Kimbell Royalty Partners (KRP) 10-K 9 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 02, 2018	Jun. 30, 2017
Document and Entity Information
Entity Registrant Name	Kimbell Royalty Partners, LP
Entity Central Index Key	1,657,788
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Well-known Seasoned Issuer	No
Entity Filer Category	Non-accelerated Filer
Entity Public Float			$ 212.2
Entity Common Stock, Shares Outstanding		16,836,453
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 5,625,495
Oil, natural gas and NGL receivables	6,792,837
Accounts receivable and other current assets	236,673
Total current assets	12,655,005
Property and equipment, net	165,232
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting	297,609,797
Less: accumulated depreciation, depletion, accretion and impairment	(15,394,238)
Total oil and natural gas properties	282,215,559
Loan origination costs, net	255,208
Total assets	295,291,004
Current liabilities
Accounts payable	316,486
Other current liabilities	1,746,662
Commodity derivative liabilities	183,957
Total current liabilities	2,247,105
Long-term debt	30,843,593
Commodity derivative liabilities	134,872
Total liabilities	33,225,570
Commitments and contingencies
Partners' capital	262,065,434
Total liabilities and partners' capital	$ 295,291,004
Predecessor
Current assets
Cash and cash equivalents		$ 505,880
Oil, natural gas and NGL receivables		474,103
Accounts receivable and other current assets		344,368
Total current assets		1,324,351
Property and equipment, net		261,568
Oil and natural gas properties
Oil and natural gas properties, using full cost method of accounting		70,888,121
Less: accumulated depreciation, depletion, accretion and impairment		(51,948,355)
Total oil and natural gas properties		18,939,766
Loan origination costs, net		13,046
Total assets		20,538,731
Current liabilities
Accounts payable		1,030,862
Other current liabilities		112,508
Asset retirement obligations		27,013
Total current liabilities		1,170,383
Asset retirement obligations		14,468
Other liabilities		123,158
Long-term debt		10,598,860
Total liabilities		11,906,869
Commitments and contingencies
Predecessor members' equity		8,631,862
Total liabilities and members' equity		$ 20,538,731

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($)	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil, natural gas and NGL revenues		$ 30,665,092
Loss on commodity derivative instruments		(318,829)
Total revenues		30,346,263
Costs and expenses
Production and ad valorem taxes		2,452,058
Depreciation, depletion and accretion expenses		15,546,341
Impairment of oil and natural gas properties		0
Marketing and other deductions		1,648,895
General and administrative expenses		8,191,792
Total costs and expenses		27,839,086
Operating income (loss)		2,507,177
Other expense
Interest expense		791,437
Income (loss) before income taxes		1,715,740
Net income (loss)		$ 1,715,740
Net income (loss) attributable to common unit:
Net income (loss) attributable to common units per unit (basic)		$ 0.11
Net income (loss) attributable to common units per unit (diluted)		$ 0.10
Weighted average number of common units outstanding
Weighted average number of common units outstanding Basic (in units)		16,336,871
Weighted average number of common units outstanding Diluted (in units)		16,455,602
Predecessor
Oil, natural gas and NGL revenues	$ 318,310		$ 3,606,659	$ 4,684,923
Total revenues	318,310		3,606,659	4,684,923
Costs and expenses
Production and ad valorem taxes	19,651		280,474	426,885
Depreciation, depletion and accretion expenses	113,639		1,604,208	4,008,730
Impairment of oil and natural gas properties			4,992,897	28,673,166
Marketing and other deductions	110,534		750,792	747,264
General and administrative expenses	532,035		1,746,218	1,789,884
Total costs and expenses	775,859		9,374,589	35,645,929
Operating income (loss)	(457,549)		(5,767,930)	(30,961,006)
Other expense
Interest expense	39,307		424,841	385,119
Income (loss) before income taxes	(496,856)		(6,192,771)	(31,346,125)
State income taxes			19,848	(32,199)
Net income (loss)	$ (496,856)		$ (6,212,619)	$ (31,313,926)
Net income (loss) attributable to common unit:
Net income (loss) attributable to common units per unit (basic)	$ (0.82)		$ (10.28)	$ (51.83)
Net income (loss) attributable to common units per unit (diluted)	$ (0.82)		$ (10.28)	$ (51.83)
Weighted average number of common units outstanding
Weighted average number of common units outstanding Basic (in units)	604,137		604,137	604,137
Weighted average number of common units outstanding Diluted (in units)	604,137		604,137	604,137

