of cash flow information:
Cash paid for interest	$	1,356		$	1,245
Cash paid for income taxes	$	1,260		$	450
Non-cash investing and financing activities:
Credit facility prior to the transaction	$	-		$	38,000
Deferred financing prior to the Transaction	$	-		$	3,214
Deferred tax asset related to the Transaction	$	-		$	60,603
Accounts payable related to property and equipment	$	-		$	229

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

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND PARTNERS’ CAPITAL

	Class A Common Stock				Class C Common Stock
	Shares		Amount		Shares		Amount		Additional Paid In Capital			Partners' Capital			Non- controlling interests			Retained Earnings			Total Stockholder's Equity / Partners' Capital
Balance at December 31, 2017		-	$	-		-	$	-	$	-		$	288,528		$	629		$	-		$	289,157
Distributions		-		-		-		-		-			(107,497	)		(38	)		-			(107,535	)
Net income		-		-		-		-		-			53,866			48			-			53,914
Balance at March 31, 2018		-	$	-		-	$	-	$	-		$	234,897		$	639		$	-		$	235,536
Distributions		-		-		-		-		-			-			-			-			-
Net income		-		-		-		-		-			16,956			47			-			17,003
Balance at June 30, 2018		-	$	-		-	$	-	$	-		$	251,853		$	686		$	-		$	252,539
Distributions		-		-		-		-		-			(36,253	)		-			-			(36,253	)
Net income prior to Transaction		-		-		-		-		-			10,137			20			-			10,157
Recapitalization in connection with the Transaction		45,855		5		40,000		4		137,866			(225,737	)		119,556			-			31,694
Net income post Transaction		-		-		-		-		-			-			2,913			2,529			5,442
Balance at September 30, 2018		45,855	$	5		40,000	$	4	$	137,866		$	-		$	123,175		$	2,529		$	263,579


Balance at December 31, 2018		45,855	$	5		40,000	$	4	$	137,866		$	-		$	127,029		$	4,810		$	269,714
Vested restricted stock grants		4		-		-		-		-						-			-			-
Stock-based compensation		-		-		-		-		99						-			-			99
Distribution equivalent rights paid		-		-		-		-		(15	)					-			-			(15	)
Distributions to non-controlling interests		-		-		-		-		-						(8,559	)		-			(8,559	)
Dividends to shareholders ($0.20 per share)		-		-		-		-		-						-			(9,171	)		(9,171	)
Net income		-		-		-		-		-						5,921			5,382			11,303
Balance at March 31, 2019		45,859		5		40,000		4		137,950			-			124,391			1,021			263,371
Vested restricted stock grants		3		-		-		-		-			-			-			-			-
Stock-based compensation		-		-		-		-		761			-			-			-			761
Distribution equivalent rights paid		-		-		-		-		(56	)		-			-			-			(56	)
Distributions to non-controlling interests		-		-		-		-		-			-			(7,397	)		-			(7,397	)
Dividends to shareholders ($0.175 per share)		-		-		-		-		(3,248	)		-			-			(4,777	)		(8,025	)
Net income		-		-		-		-		-			-			5,146			3,756			8,902
Balance at June 30, 2019		45,862	$	5		40,000	$	4	$	135,407		$	-		$	122,140		$	-		$	257,556
Vested restricted stock grants		89		-		-		-		-			-			-			-			-
Stock-based compensation		-		-		-		-		970			-			-			-			970
Distribution equivalent rights paid		-		-		-		-		(43	)		-			-			-			(43	)
Distributions to non-controlling interests		-		-		-		-		-			-			(6,346	)		-			(6,346	)
Dividends to shareholders ($0.15 per share)		-		-		-		-		(4,009	)		-			-			(2,884	)		(6,893	)
Net income		-		-		-		-		-			-			3,473			2,884			6,357
Balance at September 30, 2019		45,951	$	5		40,000	$	4	$	132,325		$	-		$	119,267		$	-		$	251,601

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

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 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, a 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 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 (collectively, “Royalties”), underlying approximately 256,000 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 68,000 gross unit 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 pay for capital expenditures such as plugging and abandonment costs at the beginning and end of a well’s productive life.

The acquisition of the Royal Entities has been accounted for as a reverse recapitalization. Under this method of accounting, Falcon is treated as the acquired company and Royal is 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. The Royal subsidiaries that were contributed in the Transactions 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 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 the audited financial statements for the year ended December 31, 2018 included in our Annual Report on Form10-K that the Company filed with the SEC on March 14, 2019.

Subsequent to the issuance of the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 2019 and the three and six months ended June 30, 2019, the Company’s management determined that a portion of the dividends to shareholders had been improperly deducted from Additional Paid In Capital (“APIC”) rather than deducted from Retained Earnings until Retained Earnings had been exhausted. As a result, in the Condensed Consolidated Statements of Shareholders’ Equity and Partners’ Capital, the dividends to shareholders have been correctly classified reducing Retained Earnings rather than APIC, and the total balances of Retained Earnings and APIC have been corrected at March 31, 2019 and at June 30, 2019 as follows:

The reclassification does not change, in any period, Total Shareholders’ Equity. The Company evaluated the materiality of these misstatements from a quantitative and qualitative perspective and has concluded the misstatements are not material to the prior periods.

Cash and cash equivalents represent unrestricted cash on hand and include all highly liquid investments purchased with a maturity of three months or less and money market funds. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments.

The preparation of 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 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. 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.

The Company’s accounts receivable balance results primarily from operators’ sales of oil and natural gas to their customers. Accounts receivable are recorded at the contractual amounts and do not bear interest. The Company reserves for specific accounts receivables when it is probable that all or a part of an outstanding balance will not be collected. The Company regularly reviews collectability and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered doubtful. As of September 30, 2019 and December 31, 2018, the Company had not recorded any reserves for uncollectible amounts or deemed any amounts to be uncollectible.

