Exhibit 99.3

 

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., Noble EF DLG LP, a Texas limited partnership, Noble EF DLG GP LLC, a Texas limited liability company, Noble EF LP, a Texas limited partnership, Noble EF GP LLC, a Texas limited liability company, Noble Marcellus LP, a Delaware limited partnership, and Noble Marcellus GP, LLC, a Delaware limited liability company as the contributed entities.

 

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

 

Overview

 

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

 

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

 

Sources of Our Revenue

 

Our revenues were derived from royalty payments we received from our operators based on the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from natural gas during processing. As of June 30, 2018, Our Royalties represented the right to receive an average of 1.36% 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. For the year ended December 31, 2017, our revenues were derived 77% from oil and condensate sales, 11% from natural gas liquid sales and 12% from natural gas sales. For the three months ended March 31, 2018, our revenues were derived 82% from oil and condensate sales, 7% from natural gas liquid sales and 11% from natural gas sales. For the six months ended June 30, 2018, our revenues were derived 83% from oil and condensate sales, 6% from natural gas liquid sales and 11% from natural gas sales. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile, and at December 31, 2017, and June 30, 2018, we did not hedge any of our exposure to changes in commodity prices. During the twelve months ended December 31, 2017, West Texas Intermediate posted prices ranged from $42.53 to $60.42 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On June 30, 2018, the West Texas Intermediate posted price for crude oil was $74.13 per Bbl and the Henry Hub spot market price of natural gas was $2.92 per MMBtu.

  

 

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

  

		Three Months Ended				Six Months Ended				Three Months Ended				Six Months Ended				Year Ended
		June 30,				June 30,				June 30,				June 30,				December 31,
		2018				2018				2018				2017				2017				2016				2015
Average prices
Oil (Bbls)		$	66.50			$	65.73			$	47.19			$	48.49			$	50.10			$	39.91			$	46.12
Natural gas (MMBtu)		$	2.80			$	2.85			$	3.07			$	3.02			$	2.81			$	2.19			$	2.33
Natural gas liquids (Bbl)		$	21.49			$	22.53			$	16.75			$	19.18			$	20.63			$	12.04			$	13.07

 

PRINCIPAL COMPONENTS OF OUR COST STRUCTURE

 

Production and Ad Valorem Taxes

 

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

 

Marketing and Transportation

 

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

 

Amortization

 

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

 

 

General and Administrative

 

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

 

Interest Expense

 

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

 

Income Tax Expense

 

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.

 

Basis of Presentation

 

The following financial statements include information regarding Royal Resources L.P. as Falcon’s predecessor entity, which includes certain interests in subsidiary companies which were not acquired by Osprey in the transactions contemplated by the Proxy Statement. 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 and KGD ORRI, L.P. were not contributed in the transactions contemplated by the Proxy Statement. For additional information, please see the pro forma financial information included in the section entitled “Unaudited Pro Forma Condensed Consolidated Combined Financial Information” included elsewhere in this Current Report on Form 8-K in Exhibit 99.6.

 

 

RESULTS OF OPERATIONS

 

The following table summarizes our revenue and expenses and production data for the period indicated.

 

