SITIO ROYALTIES CORP. You should read the following discussion of our historical performance and financial condition together with Part II, Item 6. "Selected Financial Data," the description of the business appearing in Part I, Item 1. "Business," and the consolidated financial statements and the related notes in Part II, Item 8. of this Annual Report. This discussion may contain 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. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in Part I, Item 1A. "Risk Factors" and under "Cautionary Statement Regarding Forward-Looking Statements."
Overview
We were formed to own and acquire Royalties in oil and natural gas properties inNorth America , substantially all of which are located in theEagle 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 or pay capital expenditures such as plugging and abandonment costs. We have minimal allocated lease operating expenses. As such, we have historically operated with high cash margins, converting a large percentage of revenue to free cash flow, the majority of which can be distributed to our stockholders.
Recent Developments
None.
Factors Impacting the Comparability of Our Financial Results
Public Company Expenses. We incur direct G&A expense as a result of being a publicly traded company, including, but not limited to, costs associated with hiring new personnel, implementation of compensation programs that are competitive with our public company peer group, annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs, independent director compensation and other similar costs. 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 forU.S. federal income tax purposes and for purposes of certain state and local income taxes. Royal was not subject toU.S. federal income taxes. However, Royal was subject to theTexas 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 toU.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. 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 ofDecember 31, 2019 , our Royalties represented the right to receive an average of 1.32% from the producing wells on the underlying acreage at the sales price received by our operators net of any applicable post-production expenses and taxes. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Oil, natural gas liquids and natural gas prices have historically been volatile, and atDecember 31, 2019 , we did not hedge any of our exposure to changes in commodity prices. During the twelve months endedDecember 31, 2018 ,West Texas Intermediate posted prices that ranged from$49.98 to$70.76 per Bbl and the Henry Hub settlement price of natural gas ranged from$2.64 to$4.72 per MMBtu. During the twelve months endedDecember 31, 2019 , the West Texas Intermediate posted prices that ranged from$51.55 to$63.87 per Bbl for crude oil and the Henry Hub settlement price of natural gas ranged from$2.14 to$3.64 per MMBtu for natural gas. 36
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The following table presents the breakdown of our revenue for the following
periods:
Year Ended December 31,
2019 2018 2017
Royalty Income:
Oil sales 77 % 81 % 77 %
Natural gas sales 14 % 12 % 12 %
Natural gas liquids sales 7 % 7 % 11 %
Lease bonus 2 % 0 % 0 %
Total 100 % 100 % 100 %
Commodity prices are inherently volatile, and changes in such prices have
historically had an impact on our revenue. Lower prices may not only decrease
our revenues, but also potentially the amount of oil and natural gas that our
operators can produce economically. Lower oil and natural gas prices may also
result in a reduction in the borrowing base under our credit agreement, which
may be redetermined at the discretion of our lenders.
The following table sets forth the average realized prices for oil, natural gas
and natural gas liquids for the years ended December 31, 2019 , 2018 and 2017:
Year Ended December 31,
2019 2018 2017
Oil (Bbls) $ 59.85 $ 67.14 $ 50.54
Natural gas (Mcf) $ 2.62 $ 3.10 $ 2.81
Natural gas liquids (Bbls) $ 15.45 $ 25.62 $ 20.63 Principal Components of Our Cost Structure
Production and Ad Valorem Taxes
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
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. Amortization
Our Royalties are recorded at cost and capitalized as tangible assets. Acquisition costs related to proved properties are amortized on a units of production basis over the life of the proved reserves.