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 unproved 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.

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. Proved oil and gas properties are reviewed for impairment when events and circumstances indicate a potential decline in the fair value of such properties below the carrying value, such as a downward revision of the reserve estimates or lower commodity prices. When such events or changes in circumstances occur, we estimate the undiscounted future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. If the carrying value of the properties is determined to not be recoverable based on the undiscounted cash flows, an impairment charge is recognized by comparing the carrying value to the estimated fair value of the properties. The factors used to determine fair value include, but are not limited to, estimates of proved, probable and possible reserves, future commodity prices, the timing of future production and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. There was no such impairment of proved oil and natural gas properties for the three and nine months ended September 30, 2019 or 2018.

Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value. The carrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data. There was no impairment of unproved properties for the three and nine months ended September 30, 2019 and 2018.

Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income. Upon the sale or retirement of an individual well, or an aggregation of interests which make up less than a complete depletable unit, the proceeds are credited to accumulated DD&A, unless doing so would significantly alter the DD&A rate of the depletable unit, in which case a gain or loss would be recorded.

Other assets include capitalized financing costs of $2.5 million and $3.0 million as of September 30, 2019 and December 31, 2018, respectively. The costs are associated with the Company’s credit agreement and are being amortized over the term of the credit agreement.

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 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 6 – Debt – Falcon Credit Facility” below) has a market rate of interest, its carrying amount approximated fair value (Level 2).

Revenues from royalty properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received 30 to 90 days after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Revenues from lease bonus are recorded upon receipt. The lease bonus is separate from the lease itself and is recognized as revenue to the Company upon receipt of payment.

The Company’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligations under any of the Company’s royalty income contracts.

Under the Company’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Company’s royalty income contracts do not give rise to contract assets or liabilities.

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for certain oil, natural gas and NGLs 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 quarter that payment is received from the producer. Identified differences between the Company’s revenue estimates and actual revenue received historically have not been significant. For the three and nine months ended September 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Company believes that the pricing provisions of its oil, natural gas and NGLs contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded.

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, 2019. 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 historical financial statements prior to the Transactions.

Share-based compensation awards are measured at fair value on the date of grant and are expensed, net of any actual forfeitures, over the required service period. See Note 8—Share-Based Compensation.

Since the Transactions, Falcon has not engaged in any derivative transactions. Historically, 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 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 Transactions.

The Company derives revenue from royalty interests, mineral interests, non-participating royalty interests and overriding royalty interests, or ORRIs (collectively “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.

The Company is an “emerging growth company” (“EGC”) as defined by the JOBS Act. The JOBS Act provides that an emerging growth company can take advantage of the extended transition period provided in Section 13(a) of the Exchange Act for complying with new or revised accounting standards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The Company has elected to avail itself of this exemption and, as a result, its financial statements may not be comparable to the financial statements of issuers that are required to comply with the effective dates for new or revised accounting standards that are applicable to public companies. Section 107 of the JOBS Act provides that the Company can elect to opt out of the extended transition period at any time, which election is irrevocable.

In May 2014, the Financial Accounting Standards Board (“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 is 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 has completed its review of a representative sample of revenue contracts covering its material revenue streams that was designed to evaluate any potential changes in revenue recognition upon adoption of the new standard, and based on evaluations to-date, the implementation of the new standard will not have a material impact on the consolidated financial statements and disclosures. The Company has also completed its review of the information technology and internal control changes that will be required to implement the new standard based on the results of its contract review process. The Company adopted the modified retrospective approach upon adoption of the new guidance on the effective date of January 1, 2019. The adoption of this standard did not result in a cumulative-effect adjustment. Please see Note 3—Impact of ASC 606 Adoption for further details related to the Company’s adoption of this standard.

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 adopted this update prospectively and the adoption of this requirement did not have a significant impact on the Company’s 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 adoption of this requirement did not have a significant impact on the Company’s financial condition, results of operations, cash flows and related disclosures.

In June 2018, the FASB issued new guidance which provides clarifications with respect to stock compensation issued to non-employees. This update applies the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company adopted this update effective January 1, 2019. It did not have a material impact on its financial position, results of operations or liquidity.

ASC 606, Revenue from Contracts with Customers, requires the Company to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. The Company adopted ASC 606 using the modified retrospective method, which was applied to all existing contracts for which all (or substantially all) of the revenue had not been recognized under legacy revenue guidance as of January 1, 2019.

The Company also earns revenue from lease bonuses and delay rentals. The Company generates lease bonus revenue by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company’s contract with a customer and generally transfers the rights to any oil or natural gas discovered, grants the Company a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company also recognizes revenue from delay rentals to the extent drilling has not started within the specified period, payment has been received, and the Company has no further obligation to refund the payment.

The Company has utilized the practical expedient in ASC 606 which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Given that the Company does not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, the Company does not typically record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period. Overall, there were no material changes in the timing of the satisfaction of the Company's performance obligations or the allocation of the transaction price to its performance obligations in applying the guidance in ASC 606 as compared to legacy U.S. GAAP.

The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets. The difference between the Company's estimates and the actual amounts received for oil and natural gas sales is recorded in the period that payment is received from the third party. For the three and nine months ended September 30, 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was immaterial.

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 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 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 September 30, 2019, 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 Transactions through its majority voting interests in both the Company and, accordingly, OpCo, the Transactions were 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 Transactions 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 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 cost; and (iv) the Company’s equity and earnings per share for the period from the Closing Date.

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

Below are the amounts attributed to the disposition of the RNR interests included in the condensed consolidated cash flow statements (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 party for cash proceeds of $121.1 million. The sale resulted in a realized gain of $41.3 million. For the three and nine months ended September 30, 2018, the Company has recorded approximately $0.1 million and $41.4 million in realized gains related to the sale of its interests in a portion of its oil and natural gas properties.

Royal’s historical primary sources of indebtedness were its first lien credit facility, which it entered into in October 2012, and the 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.