		Three Months Ended								Six Months Ended								Year Ended
		June 30,								June 30,								December 31,
		2018				2017				2018				2017				2017				2016				2015
Operating Results:
Revenues:
Oil and Gas Sales		$	30,457			$	24,976			$	53,295			$	54,396			$	104,321			$	73,579			$	108,018
Realized (loss) gain on hedging activities			(209	)			357				(206	)			387				751				197				-
Unrealized (loss) gain on hedging activities			(1,614	)			394				(1,708	)			1,569				1,040				(1,040	)			-
Total Revenues			28,634				25,727				51,381				56,352				106,112				72,736				108,018
Costs and Expenses:
Production and ad valorem taxes			1,734				1,542				2,972				3,205				5,980				4,768				6,527
Lease operating expense			210				152				396				263				674				440				273
Marketing and transportation			542				1,801				1,173				3,909				6,926				6,747				7,946
Amortization of royalty and working interests in oil and natural gas properties			5,283				10,235				10,078				21,410				37,085				37,265				46,533
General, administrative and other			3,534				1,465				6,153				3,140				8,450				6,309				12,175
Total costs and expenses		$	11,303			$	15,195			$	20,772			$	31,927			$	59,115			$	55,529			$	73,454
Other Income and (Expense):
Gain on sale of assets			108				-				41,382				-				31,441				-				-
Other income			-				1				-				2				34				823				436
Interest expense			(436	)			(689	)			(1,074	)			(1,343	)			(2,799	)			(3,250	)			(5,462	)
Total other income (expense):		$	(328	)		$	(688	)		$	40,308			$	(1,341	)		$	28,676			$	(2,427	)		$	(5,026	)
Net Income:		$	17,003			$	9,844			$	70,917			$	23,084			$	75,673			$	14,780			$	29,538
Net income attributable to non-controlling interest			(47	)			(28	)			(95	)			(61	)			(155	)			(69	)			(97	)
Net Income attributable to Royal Resources L.P.		$	16,956			$	9,816			$	70,822			$	23,023			$	75,518			$	14,711			$	29,441
Production Data:
Eagle Ford Shale:
Oil (Bbls)			348,839				362,002				600,588				786,143				1,402,729				1,397,556				1,876,487
Natural gas (Mcf)			845,117				766,979				1,352,169				1,626,622				3,083,099				2,936,394				4,201,152
Natural gas liquids (Bbls)			60,561				117,207				122,867				250,793				493,334				476,780				621,222
Combined volumes (BOE)			550,253				607,039				948,817				1,308,040				2,409,913				2,363,735				3,197,901
Average daily combined volumes (BOE/d)			6,047				6,671				5,242				7,227				6,603				6,476				8,761
Total:
Oil (Bbls)			384,876				409,642				675,687				863,088				1,582,322				1,474,218				1,919,955
Natural gas (Mcf)			1,127,476				1,158,127				1,955,624				2,361,498				4,565,892				4,143,679				5,357,859
Natural gas liquids (Bbls)			70,018				127,374				142,029				269,651				542,706				511,337				650,599
Combined volumes (BOE)			642,807				730,038				1,143,653				1,526,322				2,886,010				2,676,168				3,463,530
Average daily combined volumes (BOE/d)			7,064				8,022				6,319				8,433				7,907				7,332				9,489

 

 

Comparison of the three months ended June 30, 2018 to the three months ended June 30, 2017

 

Oil and Gas Revenues

 

Oil and gas revenues increased $5.5 million, or 22%, to $30.5 million for the three months ended June 30, 2018, from $25.0 million for the three months ended June 30, 2017. The increase in oil and gas revenues is attributable to a net increase in realized commodity prices offset by a decrease in oil natural gas liquids and natural gas production caused by the sale of a proportion of our interests in certain oil and natural gas properties. We received an average price of $66.50 per Bbl of oil, $2.80 per Mcf of gas and $21.49 per Bbl of natural gas liquids sold in the three months ended June 30, 2018 compared to $47.19 per Bbl of oil, $3.07 per Mcf of gas and $16.75 per Bbl of natural gas liquids sold during the three months ended June 30, 2017.

  

Production and Ad Valorem Taxes

 

Production and ad valorem taxes increased $0.2 million, or 12%, to $1.7 million for the three months ended June 30, 2018, from $1.5 million for the three months ended June 30, 2017. The increase in production and ad valorem taxes is attributable to the increase in oil and gas revenues.

 

Marketing and Transportation Expense

 

Marketing and transportation expense decreased $1.3 million, or 70%, to $0.5 million for the three months ended June 30, 2018, from $1.8 million for the three months ended June 30, 2017. The decrease in marketing and transportation expense is attributable to a net change in the production from leases that are burdened by marketing and transportation costs to leases that are not burdened by marketing and transportation costs. This change was caused by a sale of a portion of our interests in certain oil and natural gas properties and new production from existing properties.

  

 

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

 

Amortization of royalty and working interests in oil and natural gas properties expense decreased $4.9 million, or 48%, to $5.3 million for the three months ended June 30, 2018, from $10.2 million for the three months ended June 30, 2017. The decrease in amortization of royalty and working interests in oil and natural gas properties expense is attributable to decreased production and net reserves attributable to the sale of a portion of our interests in certain oil and natural gas properties.

 

General, Administrative and Other Expense

 

General, administrative and other expense increased $2.0 million, or 141%, to $3.5 million for the three months ended June 30, 2018, from $1.5 million for the three months ended June 30, 2017. The increase in general, administrative and other expense is attributable to the expenses related to the sale of a portion of our interests in certain oil and natural gas properties.