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL AND PREDECESSOR MEMBERS' EQUITY	USD ($)shares
Members' equity, beginning balance (Predecessor) at Dec. 31, 2014	$ 48,197,616
Members' equity, beginning balance (in units) (Predecessor) at Dec. 31, 2014 | shares	604,137
Increase (Decrease) in Partners' Capital
Distributions to members | Predecessor	$ (3,249,327)
Unit-based compensation | Predecessor	605,059
Net income (loss) | Predecessor	(31,313,926)
Members' equity, ending balance (Predecessor) at Dec. 31, 2015	$ 14,239,422
Members' equity, ending balance (in units) (Predecessor) at Dec. 31, 2015 | shares	604,137
Increase (Decrease) in Partners' Capital
Unit-based compensation | Predecessor	$ 605,059
Net income (loss) | Predecessor	(6,212,619)
Members' equity, ending balance (Predecessor) at Dec. 31, 2016	$ 8,631,862
Members' equity, ending balance (in units) (Predecessor) at Dec. 31, 2016 | shares	604,137
Increase (Decrease) in Partners' Capital
Unit-based compensation | Predecessor	$ 50,422
Net income (loss) | Predecessor	(496,856)
Transfer of membership units to Rivercrest Royalties Holdings, LLC | Predecessor	$ (98,988)
Transfer of membership units to Rivercrest Royalties Holdings, LLC (in units) | Predecessor | shares	(604,137)
Partners' capital, ending balance at Feb. 07, 2017	$ 8,086,440
Increase (Decrease) in Partners' Capital
Common units issued to Predecessor in exchange for oil and natural gas properties (in units) | shares	1,191,974
Common units issued to contributors in exchange for oil and natural gas properties	$ 169,033,212
Common units issued to contributors in exchange for oil and natural gas properties (in units) | shares	9,390,734
Common units sold to public	$ 103,500,000
Common units sold to public (in units) | shares	5,750,000
Underwriting discount and structuring fee incurred at initial public offering	$ (7,245,000)
Distributions to unitholders	(13,823,371)
Unit-based compensation	$ 798,413
Unit-based compensation (in units) | shares	177,091
Net income (loss)	$ 1,715,740
Partners' capital, ending balance at Dec. 31, 2017	$ 262,065,434
Partners' capital, ending balance (in units) at Dec. 31, 2017 | shares	16,509,799

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)		$ 1,715,740
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and accretion expenses		15,546,341
Impairment of oil and natural gas properties		0
Amortization of loan origination costs		57,292
Unit-based compensation		798,413
Loss on commodity derivative instruments		318,829
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables		(1,689,609)
Accounts receivable and other current assets		(236,673)
Accounts payable		316,486
Other current liabilities		1,746,662
Net cash provided by operating activities		18,573,481
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment		(61,932)
Purchase of oil and natural gas properties		(125,848,776)
Net cash used in investing activities		(125,910,708)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from initial public offering		96,255,000
Distributions to unitholders/members		(13,823,371)
Borrowings on long-term debt		30,843,593
Payment of loan origination costs		(312,500)
Net cash provided by (used in) financing activities		112,962,722
NET INCREASE IN CASH AND CASH EQUIVALENTS		5,625,495
CASH AND CASH EQUIVALENTS, end of period		5,625,495
Supplemental cash flow information:
Cash paid for interest		455,228
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ (496,856)		$ (6,212,619)	$ (31,313,926)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and accretion expenses	113,639		1,604,208	4,008,730
Impairment of oil and natural gas properties			4,992,897	28,673,166
Amortization of loan origination costs	4,241		46,969	40,965
Amortization of tenant improvement allowance	(2,864)		(34,369)	(14,321)
Unit-based compensation	50,422		605,059	605,059
Changes in operating assets and liabilities:
Oil, natural gas and NGL receivables	14,551		(66,455)	464,877
Accounts receivable and other current assets	333,056		1,027,172	(1,365,099)
Accounts payable	247,972		(952,800)	1,604,999
Other current liabilities	(77,442)		76,541	8,683
Net cash provided by operating activities	186,719		1,086,603	2,713,133
CASH FLOWS FROM INVESTING ACTIVITIES
Purchases of property and equipment			(19,305)	(31,960)
Purchase of oil and natural gas properties	(523)		(78,159)	(506,680)
Net cash used in investing activities	(523)		(97,464)	(538,640)
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders/members				(4,507,818)
Borrowings on long-term debt				3,050,000
Repayments on long-term debt			(850,000)	(605,000)
Payment of loan origination costs			(13,000)
Net cash provided by (used in) financing activities			(863,000)	(2,062,818)
NET INCREASE IN CASH AND CASH EQUIVALENTS	186,196		126,139	111,675
CASH AND CASH EQUIVALENTS, beginning of period	505,880	$ 692,076	379,741	268,066
CASH AND CASH EQUIVALENTS, end of period	692,076		505,880	379,741
Supplemental cash flow information:
Cash paid for interest	34,505		373,513	333,289
cash paid for taxes	$ 5,355		25,892	7,358
Noncash investing and financing activities:
Capital expenditures and consideration payable included in accounts payable and other liabilities			$ (37)	151,558
Capital expenditures through tenant improvement allowance				$ 171,848