On the Closing Date, the Company 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 provides for a maximum credit amount of $500.0 million and a borrowing base based on its oil and natural gas reserves and other factors of $105.0 million, subject to scheduled semi-annual and other borrowing base redeterminations and expires on the fifth anniversary of the Closing Date. On the Closing Date, $38.0 million was drawn under the Credit Facility to fund a portion of the purchase price of the Transactions, 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. Effective May 24, 2019, in connection with the Company’s spring 2019 redetermination, the borrowing base decreased from $115.0 million to $105.0 million and, as of September 30, 2019, the Company had borrowings of $38.0 million under the Credit Facility at an interest rate of 4.29% and $67.0 million available for future

borrowings under the Credit Facility. The Company incurred $3.2 million of expenses in connection with the closing of the Credit Facility. These amounts are being amortized over the term of the Credit Facility. Unamortized deferred issuance costs were $2.5 million as of September 30, 2019.

Principal amounts borrowed are payable on the maturity date. The Company has a choice of borrowing at an alternative base rate (which is equal to the greatest of the federal funds rate plus one-half of 1.0%, the prime rate or the one-month LIBOR rate plus 1.0%) 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 scheduled redeterminations of our borrowing base take place on April 1^st and October 1^st of each year.

Obligations under the Credit Facility are guaranteed by the Company and each of its 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 various affirmative, negative and financial maintenance covenants. These covenants, among other things, include restrictions on the Company’s ability to incur additional indebtedness, acquire and sell assets, create liens, enter into certain lease agreements, make investments, make distributions and require the maintenance of the financial ratios described below.

Prior to the Transactions, Falcon was a special purpose acquisition company with no operations, formed as a vehicle to affect a business combination with one or more operating businesses. After the Closing of the Transactions, 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, 2019.

Preferred Stock – At September 30, 2019, 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, 2019, there were 45,950,716 shares of Class A Common Stock issued and outstanding. 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 C Common Stock – At September 30, 2019, there were 40,000,000 shares of Class C Common Stock issued and outstanding. Class C Common Stock was issued to the Contributors in connection with the Transactions and are non-economic but entitle 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.

Public Warrants – In July 2017, the Company consummated its initial public offering of units, each consisting of one share of Class A Common Stock and one-half of one warrant (“Public Warrant”). At September 30, 2019, there were 13,749,999 Public Warrants outstanding. Each Public Warrant entitles the holder to purchase one share of Class A Common Stock at a price of $11.50 per share. The Public Warrants will expire five years after the closing of the Transactions or earlier upon redemption or liquidation. The Company may call the Public Warrants for redemption, in whole and not in part, at a price of $0.01 per warrant with not less than

30 days’ notice provided to the Public Warrant holders. However, this redemption right can only be exercised if the last sale price of the Class A Common Stock equals or exceeds $18.00 per share for any 20 trading days within a 30-day trading period ending three business days before we send the notice of redemption to the Public Warrant holders.

Private Placement Warrants – Upon closing of the Osprey initial public offering, the Sponsor purchased an aggregate of 7,500,000 warrants at a price of $1.00 per warrant (the “Private Placement Warrants”). Each Private Placement Warrant is exercisable for one share of Class A Common Stock at a price of $11.50. The Private Placement Warrants are identical to the Public Warrants discussed above, except (i) they will not be redeemable by the Company so long as they are held by the Sponsor and (ii) they may be exercisable by the holders on a cashless basis. At September 30, 2019, there were 7,500,000 Private Placement Warrants outstanding.

In connection with the Transactions, 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 OpCo 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). Upon recognition of the earn-out, as there is no consideration received, the Company would record the payment of the earn-out as adjustments through equity (non-controlling interest and additional-paid-in-capital).

The Company owns 100% of the general partner interests and 53% of the limited partner interests of OpCo and due to the Company’s controlling interest in OpCo, OpCo is a consolidated subsidiary of the Company. Non-controlling ownership interests in OpCo are presented in the consolidated balance sheet within shareholders’ 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, 2019 and 2018, $22.3 million and less than $0.1 million, respectively, of distributions for each period have been made to non-controlling interest holders of the consolidated subsidiaries.

The table below summarizes the quarterly dividends related to the Company’s quarterly financial results:

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. The Plan provides for the grant of stock options, stock appreciation rights, restricted stock, restricted stock units and other stock-based awards. Common shares that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. Distribution equivalent rights (“DER”) are also available for grant under the Plan, either alone or in tandem with other specific awards, which will entitle the recipient to receive an amount equal to dividends paid on a Class A common share. The Plan is administered by the Falcon Board of Directors or a committee thereof.

In accordance with the Plan, the Falcon Board of Directors is authorized to issue restricted stock awards (“RSA”) to eligible employees and directors. The Company estimates the fair value of the RSAs as the closing price of the Company’s Class A Common Stock on the grant date of the award, which is expensed over the applicable vesting period. Each RSA that has been granted has a DER included in each agreement. Dividends paid in connection with the DERs are accounted for as a reduction in retained earnings for those awards that are expected to vest. RSAs that are forfeited could cause a reclassification of any previously recognized DER payments from a reduction in retained earnings to additional compensation cost.

Under the Plan, the Falcon Board of Directors is authorized to issue performance stock units (“PSU”) to eligible employees and directors. The Company estimates the fair value and the derived service period of the PSUs utilizing a lattice model since one of the vesting requirements is a market-based condition (indexed to the Falcon stock price). The Company engaged a third-party consultant to calculate fair value and the derived service period of the grants at the time of issuance. The fair value of the PSUs is then amortized over the longer of the service condition or the derived service period attributable to each grant. All compensation cost for the PSUs will be recognized over the longer of the service condition or the derived service period, even if the market-condition is never satisfied as long as the award is not forfeited. The PSUs that have been granted to date do not have any DERs included in the agreements. PSUs that are forfeited could cause a reclassification of any previously recognized DER payments from a reduction in retained earnings to additional compensation cost.