 

Comparison of the six months ended June 30, 2018 to the six months ended June 30, 2017

 

Oil and Gas Revenues

 

Oil and gas revenues decreased $1.1 million, or 2%, to $53.3 million for the six months ended June 30, 2018, from $54.4 million for the six months ended June 30, 2017. The decrease in oil and gas revenues is attributable to a decrease in oil, natural gas liquids and natural gas production caused by the sale of a portion of our interests in certain oil and natural gas properties offset by an increase in realized commodity prices. We received an average price of $65.73 per Bbl of oil, $2.85 per Mcf of gas and $22.53 per Bbl of natural gas liquids sold in the six months ended June 30, 2018 compared to $48.49 per Bbl of oil, $3.02 per Mcf of gas and $19.18 per Bbl of natural gas liquids sold during the six months ended June 30, 2017.

  

Production and Ad Valorem Taxes

 

Production and ad valorem taxes decreased $0.2 million, or 7%, to $3.0 million for the six months ended June 30, 2018, from $3.2 million for the six months ended June 30, 2017. The decrease in production and ad valorem taxes is attributable to the decrease in oil and gas revenues.

 

Marketing and Transportation Expense

 

Marketing and transportation expense decreased $2.7 million, or 70%, to $1.2 million for the six months ended June 30, 2018, from $3.9 million for the six months ended June 30, 2017. The decrease in marketing and transportation expense is attributable to a net change in the production from leases that are burdened by marketing and transportation costs to leases that are not burdened by marketing and transportation costs. This change was caused by a sale of a portion of our interests in certain oil and natural gas properties and new production from existing properties.

 

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

 

Amortization of royalty and working interests in oil and natural gas properties expense decreased $11.3 million, or 53%, to $10.1 million for the six months ended June 30, 2018, from $21.4 million for the six months ended June 30, 2017. The decrease in amortization of royalty and working interests in oil and natural gas properties expense is attributable to decreased production and net reserves attributable to the sale of a portion of our interests in certain oil and natural gas properties.

 

 

General, Administrative and Other Expense

 

General, administrative and other expense increased $3.0 million, or 96%, to $6.1 million for the six months ended June 30, 2018, from $3.1 million for the six months ended June 30, 2017. The increase in general, administrative and other expense is attributable to the expenses related to the sale of a portion of our interests in certain oil and natural gas properties.
 

Comparison of the year ended December 31, 2017 to the year ended December 31, 2016

 

Oil and Gas Sales

 

Oil and gas revenues increased $30.7 million, or 42%, to $104.3 million for the year ended December 31, 2017, from $73.6 million for the year ended December 31, 2016. The increase in oil and gas revenues is attributable to an increase in realized commodity prices, an increase in drilling activity, and an increase in oil, natural gas liquids and natural gas production. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes. We received an average of $50.10 per Bbl of oil, $20.63 per Bbl of natural gas liquids and $2.81 per Mcf of natural gas for the volumes sold during the year ended December 31, 2017 compared to an average of $39.91 per Bbl of oil, $12.04 per Bbl of natural gas liquids and $2.19 per Mcf of natural gas for the volumes sold during the year ended December 31, 2016.

 

Realized Gain on Hedging Activities

 

Realized gain on hedging activities increased $0.6 million, or 281%, to $0.8 million for the year ended December 31, 2017, from $0.2 million for the year ended December 31, 2016. The increase in realized gain on hedging activities is attributable to the increase in commodity prices of oil during 2017.

 

Unrealized Gain (Loss) on Hedging Activities

 

Unrealized gain (loss) on hedging activities increased $2.1 million, to a gain of $1.0 million for the year ended December 31, 2017, from a loss of $1.0 million for the year ended December 31, 2016. The increase in unrealized gain on hedging activities is attributable to the increase in the commodity prices of oil, natural gas liquids and natural gas during 2017.

 

Production and Ad Valorem Taxes

 

Production and ad valorem taxes increased $1.2 million, or 25%, to $6.0 million for the year ended December 31, 2017, from $4.8 million for the year ended December 31, 2016. The increase in production and ad valorem taxes is attributable to increased production and increased valuations for ad valorem tax.

 

Lease Operating Expense

 

Lease operating expense increased $0.2 million, or 53%, to $0.7 million for the year ended December 31, 2017, from $0.4 million for the year ended December 31, 2016. The increase in lease operating expense is attributable to increased production and development for our working interests in the Williston basin.