General and Administrative
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 inAugust 2018 , we incurred incremental G&A expenses relating to expenses associated withSEC 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 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 andRiverbend 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 onDecember 10, 2018 . The Company has assumed the day-to-day management of the Company since the expiration of the MSA with Riverbend. 37 --------------------------------------------------------------------------------
Interest Expense
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 Tax Expense
Income taxes reflect the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or settled. Deferred income taxes are also recognized for tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying current tax rates to the differences between financial statement and income tax reporting. In assessing the realization of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income and tax planning strategies in making this assessment. We will continue to evaluate whether the valuation allowance is needed in future reporting periods. We are subject to taxation in many jurisdictions, and the calculation of our income tax liabilities involves dealing with uncertainties in the application of complex income tax laws and regulations in various taxing jurisdictions. We recognize certain income tax positions that meet a more-likely-than not recognition threshold. If we ultimately determine that the payment of these liabilities will be unnecessary, we will reverse the liability and recognize an income tax benefit during the period in which we determine the liability no longer applies. Royal was historically treated as a partnership for federal income tax purposes, with each partner being separately taxed on its share of taxable income; therefore, there is no federal income tax expense reflected in Royal's financial statements for any period prior to the Closing of the Transactions onAugust 23, 2018 .
Overview of Our Results of Operations
Basis of Presentation
The following financial information include information regardingRoyal Resources L.P. as Falcon's predecessor entity, which includes certain interests in subsidiary companies which were not acquired by the Company in the Transactions.The Royal Resources L.P. subsidiaries that were contributed in the Transactions areVickiCristina, LP ,DGK ORRI Company, L.P. ,Noble EF DLG LP ,Noble EF LP andNoble Marcellus LP . The interests in Riverbend Natural Resources, L.P ("RNR") andKGD ORRI, L.P. were not contributed in the Transactions. Thus, the financial results included in this Annual 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. 38 --------------------------------------------------------------------------------
The following table summarizes our revenue and expenses and production data for the periods indicated (in thousands, except production data).
Year Ended December 31,
2019 2018 2017
Revenues:
Oil and gas sales $ 68,463 $ 98,655 $ 95,972
Gain (loss) on hedging activities - (1,456 ) 1,791
Total revenue 68,463 97,199
97,763
Operating expenses:
Production and ad valorem taxes 4,262 5,143
5,242
Marketing and transportation 2,396 2,368
6,505
Amortization of royalty interests in oil and 12,737 16,962
33,837
natural gas properties
General, administrative and other 11,912 9,544 8,213 Total operating expenses 31,307 34,017 53,797 Operating income 37,156 63,182 43,966 Other income (expense): Gain on the sale of assets - 41,382 31,441 Other income 165 46 34 Interest expense (2,489 ) (2,350 ) (2,746 ) Total other income (expense) (2,324 ) 39,078 28,729 Income before income taxes 34,832 102,260 72,695 Provision for income taxes 3,918 3,292 - Income from continuing operations 30,914 98,968
72,695
Income (loss) from discontinued operations - 2,139
2,978
Net income 30,914 101,107
75,673
Net income attributable to non-controlling (16,564 ) (10,982 ) (155 )
interests
Net income attributable to common$ 14,350 $ 90,125 $ 75,518 shareholders/unitholders Other Financial Data: Adjusted EBITDA (1)$ 52,607 $ 80,190 $ 77,837
(1) Adjusted EBITDA is a non-GAAP financial measure. For additional information
regarding our calculation of Adjusted EBITDA as well as a reconciliation of
net income to Adjusted EBITDA, please see "Overview of Our Results of
Operations-Adjusted EBITDA" below.