The following table summarizes the activity in our unvested RSAs and PSUs for the nine months ended September 30, 2019:

For the three and nine months ended September 30, 2019, the Company incurred $1.0 million and $1.8 million, respectively, of share-based compensation which is included in general, administrative and other expenses in the accompanying consolidated statements of operations. The Company did not have any restricted shares granted until 2019 and therefore the Company did not incur any related expenses in the prior year. The unamortized estimated fair value of unvested RSAs and PSUs was $6.3 million at September 30, 2019. These costs are expected to be recognized as expense over a weighted average period of 2.1 years. In addition, for the three and nine months ended September 30, 2019, the Company paid less than $0.1 million and $0.1 million, respectively, related to DERs of RSA holders.

The Transactions were 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 Transactions due to the reverse recapitalization.

Earnings per share is computed using the two-class method. The two-class method determines earnings per share of common stock and participating securities according to dividends or dividend equivalents and their respective participation rights in undistributed earnings. Participating securities represent restricted stock awards in which the recipients have non-forfeitable rights to dividend equivalents during the performance period.

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

The Company had the following shares that were excluded from the computation of diluted earnings per share because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per share in future periods (in thousands):

Diluted net income per share also excludes the effects of OpCo Common Units (and related Class C Common Stock) associated with the earn-out, which are convertible into Class A Common Stock, and the PSUs because each are considered contingently issuable shares and the conditions for issuance were not satisfied as of September 30, 2019.

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.

For the three and nine months ended September 30, 2019, the Company recorded an income tax expense of $1.1 million and $3.9 million, respectively. For the three and nine months ended September 30, 2018, the Company recorded an income tax expense of $0.8 million during each period. 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 any period prior to the business combination on August 23, 2018.

As of September 30, 2019, the Company had $56.5 million of net deferred tax assets net of valuation allowances. These net deferred tax assets relate to oil and gas assets and other temporary items where the tax basis differs from the GAAP carrying amounts.

At September 30, 2019 and December 31, 2018, the Company had recorded a prepayment of income taxes of $0.5 million and $0.8 million, 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, 2019. 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, 2019, 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 is recorded in the amounts reported in our income tax provision.

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 Founder Shares outstanding and held by the Sponsor. The Founder Shares automatically converted into Class A Common Stock upon the consummation of the Transactions 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 Osprey initial public offering, 312,500 Founder Shares were forfeited resulting in an aggregate of 6,875,000 Founder Shares held by the Sponsor prior to the Transactions.

Atlas Energy Group, LLC, which Company officers and directors Edward Cohen and Jonathan Cohen 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 three and nine months ended September 30, 2019, the Company paid less than $0.1 million for each period in expenses in connection with such services. For the three and nine months ended September 30, 2018, the Company paid less than $0.1 million for each period 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”), 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 three and nine months ended September 30, 2019, the Company was reimbursed $0.1 million and $0.2 million, respectively, under this agreement. For the three and nine months ended September 30, 2018, the Company was reimbursed less than $0.1 million for each period.

Royal Resources L.P. (“Royal”), which owns 35.2 million shares of the Class C Common Stock of the Company, as well as 35.2 million units of OpCo, entered into a Master Service Agreement (“MSA”) with the Company in December 2018. Under the MSA, the Company provides certain management services to Royal. For the three and nine months ended September 30, 2019, the Company received less than $0.1 million and $0.5 million, respectively, under this agreement.

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:

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.

Future non-cancelable commitments related to certain contractual obligations as of September 30, 2019 are presented below (in thousands):

In November 2019, the Company declared a quarterly cash dividend of $0.135 per share of Class A Common Stock totaling approximately $6.2 million for all shares of Class A Common Stock outstanding. The dividend is for the period from July 1, 2019 through September 30, 2019. The dividend is payable on December 3, 2019 to all Class A shareholders of record on November 20, 2019.

In November 2019, OpCo made distributions totaling $11.6 million to its unitholders, of which $6.2 million was distributed to the Company.

Effective November 8, 2019, in connection with the Company’s fall redetermination, the borrowing base decreased from $105 million to $90 million. The borrowing base decrease would decrease the amount available for future borrowings to $52.0 million, based upon the borrowings under the Credit Facility as of September 30, 2019.

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 report 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 report. 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 NGLs. 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 Annual Report on Form 10-K filed with the SEC on March 14, 2019. Should one or more of the risks or uncertainties described in 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 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 our unaudited financial statements and accompanying notes included herein and “Selected Financial Data,” and our audited financial statements and related notes thereto included in our Annual Report on Form 10-K filed with the SEC on March 14, 2019. 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 our 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 18 of our Annual Report on Form 10-K filed with the SEC on March 14, 2019.

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.

We own Royalties that entitle us to a portion of the production of oil, natural gas and NGLs from the underlying acreage at the sales price received by the operator, net of production expenses and taxes. We have no obligation to fund finding and development costs, lease operating expenses or pay capital expenditures such as plugging and abandonment costs. As such, we have historically operated with high cash margins, converting a large percentage of revenue to free cash flow, the majority of which has been distributed to our stockholders in the form of a dividend.

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

Income Taxes. Prior to the Transactions, Royal was treated as a partnership for U.S. federal income tax purposes and for purposes of certain state and local income taxes. Royal was not subject to U.S. federal income taxes. However, Royal was subject to the Texas margin tax. Any taxable income or loss generated by Royal was passed through to and included in the taxable income or loss of its members. We are a corporation and are subject to U.S. federal income taxes, in addition to state and local income taxes with respect to our allocable share of any taxable income or loss of OpCo, as well as any stand-alone income or loss generated by us.