ORGANIZATION

ORGANIZATION	12 Months Ended
	Dec. 31, 2017
ORGANIZATION
ORGANIZATION	NOTE 1—ORGANIZATION Kimbell Royalty Partners, LP (the “Partnership”) is a Delaware limited partnership formed on October 30, 2015. In connection with its formation, the Partnership issued a non-economic general partner interest in the Partnership to Kimbell Royalty GP, LLC, its general partner. The Partnership has adopted a fiscal year-end of December 31. On February 8, 2017, the Partnership completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the Partnership’s initial assets were contributed to the Partnership by the Contributing Parties at the closing of the IPO. As a result, as of December 31, 2016, the Partnership had not yet acquired any of such assets. Unless otherwise indicated, the financial information presented for periods on or after February 8, 2017 refers to the Partnership as a whole. The financial information presented for the periods on or prior to February 7, 2017, is solely that of the Predecessor, Rivercrest Royalties, LLC, and does not include the results of the Partnership as a whole. The mineral and royalty interests underlying the oil, natural gas and natural gas liquids (“NGLs”) production revenues of the Predecessor represented approximately 11% of the Partnership’s total future undiscounted cash flows, based on the reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”) as of December 31, 2016. The Predecessor is a Delaware limited liability company formed on October 25, 2013 to own mineral and royalty interests in the United States of America (‘‘United States’’). In addition to mineral and royalty interests, the Predecessor’s assets include overriding royalty interests. These non-cost-bearing interests are collectively referred to as ‘‘mineral and royalty interests.’’ The Predecessor also had non-operated working interests in certain oil and natural gas properties. Prior to the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated asset retirement obligations (“ARO”) to an affiliated entity that was not contributed to the Partnership.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (‘‘GAAP’’). A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows. Segment Reporting The Partnership 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 in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole. 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, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, valuation of commodity derivative financial instruments and equity‑based compensation. The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion. Reclassification of Prior Period Presentation Certain prior period amounts have been reclassified for consistency with the current period presentation. These reclassifications had no effect on previously reported net income (loss), total cash flows from operations or working capital. Cash and Cash Equivalents The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents. Accounts Receivable Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership is entitled to receive royalty payments with respect to the acquired properties on and after February 1, 2017. The Predecessor’s other current assets include amounts due as reimbursement for costs incurred by the Predecessor. The Partnership estimates and records an allowance for doubtful accounts when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2017, and 2016, no allowance for doubtful accounts is deemed necessary based upon a review of current receivables and the lack of historical write offs. Derivative Financial Instruments The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statement of operations within loss on commodity derivative instruments. Property and Equipment Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease. Oil and Natural Gas Properties The Partnership follows the full cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. The Partnership has not assigned any value to unproved properties in which it holds an interest. The full cost ceiling is evaluated at the end of each period. While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12‑month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. The fair value of these acquired assets was based on the common units issued to the Contributing Parties, other than the Predecessor, multiplied by the IPO price per common unit plus the net proceeds of the IPO that were distributed to the Contributing Parties, excluding the value of any common units or net proceeds distributed to the Predecessor. In accordance with SEC guidance, management determined the fair value of the acquired properties clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through December 31, 2017. A component of the exemption received from the SEC is that we were required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of December 31, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, management considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO, and management affirmed that there has not been a material decline to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at December 31, 2017 of $237.2 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $64.3 million as of December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired. All of the Partnership’s oil and natural gas properties are subject to the full-cost ceiling test. No impairment expense was recorded for the period from February 8, 2017 to December 31, 2017. No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). During the years ended December 31, 2016 and 2015, our Predecessor recorded a non-cash impairment charge of $5.0 million and $28.7 million, respectively, primarily due to changes in reserve values resulting from the decline in commodity prices and other factors. The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the years ended December 31, 2016 and 2015. Due to the nature of the Partnership’s and the Predecessor’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the years ended December 31, 2016 and 2015. Other Current Liabilities At December 31, 2017 and 2016, the Partnership’s and Predecessor’s other current liabilities consisted of the following: Partnership Predecessor December 31, December 31, 2017 2016 Accrued ad valorem taxes $ 531,664 $ - Revenue payable 509,125 - Accrued revenue processing fees 344,314 - Accrued interest expense 278,925 - Other current liabilities 82,634 112,508 Total current liabilities $ 