 

Marketing and Transportation Expense

 

Marketing and transportation expense increased $0.2 million, or 3%, to $6.9 million for the year ended December 31, 2017, from $6.7 million for the year ended December 31, 2016. The increase in marketing and transportation expense is attributable to increased production.

 

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

 

Amortization of royalty and working interests in oil and natural gas properties expense decreased $0.2 million, or 0.5%, to $37.1 million for the year ended December 31, 2017, from $37.3 million for year ended December 31, 2016. The decrease in amortization of royalty and working interests in oil and natural gas properties expense is attributable to the sale of a portion of our interests in certain oil and natural gas properties and an increase in reserves attributable to new wells offset by increased production volumes.

 

 

General, Administrative and Other Expense

 

General, administrative and other expense increased $2.1 million, or 34%, to $8.5 million for the year ended December 31, 2017, from $6.3 million for the year ended December 31, 2016. The increase in general, administrative and other expense is attributable to the expenses related to the sale of a portion of our interests in certain oil and natural gas properties.

 

Gain on Sale of Assets

 

Gain on sale of assets increased $31.4 million to $31.4 million for the year ended December 31, 2017, from $0 for the year ended December 31, 2016. The increase in other gain on sale of assets is attributable to the sale of a portion of our interests in certain oil and natural gas properties.

 

Other Income

 

Other income decreased $0.8 million, or 96%, to $0.03 million for the year ended December 31, 2017, from $0.8 million for the year ended December 31, 2016. The decrease in other income is attributable to the change in classification of lease bonuses and extensions as other income in 2016 to oil and gas sales in 2017.

 

Interest Expense

 

Interest expense decreased $0.5 million, or 14%, to $2.8 million for the year ended December 31, 2017, from $3.3 million for the year ended December 31, 2016. The decrease in interest expense is attributable to a $52.5 million repayment of long-term debt in 2016.

 

Comparison of the year ended December 31, 2016 to the year ended December 31, 2015

 

Oil and Gas Sales

 

Oil and gas revenues decreased $34.4 million, or 32%, to $73.6 million for the year ended December 31, 2016, from $108 million for the year ended December 31, 2015. The decrease in oil and gas revenues is attributable to a decrease in oil, natural gas liquids and natural gas production as well as a decrease in realized commodity prices. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes. We received an average of $39.91 per Bbl of oil, $12.04 per Bbl of natural gas liquids and $2.19 per Mcf of natural gas for the volumes sold during the year ended December 31, 2016 compared to an average of $46.12 per Bbl of oil, $13.07 per Bbl of natural gas liquids and $2.33 per Mcf of natural gas for the volumes sold during the year ended December 31, 2015.

 

Realized Gain on Hedging Activities

 

Realized gain on hedging activities increased $0.2 million to $0.2 million for the year ended December 31, 2016, from $0 for the year ended December 31, 2015. The increase in realized gain on hedging activities is attributable to the use of commodity hedges during 2016.

 

Unrealized Gain (Loss) on Hedging Activities

 

Unrealized gain (loss) on hedging activities decreased $1.0 million to a loss of $1.0 million for the year ended December 31, 2016, from $0 for the year ended December 31, 2015. The decrease in unrealized gain (loss) on hedging activities is attributable to the use of commodity hedges during 2016.

 

Production and Ad Valorem Taxes

 

Production and ad valorem taxes decreased $1.8 million, or 27%, to $4.8 million for the year ended December 31, 2016, from $6.5 million for the year ended December 31, 2015. The decrease in production and ad valorem taxes is attributable to a decrease in oil, natural gas liquids and natural gas production during 2016.

  

 

Lease Operating Expense

 

Lease operating expense increased $0.2 million, or 61%, to $0.4 million for the year ended December 31, 2016, from $0.3 million for the year ended December 31, 2015. The increase in lease operating expense is attributable to increased production for our working interests in the Williston basin.

 

Marketing and Transportation Expense

 

Marketing and transportation expense decreased $1.2 million, or 15%, to $6.7 million for the year ended December 31, 2016, from $7.9 million for the year ended December 31, 2015. The decrease in marketing and transportation expense is attributable to decreased production.

 

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

 

Amortization of royalty and working interests in oil and natural gas properties expense decreased $9.3 million, or 20%, to $37.3 million for the year ended December 31, 2016, from $46.5 million for year ended December 31, 2015. The decrease in amortization of royalty and working interests in oil and natural gas properties expense is attributable to a decrease in oil, natural gas liquids and natural gas production.