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 NGLs that are extracted from natural gas during processing. As of September 30, 2019, our Royalties represented the right to receive an average of 1.33% 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, NGLs and natural gas prices have historically been volatile, and at September 30, 2019 and December 31, 2018, we did not hedge any of our exposure to changes in commodity prices. During the year ended December 31, 2018, West Texas Intermediate posted prices that ranged from $49.98 to $70.76 per Bbl and the NYMEX monthly settlement price of natural gas ranged from $2.64 to $4.72 per MMBtu. During the three months ended September 30, 2019, the West Texas Intermediate posted prices for crude oil ranged from $54.84 to $57.55 per Bbl and the NYMEX monthly settlement price of natural gas ranged from $2.14 to $2.29 per MMBtu. During the nine months ended September 30, 2019, the West Texas Intermediate posted prices for crude oil ranged from $51.55 to $63.87 per Bbl and the NYMEX monthly settlement price of natural gas ranged from $2.14 to $3.64 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 NGLs for the three and nine months ended September 30, 2019 and 2018:

Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state and 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 expenses include the costs to process and transport our production to applicable sales points. Generally, the terms of the lease governing the development of our properties permit the operator to pass through these expenses to us by deducting a pro rata portion of such expenses from our production revenues.

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

General and administrative expenses are costs not directly associated with the production of oil, natural gas and NGLs and include the cost of executives and employees and related benefits (including stock-based compensation expenses), office expenses and fees for professional services. Since the completion of the Transactions in August 2018, we have begun incurring incremental G&A expenses relating to expenses associated with SEC reporting requirements, including annual and quarterly reports to shareholders, tax return preparation and dividend expenses, Sarbanes-Oxley Act compliance expenses, expenses associated with listing our securities, independent auditor fees, legal expenses and investor relations expenses. These incremental G&A expenses are not reflected in the historical financial statements.

Historically these 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 performed substantially the same services for the Company as those Riverbend performed for Royal prior to the Closing Date for the duration of the term of the MSA, which expired on December 10, 2018. The Company has assumed the day-to-day management of the Company since the expiration of the MSA with Riverbend.

We finance a portion of our working capital requirements and acquisitions with borrowings under our credit facility. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to the lenders under our credit facility in interest expense on our statement of operations. Please read “—Liquidity and Capital Resources—Indebtedness” for further details of our credit facility.

Borrowings under Royal’s first lien credit facility and RNR credit facility 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 are no longer our obligations after the Closing.

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 any period prior to the Closing of the Transactions on August 23, 2018.

The following financial information 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 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 Annual Report on Form 10-K filed with the SEC on March 14, 2019.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Revenues:
Oil and gas sales	$	15,908		$	23,825		$	55,411		$	72,354
Gain (loss) on hedging activities		-			458			-			(1,456	)
Total revenue		15,908			24,283			55,411			70,898
Expenses:
Production and ad valorem taxes		891			1,326			2,940			3,854
Marketing and transportation		584			493			1,933			1,487
Amortization of royalty interests in oil and natural gas properties		3,184			4,494			9,624			13,179
General, administrative and other		3,168			1,132			8,728			7,013
Total operating expenses		7,827			7,445			23,225			25,533
Operating income		8,081			16,838			32,186			45,365
Other income (expense):
Gain on the sale of assets		-			-			-			41,382
Other income		58			38			134			39
Interest expense		(650	)		(557	)		(1,838	)		(1,600	)
Total other income (expense)		(592	)		(519	)		(1,704	)		39,821
Income before income taxes		7,489			16,319			30,482			85,186
Provision for income taxes		1,132			810			3,920			810
Income from continuing operations		6,357			15,509			26,562			84,376
Income from discontinued operations		-			91			-			2,139
Net income		6,357			15,600			26,562			86,515
Net income attributable to non-controlling interests		(3,473	)		(2,933	)		(14,540	)		(3,028	)
Net income attributable to common shareholders/unitholders	$	2,884		$	12,667		$	12,022		$	83,487
Other Financial Data:
Adjusted EBITDA ⁽¹⁾	$	12,316		$	21,332		$	43,821		$	58,545

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Production Data:
Oil (Bbls)		220,537			258,665			695,453			934,353
Natural gas (BOE)		133,749			187,640			468,123			513,577
Natural gas liquids (Bbls)		89,652			68,134			240,015			210,163
Combined volumes (BOE)		443,938			514,439			1,403,591			1,658,093
Average daily combined volume (BOE/d)		4,825			5,592			5,141			6,074
% Oil		50	%		50	%		50	%		56	%

Average sales prices:
Oil (Bbls)	$	60.02		$	74.43		$	60.90		$	68.11
Natural gas (Mcf)	$	2.15		$	3.03		$	2.70		$	2.92
Natural gas liquids (Bbls)	$	10.57		$	28.73		$	15.12		$	24.54
Combined per (BOE)	$	35.84		$	47.86		$	38.17		$	46.92

Average Costs ($/BOE):
Production and ad valorem taxes	$	2.01		$	2.58		$	2.09		$	2.32
Marketing and transportation expense	$	1.32		$	0.96		$	1.38		$	0.90
General and administrative	$	7.14		$	2.20		$	6.22		$	4.23
Interest expense, net	$	1.46		$	1.08		$	1.31		$	0.97
Depletion	$	7.17		$	8.74		$	6.86		$	7.95

Comparison of the three months ended September 30, 2019 to the three months ended September 30, 2018:

Oil and gas revenues decreased $7.9 million, or 33%, to $15.9 million for the three months ended September 30, 2019, from $23.8 million for the three months ended September 30, 2018. The decrease in oil and gas revenues was attributable to a decrease in oil and natural gas production in addition to a significant decline in realized oil and natural gas prices. We received an average price of $60.02 per Bbl of oil and $2.15 per Mcf of gas sold in the three months ended September 30, 2019 compared to $74.43 per Bbl of oil and $3.03 per Mcf of gas sold during the three months ended September 30, 2018.