1,746,662 $ 112,508 Asset Retirement Obligations Prior to the transactions that were completed in connection with the closing of the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. The Predecessor’s ARO reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Predecessor’s non-operated working interests in oil and natural gas properties. Fair values of legal obligations to retire and remove long-lived assets were recorded when the obligation was incurred. When the liability was initially recorded, the Partnership capitalized this cost by increasing the carrying amount of the related property and equipment. Over time, the liability was accreted for the change in its present value and the capitalized cost in oil and natural gas properties was depleted based on units of production consistent with the related asset. Other Long-Term Liabilities The Predecessor’s other long-term liabilities consist of a tenant improvement allowance granted at the effective date of the lease for the Partnership’s office space. This allowance was accounted for as a deferred incentive and was being amortized over the term of the lease as a reduction to rent expense. The deferred incentive was fully realized through the transactions that were completed in connection with the closing of the Partnership’s IPO and is not recognized in the Partnership’s financial statements. Income Taxes The Partnership is a master limited partnership and is taxed as a partnership under the Internal Revenue Code whereby the Partnership’s partners are taxed on their proportionate share of taxable income. The financial statements, therefore, do not include a provision for federal income taxes. Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Partnership and the Predecessor incurred de minimis amounts of state income taxes during 2017 and 2016. Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership and the Predecessor had no uncertain tax positions at December 31, 2017 and 2016. The Partnership and Predecessor recognizes interest and penalties related to uncertain tax positions in income tax expense. For the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, and the years ended December 31, 2016 and 2015, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions. The Partnership has filed all tax returns to date that are currently due. Tax years after December 31, 2013 remain subject to possible examination by taxing authorities although no such examination has been requested. Concentration of Credit Risk The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations. At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits. During the period from February 8, 2017 to December 31, 2017, one purchaser accounted for approximately 14% of oil, natural gas and NGL sales revenue. During the year ended December 31, 2016, three purchasers accounted for approximately 20%, 13% and 10% of oil, natural gas and NGL sales revenue. Revenue Recognition The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and NGL sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within oil, natural gas, and NGL receivables in the accompanying consolidated balance sheets. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known. Fair Value Measurements The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5 for further discussion of the Partnership’s fair value measurements. Recently Issued Accounting Pronouncements In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, “Business Combinations—Clarifying the Definition of a Business.” This update apples to all entities that must determine whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The update requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the transaction should not be accounted for as a business. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years. This update should be and will be applied prospectively on or after the effective date. The adoption of this update will change the process that the Partnership uses to evaluate whether it has acquired a business or an asset. This update is not expected to have a material impact on the Partnership’s financial statements or results of operations. In June 2016, the FASB issued ASU 2016‑13, "Measurement of Credit Losses on Financial Instruments." ASU 2016‑13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Partnership does not believe this standard will have a material impact on its financial statements. In April 2016, the FASB issued ASU 2016-10, “Revenue from Contracts with Customers—Identifying Performance Obligations and Licensing.” This update clarifies two principles of Accounting Standards Codification (“ASC”) Topic 606, identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08, the revenue recognition standard discussed below. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity. In March 2016, the FASB issued ASU 2016‑09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016‑09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year. The Partnership adopted this standard effective at the issuance of its restricted units under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) on May 12, 2017. The Partnership elected to account for forfeitures as they occur as a result of adopting this standard. In February 2016, the FASB issued ASU 2016‑02, "Leases." ASU 2016‑02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers’ (Topic 606).” an ASU on a comprehensive new revenue recognition standard that will supersede ASC 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either ‘‘full retrospective’’ adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or ‘‘modified retrospective’’ adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. As of December 31, 2017, we have substantially completed our evaluation of our sources of revenue and the impact of this accounting standards update on our consolidated results of operations, financial position, cash flows and financial disclosures for 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 Partnership 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 Partnership will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Partnership. Additionally, the Partnership does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams. The Partnership intends to use the full retrospective approach upon adoption of the new guidance on the effective date of January 1, 2018 and does not anticipate recording or disclosing any material transition adjustments upon adoption.