 

General, Administrative and Other Expense

 

General, administrative and other expense decreased $5.9 million, or 48%, to $6.3 million for the year ended December 31, 2016, from $12.2 million for the year ended December 31, 2015. The decrease in general, administrative and other expense is attributable to non-recurring expenses incurred in 2015 related to a potential initial public offering of certain Royal assets in addition to higher management fees in 2015.

 

Other Income

 

Other income increased $0.4 million, or 89%, to $0.8 for the year ended December 31, 2016, from $0.4 million for the year ended December 31, 2015. The increase in other income is attributable to higher lease bonuses and extensions in 2016.

 

Interest Expense

 

Interest expense decreased $2.2 million, or 40%, to $3.3 million for the year ended December 31, 2016, from $5.5 million for the year ended December 31, 2015. The decrease in interest expense is attributable to a $52.5 million repayment of long-term debt in 2016.

  

LIQUIDITY AND CAPITAL RESOURCES

 

Overview

 

Our primary sources of liquidity have historically been cash flows from operations and equity and debt financings, and our primary uses of cash have historically been for replacement and growth capital expenditures, including the acquisition of oil and natural gas properties.

 

Cash Flows

 

The following table presents our cash flows for the period indicated.

 

		Six Months Ended								Year Ended
		June 30,								December 31,
(in thousands)		2018				2017				2017				2016				2015
Cash Flow Data:
Cash flows provided by operating activities		$	38,836			$	40,623			$	80,791			$	51,279			$	88,197
Cash flows provided by (used in) investing activities			120,590				(2,054	)			83,048				(5,260	)			(8,100	)
Cash flows used in financing activities			(134,535	)			(31,000	)			(161,390	)			(76,225	)			(76,563	)
Net increase (decrease) in cash		$	24,891			$	7,569			$	2,449			$	(30,206	)		$	3,534

 

 

Operating Activities

 

Our operating cash flow has historically been sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. 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.

 

Cash flow provided by operating activities for the six months ended June 30, 2018 did not meaningfully change from the cash provided from operating activities for the six months ended June 30, 2017.

 

The increase in cash flow provided by operating activities in the year ended December 31, 2017 as compared to the year ended December 31, 2016 is attributable to higher production from our oil and natural gas properties related to new wells and increased commodity prices of oil, natural gas liquids and natural gas during 2017.

 

The decrease in cash flow provided by operating activities in the year ended December 31, 2016 as compared to the year ended December 31, 2015 is attributable to a reduction in net income before amortization of royalty and working interest in oil and natural gas properties during 2016 and a $0.7 million increase in accounts receivable in 2016 compared a $12.5 million decrease in accounts receivable in 2015.

 

 Investing Activities

 

Cash provided by investing activities for the six months ended June 30, 2018 was $120.6, as a result of proceeds from the sale of assets of $120.9 million and $0.3 million used for additions to oil and natural gas properties. Cash used in investing activities for the six months ended June 30, 2017 was $2.0 million, as a result of $2.1 million used for additions to oil and natural gas properties offset by a $0.1 million decrease in advances to operators.

 

Cash provided by investing activities for the year ended December 31, 2017 was $83.0 million, as a result of $86.3 million from proceeds from the sale of assets, $3.5 million used for additions to oil and natural gas properties and $0.2 million from a decrease in advances to operators.

 

Cash used in investing activities for the year ended December 31, 2016 was $5.3 million, a result of $5.0 million used for additions to oil and natural gas properties and $0.2 million used in advances to operators.

 

Cash used in investing activities for the year ended December 31, 2015 was $8.1 million, a result of additions to oil and natural gas properties.

 

Financing Activities

 

Cash used in financing activities for the six months ended June 30, 2018 was $134.5 million and was a result of partner distributions of $107.5 million and a $27 million repayment of long-term debt. Cash used in financing activities for the six months ended June 30, 2017 was $31 million and was a result of partner distributions of $30 million and a $1 million repayment of long-term debt.

 

Cash used in financing activities for the year ended December 31, 2017 was $161.4 million, a result of $1 million from repayment of long-term debt and $160.4 million used in partner distributions.

 

 

Cash used in financing activities for the year ended December 31, 2016 was $76.2 million, a result of partner distributions of $23.6 million, $0.05 million of partner contributions, $52.5 million from the repayment of long-term debt and related debt issuance costs that were being amortized.

 

Cash used in financing activities for the year ended December 31, 2015 was $76.6 million, a result of distributions to partners during the year.