Production and ad valorem taxes decreased $0.4 million, or 33%, to $0.9 million for the three months ended September 30, 2019, from $1.3 million for the three months ended September 30, 2018. The decrease in production and ad valorem taxes was attributable to the decrease in oil and natural gas production. As a percentage of oil and natural gas revenue, production and ad valorem taxes were 6% for each of the three months ended September 30, 2019 and 2018.

Marketing and transportation expense increased $0.1 million, or 18%, to $0.6 million for the three months ended September 30, 2019, from $0.5 million for the three months ended September 30, 2018. As a percentage of revenue, marketing and transportation expense was 4% compared to 2% for the same period in the prior year. Marketing and transportation expense as a percentage of revenue was lower during the three months ended September 30, 2018 due to certain oil and gas interests that the Company owns in the Eagle Ford that contributed a significant amount of production but contractually are not charged for any marketing and transportation expenses.

Amortization of royalty interests in oil and gas properties expense decreased $1.3 million, or 29%, to $3.2 million for the three months ended September 30, 2019, from $4.5 million for the three months ended September 30, 2018. The decrease in amortization of royalty interests in oil and gas properties expense was primarily attributable to a decrease in production in Q3 2019.

General, administrative and other expense increased $2.0 million, or 180%, to $3.2 million for the three months ended September 30, 2019, from $1.1 million for the three months ended September 30, 2018. The increase in general, administrative and other expense as a percentage of revenue was attributable to the change in management related to the Transactions and the additional costs incurred related to being a publicly traded company. In addition, the Company incurred approximately $1.0 million in non-cash

stock-based compensation expense during the third quarter of 2019 related to our long-term incentive plan which was not implemented until 2019.

Interest expense increased by $0.1 million to $0.7 million for the three months ended September 30, 2019, from $0.6 million for the three months ended September 30, 2018. The increase in interest expense was attributable to greater average outstanding borrowings and higher interest rates under our Credit Facility.

Income tax expense increased by $0.3 million for the three months ended September 30, 2019, from $0.8 million for the three months ended September 30, 2018. The increase in income taxes was attributable to the Company only incurring income taxes for a portion of the third quarter of 2018 because the Transactions did not take place until August 23, 2018. Prior to the Transactions, Royal was treated as a partnership and was not subject to income taxes.

Comparison of the nine months ended September 30, 2019 to the nine months ended September 30, 2018:

Oil and gas revenues decreased $16.9 million, or 23%, to $55.4 million for the nine months ended September 30, 2019, from $72.4 million for the nine months ended September 30, 2018. The decrease in oil and gas revenues was attributable to a decrease in oil and natural gas production in addition to a decrease in realized oil and natural gas prices. In March 2018, six wells on certain oil and gas properties located in the Eagle Ford shale, which the Company has a significant interest in, came on line and the subsequent natural decline in production after they came on line through September 30, 2019 was the main cause for the decrease in oil and natural gas production. The decrease in revenue was partially offset by a $1.5 million increase in lease bonus revenue in 2019. We received an average price of $60.90 per Bbl of oil and $2.70 per Mcf of gas sold during the nine months ended September 30, 2019 compared to $68.11 per Bbl of oil and $2.92 per Mcf of gas sold during the nine months ended September 30, 2018.

Production and ad valorem taxes decreased $0.9 million, or 24%, to $2.9 million for the nine months ended September 30, 2019, from $3.9 million for the nine months ended September 30, 2018. The decrease in production and ad valorem taxes was attributable to the decrease in oil and natural gas production. As a percentage of oil and natural gas revenue, production and ad valorem taxes were 5% for each of the nine months ended September 30, 2019 and 2018.

Marketing and transportation expense increased $0.4 million, or 30%, to $1.9 million for the nine months ended September 30, 2019, from $1.5 million for the nine months ended September 30, 2018. As a percentage of revenue, marketing and transportation expense was 3% as compared to 2% for same period in the prior year. Marketing and transportation expense as a percentage of revenue was lower during the nine months ended September 30, 2018 due to certain oil and gas interests that the Company owns in the Eagle Ford that contributed a significant amount of production but contractually are not charged for any marketing and transportation expenses.

Amortization of royalty interests in oil and gas properties expense decreased $3.6 million, or 27%, to $9.6 million for the nine months ended September 30, 2019, from $13.1 million for the nine months ended September 30, 2018. The decrease in amortization of royalty interests in oil and gas properties expense was attributable to a portion of our interests in certain oil and natural gas properties sold during Q1 2018 having had a higher amortization rate in addition to a decrease in production during the nine months ended September 30, 2019.

General, administrative and other expense increased by $1.7 million, or 24%, to $8.7 million for the nine months ended September 30, 2019, from $7.0 million for the nine months ended September 30, 2018. The increase in general, administrative and other expense was attributable to the change in management related to the Transactions and the additional costs incurred related to being a publicly traded company. In addition, the Company incurred approximately $1.8 million in non-cash stock-based compensation expense during 2019 in connection with the implementation of our long-term incentive plan.

Interest expense increased by $0.2 million to $1.8 million for the nine months ended September 30, 2019, from $1.6 million for the nine months ended September 30, 2018. The increase in interest expense was attributable to greater average outstanding borrowings and higher interest rates under our Credit Facility.

Income tax expense increased by $3.1 million for the nine months ended September 30, 2019, from $0.8 million for the nine months ended September 30, 2018. The increase in income taxes was attributable to the Company only incurring income taxes for a portion of the third quarter of 2018 because the Transactions did not take place until August 23, 2018. Prior to the Transactions, Royal was treated as a partnership and was not subject to income taxes.

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 stockholders.

We define Adjusted EBITDA as net income plus interest expense, net, depletion expense, provision for (benefit from) income taxes and share-based compensation less gain (loss) on the sale of assets which related to a pre-Transactions 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 to Adjusted EBITDA, our most directly comparable GAAP financial measure for the periods indicated (in thousands).