39
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For the Year Ended
December 31,
2019 2018 2017
Production Data:
Oil (Bbls) 879,288 1,237,813 1,582,322
Natural gas (BOE) 598,019 686,279 760,982
Natural gas liquids (Bbls) 296,813 293,086 542,706
Combined volumes (BOE) 1,774,120 2,217,178 2,886,010Average daily combined volume (BOE/d) 4,861 6,074 7,907 % Oil 50 % 56 % 55 % Average sales prices: Oil (Bbls)$ 59.85 $ 67.14 $ 50.54 Natural gas (Mcf)$ 2.62 $ 3.10 $ 2.81 Natural gas liquids (Bbls)$ 15.45 $ 25.62 $ 20.63 Combined per (BOE)$ 37.54 $ 46.63 $ 35.67 Average Costs ($/BOE): Production and ad valorem taxes$ 2.40 $ 2.32 $ 1.82 Gathering and transportation expense$ 1.35 $ 1.07 $ 2.25 General and administrative$ 6.71 $ 4.30 $ 2.85 Interest expense, net$ 1.40 $ 1.06 $ 0.95 Depletion$ 7.18 $ 7.65 $ 11.72
Comparison of Year Ended
Oil and Gas Revenues
Oil and gas revenues decreased$30.2 million , or 31%, to$68.5 million for the year endedDecember 31, 2019 , from$98.7 million for the year endedDecember 31, 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. InMarch 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 throughDecember 31, 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$59.85 per Bbl of oil and$2.62 per Mcf of gas sold during the year endedDecember 31, 2019 compared to$67.14 per Bbl of oil and$3.10 per Mcf of gas sold during the year endedDecember 31, 2018 .
Production and Ad Valorem Taxes
Production and ad valorem taxes decreased$0.9 million , or 17%, to$4.3 million for the year endedDecember 31, 2019 , from$5.1 million for the year endedDecember 31, 2018 . The decrease in production and ad valorem taxes was attributable to the decrease in production. As a percentage of oil and gas revenue, production and ad valorem taxes was 6% for the year endedDecember 31, 2019 compared to 5% for the year endedDecember 31, 2018 . The increase during the year endedDecember 31, 2019 was partially related to approximately$0.7 million increase in ad valorem taxes assessed on our properties compared to the prior year.
Marketing and Transportation Expense
Marketing and transportation expense decreased by less than$0.1 million or 1%, to$2.4 million for the year endedDecember 31, 2019 , from$2.4 million for the year endedDecember 31, 2018 . As a percentage of revenue, marketing and transportation expense was 3% during the year endedDecember 31, 2019 as compared to 2% for same period in the prior year. Marketing and transportation expense as a percentage of revenue was lower during the year endedDecember 31, 2018 due to certain oil and gas interests that the Company owns in the EagleFord 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 Natural Gas Properties Expense
Amortization of royalty interests in oil and natural gas properties expense decreased$4.2 million , or 25%, to$12.7 million for the year endedDecember 31, 2019 , from$17.0 million for the year endedDecember 31, 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 year endedDecember 31, 2019 . 40 --------------------------------------------------------------------------------
General, Administrative and Other Expense
General, administrative and other expense increased by$2.4 million , or 25%, to$11.9 million for the year endedDecember 31, 2019 , from$9.5 million for the year endedDecember 31, 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$2.5 million in non-cash stock-based compensation expense during 2019 in connection with the implementation of our long-term incentive plan.
Interest Expense
Interest expense increased by$0.1 million , or 6%, to$2.5 million for the year endedDecember 31, 2019 , from$2.4 million for the year endedDecember 31, 2018 . The increase in interest expense was attributable to greater average outstanding borrowings partially offset by lower interest rates under our Credit Facility. Income Taxes Income tax expense increased to$3.9 million for the year endedDecember 31, 2019 , compared to$3.3 million for the year endedDecember 31, 2018 . The increase in income taxes was attributable to the Company only incurring income taxes for a portion of the prior year because the Transactions did not take place untilAugust 23, 2018 . Prior to the Transactions, Royal was treated as a partnership and was not subject to income taxes.
Comparison of the Year Ended
Oil and Gas Revenues Oil and gas revenues increased$2.7 million , or 3%, to$98.7 million for the year endedDecember 31, 2018 , from$96.0 million for the year endedDecember 31, 2017 . The increase in oil and gas revenues was attributable to a net increase in realized commodity prices offset by a decrease in oil, natural gas liquids and natural gas production caused by the sale of a proportion of our interests in certain oil and natural gas properties inFebruary 2018 .