 

Indebtedness

 

Old Credit Facilities

 

Royal’s historical primary sources of indebtedness are its first lien credit facility, which it entered into in October 2012, and Royal’s RNR credit facility:

 

●

First lien credit facility: As of December 31, 2017, the borrowing base on the first lien credit facility was $57 million. As of June 30, 2018, the borrowing base on the first lien credit facility was $30 million. The borrowing base is re-determined semi-annually. Borrowings are either at LIBOR or at the Base Rate, at Royal’s option, plus a variable credit spread. The variable credit spread is based on the percentage of the borrowing base utilized. The outstanding principal is due October 19, 2020.

 

●

RNR credit facility: As of December 31, 2017 and June 30, 2018, the borrowing base on the RNR credit facility was $2 million. Borrowings are between 7% and 9% for LIBOR-based loans, and between 6% and 8% for Base Rate loans. The interest rate is based on the percentage of the borrowing base utilized. The outstanding principal is due November 21, 2019. The RNR credit facility was incurred by Riverbend Natural Resources, LP, which will not be contributed in the transaction contemplated by the Proxy Statement.

 

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

 

New Credit Facility

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

 

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

 

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

 

 

CONTRACTUAL OBLIGATIONS

 

The following tables present our contractual obligations and other commitments as of December 31, 2017 and June 30, 2018:

  

		Payments Due by Period – as of December 31, 2017
		Total				2018				2019				2020				2021				Thereafter
Long-term debt		$	58,000				—			$	1,000			$	57,000				—				—
Total		$	58,000				—			$	1,000			$	57,000				—				—

 

		Payments Due by Period – as of June 30, 2018
		Total				2018				2019				2020				2021				Thereafter
Long-term debt		$	31,000				—			$	1,000			$	30,000				—				—
Total		$	31,000				—			$	1,000			$	30,000				—				—

 

CRITICAL ACCOUNTING POLICIES

 

The discussion and analysis of our historical financial condition and results of operations are based upon our audited and unaudited consolidated financial statements, incorporated by reference herein to the Proxy Statement, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

 

Management Estimates

 

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

 

Royalty and Working Interests in Oil and Natural Gas Properties

 

Royalty and working interests include acquired interests in production, development, and exploration stage properties. We followed the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. Oil and natural gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Lease rentals are expensed as incurred.

 

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

 

 

Impairment of Royalty and Working Interests in Oil and Natural Gas Properties

 

We review and evaluate our royalty and working interests in oil and natural gas properties for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. Our estimates of recoverability and fair value are based on numerous assumptions and it is possible that actual results will be significantly different than the estimates, as actual future quantities of recoverable oil and natural gas, commodity prices, production levels, operating costs, and taxes associated with production of oil and natural gas reserves are each subject to significant risks and uncertainties. The carrying value of exploration stage interests are evaluated for impairment when information becomes available indicating that production will not occur in the future. When required, impairment losses are recognized based on the fair value of the assets. No such impairment expense was recorded for the six months ended June 30, 2018 or 2017 and the years ended December 31, 2017, 2016 or 2015.

 

Asset Retirement Obligations

 

Our asset retirement obligations (“ARO”) relate to our working interests in the Williston basin and represent the future abandonment costs of working interests in tangible assets, namely the plugging and abandonment of wells and land remediation. The fair value of a liability for an asset’s retirement is recognized in the period in which it is incurred and becomes determinable, with an offsetting increase in the carrying amount of the associated asset. The cost of the tangible assets, including the initially recognized ARO, is depleted over the useful life of the asset. The ARO are recorded at fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.

 

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including, but not limited to: the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance.

 

Revenue Recognition

 

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

 

Inflation

 

Inflation did not have a material impact on results of operations for the periods presented.

 

Off-Balance Sheet Arrangements

 

We had no off-balance sheet arrangements as of June 30, 2018.

  

QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

 

Commodity Price Risk

 

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

 

Revenue Concentration Risk

 

We are subject to risk resulting from the concentration of oil and gas revenues in producing oil and natural gas properties and receivables with several significant purchasers. For the year ended December 31, 2017, we received approximately 28%, 18%, 18% and 15% of our revenue from Devon, EOG, BHP, and ConocoPhillips, respectively. For the six months ended June 30, 2018, we received approximately 35%, 24%, and 18% of our revenue from ConocoPhillips, EOG, and Devon, respectively. We did not require collateral and did not believe the loss of any single purchaser would materially impact our operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.