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.

Our shareholders agreement does not require us to distribute any of the cash we generate from operations. We believe, however, that it is in the best interests of our stockholders if we distribute a substantial portion of the cash we generate from operations. Cash dividends are made to the common stockholders of record on the applicable record date, generally within 60 days after the end of each quarter. Available cash for each quarter’s dividend is determined by the Board of Directors following the end of such quarter.

Available cash for each quarter generally equals Adjusted EBITDA reduced for cash needed for debt service, income tax requirements and other contractual obligations and fixed charges that the Board of Directors deems necessary or appropriate, if any.

The following table presents cash distributions approved by the Board of Directors of our general partner for the periods presented.

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 provides for a maximum credit amount of $500.0 million and a borrowing base based on its oil and natural gas reserves and other factors of $105.0 million, subject to scheduled semi-annual and other borrowing base redeterminations and expires on the fifth anniversary of the Closing Date. On the Closing Date, $38.0 million was drawn under the Credit Facility to fund a portion of the purchase price of the Transactions, 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. Effective May 24, 2019, in connection with the Company’s spring 2019 redetermination, the borrowing base decreased from $115.0 million to $105.0 million and, as of September 30, 2019, the Company had borrowings of $38.0 million under the Credit Facility at an interest rate of 4.29% and $67.0 million available for future borrowings under the Credit Facility. Subsequent to September 30, 2019, the Company completed the scheduled fall redetermination process and the Company’s borrowing based was reduced to $90.0 million. Therefore, based upon the borrowings outstanding under the Credit Facility at September 30, 2019, the amount available for future borrowings would be reduced to $52.0 million.

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 scheduled redeterminations of our borrowing base take place on April 1^st and October 1^st of each year.

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 of 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, 2019, 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.

Prior to the Transactions, Royal had other credit facilities in place which were extinguished at the closing of the Transactions. For a full description of these credit facilities please see “Item 1– Note 6 – Debt – Royal Credit Facilities.”

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

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 have historically been beyond our control and are difficult to predict.

The decrease in cash flow provided by operating activities for the nine months ended September 30, 2019 as compared to the nine months ended September 30, 2018 was primarily related to a 25% decrease in oil production, a 9% decrease in natural gas production coupled with a 10% decrease in realized oil prices and a 8% decrease in realized natural gas prices period over period partially offset by an increase in working capital primarily driven by the timing of collection of accounts receivables and the timing of payments of accounts payable and accrued expenses.

Investing activities are primarily related to the acquisition and disposition of oil and natural gas interests. Cash used in investing activities for the nine months ended September 30, 2019 was $21.4 million and the majority was related to the acquisition of certain royalty interests in oil and natural gas properties. Cash provided by investing activities for the nine months ended September 30, 2018 was $123.5 million and was mostly related to the proceeds from the sale of certain oil and natural gas properties.

Cash used in financing activities for the nine months ended September 30, 2019 was $29.5 million, primarily related to distributions and dividends totaling $46.5 million partially offset by a net increase in borrowings under our Credit Facility of $17.0 million. The borrowings under our Credit Facility were primarily used to fund the acquisition of certain royalty interests in oil and gas properties during the period. Cash used in financing activities for the nine months ended September 30, 2018 was $177.9 million, primarily attributable to $143.8 million of distributions and $27.0 million of repayments made on the RNR credit facility.

There were no material changes in our contractual obligations and other commitments as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.

There have been no changes to our critical accounting policies and estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018.

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 and 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.

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 nine months ended September 30, 2019, we received approximately 35%, 29%, and 17% of our revenue from ConocoPhillips, EOG Resources, and Devon, respectively. For the nine months ended September 30,

2018, we received approximately 41%, 21%, and 16% of our revenue from ConocoPhillips, EOG Resources, 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.

We have exposure to changes in interest rates on our indebtedness. As of September 30, 2019, 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.

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.

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, 2019. 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.

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.

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 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 stockholders.

Factors that could cause our actual results to differ materially from those in this Quarterly Report are any of the risks described in our Annual Report on Form 10-K which was filed with the SEC on March 14, 2019. 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 Annual Report on Form 10-K which was filed with the SEC on March 14, 2019, except we may disclose changes to such factors or disclose additional factors from time to time in our future filings with the SEC.

The following documents are filed as part of this Quarterly Report on Form 10-Q or incorporated herein by reference.

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.

Delaware		82-0820780
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

510 Madison Avenue, 8^th Floor, New York, NY		10022
(Address of principal executive offices)		(Zip Code)

			Page
GLOSSARY OF TERMS			3
PART I.	FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)
		Condensed Consolidated Balance Sheets	5
		Condensed Consolidated Statements of Operations	6
		Condensed Consolidated Statements of Cash Flows	7
		Condensed Consolidated Statements of Shareholders’ Equity and Partners’ Capital	8
		Notes to Condensed Consolidated Financial Statements	9
	Cautionary Statement Regarding Forward-Looking Statements		23
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
	Item 4.	Controls and Procedures	33
PART II.	OTHER INFORMATION
	Item 1.	Legal Proceedings	33
	Item 1A.	Risk Factors	33
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33
	Item 3.	Defaults Upon Senior Securities	34
	Item 4.	Mine Safety Disclosures	34
	Item 6.	Exhibits	34
EXHIBIT INDEX			35
SIGNATURES			36