Production and Ad Valorem Taxes
Production and ad valorem taxes decreased
Marketing and Transportation Expense
Marketing and transportation expense decreased$4.1 million , or 64%, to$2.4 million for the year endedDecember 31, 2018 , from$6.5 million for the year endedDecember 31, 2017 . The decrease in marketing and transportation expense was attributable to a net change in the production from leases that are burdened by marketing and transportation costs to leases that are not burdened by marketing and transportation costs. This change was caused by a sale of a portion of our interests in certain oil and natural gas properties inFebruary 2018 and new production from existing properties.
Amortization of Royalty Interests in Oil and Natural Gas Properties Expense
Amortization of royalty interests in oil and natural gas properties expense decreased$16.9 million , or 50%, to$17.0 million for the year endedDecember 31, 2018 , from$33.8 million for the year endedDecember 31, 2017 . The decrease in amortization of royalty interests in oil and natural gas properties expense was attributable to decreased production and amortization expense attributable to a portion of our interests in certain oil and natural gas properties that were sold during Q4 2017 and Q1 2018 that had a high amortization rate.
General, Administrative and Other Expense
General, administrative and other expense increased by$1.3 million , or 16%, to$9.5 million for the year endedDecember 31, 2018 , from$8.2 million for the year endedDecember 31, 2017 . The increase in general, administrative and other expense was attributable to the change in management related to the Transactions as the Company is in the process of building its employee base to support the business. Interest Expense Interest expense decreased by$0.4 million , or 14%, to$2.4 million for the year endedDecember 31, 2018 , from$2.7 million for the year endedDecember 31, 2017 . The decrease is interest expense was attributable to the extinguishment of the Royal indebtedness at the closing of the Transactions, along with a lower average debt drawn during the year. 41 --------------------------------------------------------------------------------
Income Taxes
Income tax expense increased by$3.3 million for the year endedDecember 31, 2018 , from$0.0 million for the year endedDecember 31, 2017 . The increase in income taxes was attributable to Royal historically being treated as a partnership which changed as a part of the Transactions. Falcon is treated as aC-Corp and accordingly is subject to federal income taxes.
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure used by management
and external users of our financial statements, such as industry analysts,
investors, lenders and rating agencies. We believe Adjusted EBITDA is useful
because it allows us to evaluate our performance and compare the results of our
operations period to period without regard to our financing methods or capital
structure. In addition, management uses Adjusted EBITDA to evaluate cash flow
available to pay dividends to our common 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).
Year Ended December 31,
2019 2018 2017
Net income $ 30,914 $ 101,107 $ 75,673
Income attributable to discontinued operations - (2,139 ) (2,978 )
Interest expense, net 2,489 2,350 2,746
Depletion 12,737 16,962 33,837
Income taxes 3,918 3,292 -
Gain on the sale of assets - (41,382 ) (31,441 )
Share based compensation 2,549 - -
Adjusted EBITDA $ 52,607 $ 80,190 $ 77,837 Liquidity and Capital Resources
Overview
Our primary sources of liquidity have historically been cash flows from
operations and equity and debt financings, and our primary uses of cash are for
dividends and for the acquisition of additional Royalties. 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.
42
--------------------------------------------------------------------------------The following table presents cash distributions approved by the Board of Directors of our general partner for the periods presented.
Total
Quarterly
Dividend Total Cash Shareholders
Quarter Ended Per Share Dividends Payment Date Record Date
December 31, 2019 $ 0.1350 $ 6,205 March 9, 2020 February 25, 2020
September 30, 2019 $ 0.1350 $ 6,203 December 3, 2019 November 20, 2019
June 30, 2019 $ 0.1500 $ 6,879 September 6, 2019 August 26, 2019
March 31, 2019 $ 0.1750 $ 8,026 May 29, 2019 May 17, 2019
December 31, 2018 $ 0.2000 $ 9,171 February 28, 2019 February 21, 2019
September 30, 2018(1) $ 0.0950 $ 4,356 November 15, 2018 November 8, 2018
(1) Represents the initial pro rata distribution of our quarterly dividend for
the period from August 23, 2018 through September 30, 2018 .