ACQUISITIONS

ACQUISITIONS	12 Months Ended
	Dec. 31, 2017
ACQUISITIONS
ACQUISITIONS	NOTE 3—ACQUISITIONS In the second quarter of 2017, the Partnership acquired mineral and royalty interests underlying 1.1 million gross acres, 6,881 net royalty acres, for an aggregate purchase price of approximately $16.8 million. The Partnership funded these acquisitions with borrowings under its secured revolving credit facility. On October 9, 2017, the Partnership acquired mineral and royalty interests underlying 8,460 gross acres, 983 net royalty acres, for an aggregate purchase price of approximately $3.9 million in Uintah County, Utah. The Partnership funded this acquisition with borrowings under its secured revolving credit facility. On November 8, 2017, the Partnership acquired mineral and royalty interests underlying 71,410 gross acres, 2,757 net royalty acres, for an aggregate purchase price of approximately $7.3 million in various counties in Arkansas. The Partnership funded this acquisition with borrowings under its secured revolving credit facility. On December 13, 2017, the Partnership acquired a diverse package of mineral and overriding royalty interests for an aggregate purchase price of approximately $1.3 million. The core positions are located in California and Wyoming and the package also includes small interests located in Kansas, Arkansas, Texas and Utah. The Partnership funded this acquisition with borrowings under its secured revolving credit facility.

DERIVATIVES

DERIVATIVES	12 Months Ended
	Dec. 31, 2017
DERIVATIVES
DERIVATIVES	NOTE 4—DERIVATIVES To reduce the impact of fluctuations in oil and natural gas prices on revenues, the Partnership entered into commodity derivative contracts for the years ended December 31, 2018 and 2019, effective January 1, 2018 and 2019, respectively, with a trade date of December 12, 2017, as to reduce its exposure to price volatility of oil and natural gas. The Partnership entered into oil and natural gas derivative instrument contracts that contain netting arrangements. The counterparty to the contracts is an unrelated third party. The Partnership has not designated any of its derivative contracts as hedges for accounting purposes. The Partnership records all derivative contracts at fair value. Changes in the fair values of the Partnership’s derivative instruments are presented on a net basis in the accompanying consolidated statement of operations and consisted of the following: Period from February 8, 2017 to December 31, 2017 Beginning fair value of commodity derivative instruments $ — Loss on commodity derivative instruments (318,829) Ending fair value of commodity derivative instruments $ (318,829) At December 31, 2017 , the Partnership’s commodity derivative contracts consisted of fixed price swaps, under which the Partnership receives a fixed price for the contract and pays a floating market price to the counterparty over a specified period for a contracted volume. Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month. At December 31, 2017, the Partnership’s open commodity derivative contracts consisted of the following: Oil Price Swaps Notional Weighted Average Volumes (MBbls) Fixed Price (per Bbl) January 2018 - December 2018 43,070 $ 56.00 January 2019 - December 2019 43,070 $ 53.07 Natural Gas Price Swaps Notional Weighted Average Volumes (MMBtu) Fixed Price (per MMBtu) January 2018 - December 2018 352,590 $ 2.71 January 2019 - December 2019 352,590 $ 2.76