	September 30,		December 31,
	2019		2018
Assets:
Current assets:
Cash and cash equivalents	$	2,627	$	7,317
Account receivable		8,029		11,271
Prepaid expenses		1,292		1,524
Total current assets		11,948		20,112
Royalty interests in oil and natural gas properties, net of accumulated amortization of $127,229 and $117,605 respectively		220,446		209,168
Property and equipment, net		497		-
Deferred tax asset, net		56,470		58,773
Other assets		2,690		3,182
Total assets	$	292,051	$	291,235
Liabilities and shareholders' equity:
Current liabilities:
Accounts payable and accrued expenses	$	1,974	$	521
Credit facility		38,000		21,000
Other non-current liabilities		476		-
Total liabilities		40,450		21,521
Commitments and contingencies (See Note 13)
Shareholders' equity:
Preferred stock, $0.0001 par value; 1,000,000 shares authorized; none issued and outstanding		-		-
Class A common stock, $0.0001 par value; 240,000,000 shares authorized; 45,950,716 and 45,855,000 shares issued and outstanding as of September 30, 2019 and December 31, 2018, respectively		5		5
Class C common stock, $0.0001 par value; 120,000,000 shares authorized; 40,000,000 issued and outstanding as of September 30, 2019 and December 31, 2018		4		4
Additional paid in capital		132,325		137,866
Non-controlling interests		119,267		127,029
Retained earnings		-		4,810
Total shareholders' equity		251,601		269,714
Total liabilities and shareholders' equity	$	292,051	$	291,235

	Retained		Additional Paid
	Earnings		In Capital
March 31, 2019 as presented		10,192		128,779
March 31, 2019 as corrected		1,021		137,950

June 30, 2019 as presented		13,948		121,459
June 30, 2019 as corrected		-		135,407

	As of
	September 30,			December 31,
	2019			2018
Oil and natural gas interests:
Subjection to depletion	$	310,863		$	307,438
Not subjection to depletion		36,812			19,335
Gross oil and natural gas interests		347,675			326,773
Accumulated depletion and impairment		(127,229	)		(117,605	)
Oil and natural gas interests, net	$	220,446		$	209,168

Large accelerated filer		☐		Accelerated filer		☑
Non-accelerated filer		☐		Smaller reporting company		☐

Financial Covenant		Required Ratio
Ratio of total net debt to EBITDAX, as defined in the Credit Facility		Not greater than 4.0 to 1.0
Ratio of current assets to current liabilities, as defined in the Credit Facility		Not less than 1.0 to 1.0

	Class A Common Stock		Class C Common Stock		Warrants
Beginning Balance at December 31, 2018		45,855,000		40,000,000		21,249,999
Restricted stock grant vesting		95,716		-		-
Shares outstanding at September 30, 2019		45,950,716		40,000,000		21,249,999

Quarter Ended	Total Quarterly Dividend Per Class A Common Share		Total Cash Dividend		Payment Date	Stockholders Record Date
September 30, 2019	$	0.1350	$	6,203,347	December 3, 2019	November 20, 2019
June 30, 2019	$	0.1500	$	6,879,245	September 6, 2019	August 26, 2019
March 31, 2019	$	0.1750	$	8,025,786	May 29, 2019	May 17, 2019
December 31, 2018	$	0.2000	$	9,171,000	February 28, 2019	February 21, 2019
September 30, 2018⁽¹⁾	$	0.0950	$	4,356,225	November 15, 2018	November 8, 2018

				Weighted Average				Weighted Average
	Restricted			Grant-Date		Performance Stock		Grant-Date
	Stock			Fair Value		Units		Fair Value
Unvested at December 31, 2018		-					-
Granted		419,640		$	8.14		1,413,334	$	3.45
Vested		(97,598	)	$	8.30		-	$	-
Forfeited		(25,125	)	$	7.97		-	$	-
Unvested at September 30, 2019		296,917		$	8.10		1,413,334	$	3.45

	% of Revenues						% of Revenues
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
ConocoPhillips		40	%		58	%		35	%		41	%
EOG Resources		28	%		13	%		29	%		21	%
Devon		18	%		13	%		17	%		16	%
Total		86	%		84	%		81	%		78	%

	Payments Due by Period
	Total		Remainder of 2019		2020		2021		2022		2023		Thereafter
Long-term debt obligations	$	38,000	$	-	$	-	$	-	$	-	$	38,000	$	-
Operating lease obligations		1,578		79		397		400		211		196		295
Total	$	39,578	$	79	$	397	$	400	$	211	$	38,196	$	295

Quarter Ended	Total Quarterly Dividend Per Class A Common Share		Total Cash Dividends		Payment Date	Stockholders Record Date
September 30, 2019	$	0.1350	$	6,203,347	December 3, 2019	November 20, 2019
June 30, 2019	$	0.1500	$	6,879,245	September 6, 2019	August 26, 2019
March 31, 2019	$	0.1750	$	8,025,786	May 29, 2019	May 17, 2019
December 31, 2018	$	0.2000	$	9,171,000	February 28, 2019	February 21, 2019
September 30, 2018 ⁽¹⁾	$	0.0950	$	4,356,225	November 15, 2018	November 8, 2018

	Nine Months Ended September 30,
	2019			2018
Net cash flows provided by (used in):
Operating activities	$	46,260		$	56,802
Investing activities		(21,445	)		123,527
Financing activities		(29,505	)		(177,920	)

Exhibit No.		Description

3.1		Second Amended and Restated Certificate of Incorporation of Falcon Minerals Corporation, dated as of August 23, 2018 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (file No. 001-38158) filed August 29, 2018).

3.2		Amended and Restated Bylaws of Falcon Minerals Corporation (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K/A (file No. 001-38158) filed January 23, 2019).

31.1*		Certification of Principal Executive Officer Pursuant to Securities Exchange Act Rules 13a-14(a) and 15(d)-14(a), as adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Principal Financial Officer Pursuant to Securities Exchange Act Rules 13a-14(a) and 15(d)-14(a), as adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2**		Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

	FALCON MINERALS CORPORATION


Date: November 8, 2019	By:	/s/ Daniel C. Herz
		Daniel C. Herz
		President and Chief Executive Officer (Principal Executive Officer)

Date: November 8,2019	By:	/s/ Bryan C. Gunderson
		Bryan C. Gunderson
		Chief Financial Officer
		(Principal Financial Officer)