Indebtedness
Falcon Credit Facility
On the Closing Date, we entered into a credit facility with Citibank, N.A ., as
administrative agent and collateral agent for the lenders from time to time
party thereto (the "Credit Facility"). The Credit Facility provides for a
maximum credit amount of $500.0 million and a borrowing base based on our oil
and natural gas reserves and other factors of $90.0 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 November 8, 2019 , in connection with the Company's
fall 2019 redetermination, the borrowing base decreased from $105.0 million to
$90 million and, as of December 31, 2019 , the Company had borrowings of $42.5
million under the Credit Facility at an interest rate of 4.05% and $47.5 million
available for future borrowings under the Credit Facility.
Principal amounts borrowed are payable on the maturity date. We have a choice of
borrowing at the base rate or LIBOR, with such borrowings bearing interest,
payable quarterly in arrears for base rate loans and one month, two-month, three
month or six-month periods for LIBOR loans. LIBOR loans bear interest at a rate
per annum equal to the rate appearing on the Reuters Reference LIBOR01 or
LIBOR02 page as the LIBOR, for deposits in dollars at 12:00 noon (London,
England time) for one, two, three, or six months plus an applicable margin
ranging from 200 to 300 basis points. Base rate loans bear interest at a rate
per annum equal to the greatest of (i) the agent bank's reference rate, (ii) the
federal funds effective rate plus 50 basis points and (iii) the rate for
one-month LIBOR loans plus 1%, plus an applicable margin ranging from 100 to 200
basis points. The scheduled redeterminations of our borrowing base take place on
April 1st and October 1st 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 ofDecember 31, 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 "Note 6 - Debt - Royal Credit Facilities." 43 --------------------------------------------------------------------------------
Cash Flows
Year Ended
A summary of the changes in cash flow data for the years endedDecember 31, 2019 and 2018 are set forth in the following table (in thousands, except percentages): Year Ended December 31, 2019 2018 $ Change % Change Net cash flows provided by (used in): Operating activities$ 55,229 $ 77,886 $ (22,657 ) -29% Investing activities (23,353 ) 122,312 (145,665 ) -119% Financing activities (36,650 ) (203,378 ) 166,728 -82% Cash Flow from Operating Activities. Our operating cash flow has historically been sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas for which we receive royalty revenue. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. The decrease in cash flow provided by operating activities for the year endedDecember 31, 2019 as compared to the year endedDecember 31, 2018 was primarily related to a 29% decrease in oil production, a 13% decrease in natural gas production coupled with a 11% decrease in realized oil prices and a 15% 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. Cash Flow from Investing Activities. Investing activities are primarily related to the acquisition and disposition of oil and natural gas interests. Cash used in investing activities for the year endedDecember 31, 2019 was$23.4 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 year endedDecember 31, 2018 was$122.3 million and the majority was related to the sale of certain interests in our oil and natural gas properties inFebruary 2018 . Cash Flow from Financing Activities. Cash used in financing activities for the year endedDecember 31, 2019 was$36.7 million , primarily related to dividends and distributions totaling$58.0 million partially offset by a net increase in borrowings under our Credit Facility of$21.5 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 year endedDecember 31, 2018 was$203.4 million , primarily related to dividends and distributions totaling$159.4 million and debt repayments of$44.0 million .