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2017
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS	NOTE 5—FAIR VALUE MEASUREMENTS Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows: · Level 1—quoted market prices for identical assets or liabilities in active markets. · Level 2—quoted market prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability and inputs derived principally from or corroborated by observable market data by correlation or other means. · Level 3—unobservable inputs for the asset or liability. The Partnership’s commodity derivative instruments are classified within Level 2. The fair values of the Partnership’s oil and natural gas fixed price swaps are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors and discount rates, or can be corroborated from active markets. The Predecessor’s ARO is classified within Level 3 as the fair value is estimated using discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 10 for the summary of changes in the fair value of the Predecessor’s ARO for the Predecessor 2017 Period.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2017
LONG-TERM DEBT.
LONG-TERM DEBT	NOTE 6—LONG-TERM DEBT In connection with its IPO, the Partnership entered into a $50.0 million secured revolving credit facility that is secured by substantially all of its assets and the assets of its wholly owned subsidiaries. Availability under the secured revolving credit facility equals the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base will be re-determined semi-annually on February 1 and August 1 of each year based on the value of the Partnership’s oil and natural gas properties and the oil and natural gas properties of its wholly owned subsidiaries. In connection with the February 1, 2018 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $100.0 million. Aggregate commitments remain at $50.0 million providing for maximum availability under the revolving credit facility of $50.0 million. The secured revolving credit facility permits aggregate commitments to be increased to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The secured revolving credit facility matures on February 8, 2022. The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit the Partnership’s ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility also contains covenants requiring the Partnership to maintain the following financial ratios or to reduce the Partnership’s indebtedness if the Partnership is unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facility also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control. As of December 31, 2017, the Partnership’s outstanding balance was $30.8 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2017. During the period from February 8, 2017 to December 31, 2017, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% and Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%. For the period from February 8, 2017 to December 31, 2017, the weighted average interest rate on the Partnership’s outstanding borrowings was 3.94%. On January 31, 2014, the Predecessor entered into a credit agreement with Frost Bank for up to a $50.0 million revolving credit facility. The credit facility was subject to borrowing base restrictions and was collateralized by certain properties. The borrowing base on the Predecessor’s credit facility was $20.0 million with interest payable monthly on Alternate Base Rate loans or at the end of the interest period on any Eurodollar loans, with all principal and unpaid interest due at maturity on January 15, 2018. As of December 31, 2016, the Predecessor had outstanding advances on long-term debt totaling $10.6 million. On February 8, 2017, the Predecessor repaid the entire outstanding principal and interest balance on the credit facility with cash proceeds from the sale of the Predecessor’s mineral and royalty interests to the Partnership.

COMMON UNITS

COMMON UNITS	12 Months Ended
	Dec. 31, 2017
COMMON UNITS
COMMON UNITS	NOTE 7—COMMON UNITS On February 8, 2017, the Partnership completed its IPO of 5,750,000 common units representing limited partner interests, which included 750,000 common units issued pursuant to the underwriters’ option to purchase additional common units. The mineral and royalty interests making up the initial assets were contributed to the Partnership by the Contributing Parties at the time of the IPO. On May 12, 2017, the Partnership issued 163,324 restricted units under the LTIP. On May 2, 2017, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.23 per common unit for the period ended March 31, 2017. The distribution was paid on May 15, 2017 to unitholders of record as of the close of business on May 8, 2017. The amount of the first quarter 2017 distribution was adjusted for the period from the date of the closing of the Partnership’s IPO through March 31, 2017. On July 28, 2017, the Board of Directors declared a quarterly cash distribution of $0.30 per common unit for the quarter ended June 30, 2017. The distribution was paid on August 14, 2017 to unitholders of record as of the close of business on August 7, 2017. On August 9, 2017, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant of (i) common units in an amount equal to $30,000 each to certain non-employee directors of the Partnership under the LTIP, which were fully vested as of the grant date, and (ii) a total of 4,247 restricted units to certain consultants under the LTIP. Such grants were made on August 11, 2017. On October 27, 2017, the Board of Directors declared a quarterly cash distribution of $0.31 per common unit for the quarter ended September 30, 2017. The distribution was paid on November 13, 2017 to unitholders of record as of the close of business on November 6, 2017. As of December 31, 2017, 16,509,799 common units of the Partnership were outstanding. During the year ended December 31, 2015, the Predecessor made distributions to members totaling $3.2 million. The Predecessor made no distributions during the year ended December 31, 2016.