Year Ended
A summary of the changes in cash flow data for the years endedDecember 31, 2018 and 2017 are set forth in the following table (in thousands, except percentages): Year Ended December 31, 2018 2017 $ Change % Change Net cash flows provided by (used in): Operating activities$ 77,886 $ 80,791 $ (2,905 ) -4 % Investing activities 122,312 83,048 39,264 47 % Financing activities (203,378 ) (161,390 ) (41,988 ) 26 % Cash Flow from Operating Activities. Our operating cash flow has historically been sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas for which we receive royalty revenue. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. The decrease in cash flow provided by operating activities for the year endedDecember 31, 2018 as compared to the year endedDecember 31, 2017 was attributable to an increase in net income of$25.4 million , non-cash charges of$2.2 million related to hedging activities and$2.3 million related to deferred income taxes offset by non-cash charges of$9.9 million associated with the increase in the gains on sale of assets and a decrease in depletion of$18.5 million attributable to the sale of certain assets that occurred in Q4 2017 and Q1 2018. In addition, the operating cash flows had a decrease in working capital of$3.3 million . The net changes in working 44 --------------------------------------------------------------------------------
capital were primarily driven by the timing of collection of accounts receivables and the timing of payments of accounts payable and accrued expenses.
Cash Flow from Investing Activities. Investing activities are primarily related to the acquisition and disposition of oil and natural gas interests. Cash provided by investing activities for the year endedDecember 31, 2018 was$122.3 million and the majority was related to the sale of certain interests in our oil and natural gas properties inFebruary 2018 . Cash provided by investing activities for the year endedDecember 31, 2017 was$83.0 million and the majority was related to the sale of certain interests in our oil and natural gas properties inDecember 2017 . Cash Flow from Financing Activities. Cash used in financing activities for the year endedDecember 31, 2018 was$203.4 million , primarily related to dividends and distributions totaling$159.4 million and debt repayments of$44.0 million . Cash used in financing activities for the year endedDecember 31, 2017 was$161.4 million , primarily attributed to$160.4 million of distributions and debt repayments of$1.0 million . Contractual Obligations We have contractual obligations that are required to be settled in cash. Our contractual obligations as ofDecember 31, 2019 were as follows (in thousands): Payments Due by Period Less than 1 to 3 3 to 5 More than Total 1 year years years 5 years
Long-term debt obligations
Operating lease obligations 992 309 432 214 37 Total$ 43,492 $ 309 $ 432 $ 42,714 $ 37
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements.
Recently Issued Accounting Pronouncements
For a discussion of recently issued accounting pronouncements that will affect us, see "Note 2-Summary of Significant Accounting Policies-Recently Issued Accounting Pronouncements" to our accompanying consolidated financial statements for the fiscal year endedDecember 31, 2019 .
Critical Accounting Policies and Estimates
Management Estimates
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of management estimates and assumptions relate to amortization calculations, and estimates of fair value for long-lived assets, and reserves for contingencies and litigation. Management based its estimates on historical experience and on various other assumptions that were believed to be reasonable under the circumstances. Actual results could differ from these estimates.
Royalty Interests in
Royalty interests include acquired interests in production, development, and exploration stage properties. We follow the successful efforts method of accounting. Under this method, costs to acquire mineral and royalty interests in oil and natural gas properties are capitalized when incurred. Acquisition costs of proven royalty interests are amortized using the units of production method over the life of the property, which is estimated using proven reserves. Acquisition costs of royalty interests on exploration stage properties, where there are no proven reserves, are not amortized. At such time as the associated unproved 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.
Oil and Natural Gas Reserve Quantities
Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net cash flows. TheSEC has defined proved reserves as the estimated quantities of oil and natural gas which geological and engineering 45 -------------------------------------------------------------------------------- data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Impairment of Royalty Interests in
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. 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. No such impairment expense was recorded for the years endedDecember 31, 2019 or 2018.
Revenue Recognition
Revenues from our Royalties represent the right to receive revenues from oil, natural gas and NGL sales obtained by the operator of the wells in which the Company owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser. Virtually all of the pricing provisions in the Company's contracts are tied to a market index. Royalty interest and revenue recognition related accounting policies are defined and described more fully in Note 2-Summary of Significant Accounting Policies to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.
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