EARNINGS PER UNIT

EARNINGS PER UNIT	12 Months Ended
	Dec. 31, 2017
EARNINGS PER UNIT
EARNINGS PER UNIT	NOTE 8—EARNINGS PER UNIT Basic earnings per unit (“EPU”) is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested common units granted under the Partnership’s LTIP for its employees, directors and consultants and unvested options granted under the Predecessor’s long-term incentive plan as described in Note 9—Unit-Based Compensation. For the Predecessor 2017 period and the years ended December 31, 2016 and 2015, the effect of the 110,000 options issued under the Predecessor’s long-term incentive plan were anti-dilutive. Therefore, the options issued under the Predecessor’s long-term incentive plan were not included in the diluted EPU calculation on the consolidated statements of operations for those periods. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share: Partnership Predecessor Period from February 8, 2017 to December 31, Period from January 1, 2017 to February 7, Year Ended December 31, 2017 2017 2016 2015 Net income (loss) $ 1,715,740 $ (496,856) $ (6,212,619) $ (31,313,926) Net income (loss) attributable to common units Basic $ 0.11 $ (0.82) $ (10.28) $ (51.83) Diluted $ 0.10 $ (0.82) $ (10.28) $ (51.83) Weighted average number of common units outstanding Basic 16,336,871 604,137 604,137 604,137 Diluted 16,455,602 604,137 604,137 604,137

UNIT-BASED COMPENSATION

UNIT-BASED COMPENSATION	12 Months Ended
	Dec. 31, 2017
UNIT-BASED COMPENSATION
UNIT-BASED COMPENSATION	NOTE 9—UNIT-BASED COMPENSATION The Partnership’s LTIP authorizes grants of up to 2,041,600 common units in the aggregate to its employees, directors and consultants. The restricted units issued under our LTIP generally vest in one-third installments on each of the first three anniversaries of the grant date, subject to the grantee’s continuous service through the applicable vesting date. Compensation expense for such awards will be recognized over the term of the service period on a straight-line basis over the requisite service period for the entire award. Management elects not to estimate forfeiture rates and to account for forfeitures in compensation cost when they occur. Compensation expense for consultants will be accrued for services provided during the intervening periods between the grant and vesting dates, utilizing then-current fair values for the awards and applying mark-to-market accounting until actual vesting occurs. Distributions related to the restricted units are paid concurrently with our distributions for common units. The fair value of our restricted units issued under our LTIP to our employees and directors is determined by utilizing the market value of our common units on the respective grant date. The restricted units issued to non-employee consultants will utilize current market value of our common units for the awards and apply mark-to-market accounting until vesting occurs. The following table presents a summary of the Partnership’s unvested common units. Weighted Weighted Weighted Average Average Average Grant-Date Market-Date Remaining Fair Value Fair Value Contractual Units per Unit per Unit Term Unvested at February 8, 2017 — $ — $ — — Granted - service condition employees 143,318 18.655 — — Granted - service condition consultants 24,253 — 16.250 — Granted - non-employee directors 9,520 16.250 Vested (9,520) — — — Forfeited — — — — Exercised — — — — Unvested at December 31, 2017 167,571 $ 18.655 $ 16.250 1.364 years Prior to the IPO, the Predecessor had a long-term incentive plan that provided for the issuance of up to 110,000 membership units in the form of options as compensation for services performed for the Predecessor. The options carried a distribution right, whereby the option holder received distributions that were commensurate with those given to holders of membership units. A summary of the Predecessor’s option activity as of February 7, 2017 is as follows: Weighted Weighted Average Average Remaining Exercise Contractual Units Price Term Outstanding, December 31, 2016 110,000 $ 100 8.00 years Granted — — — Forfeited — — — Exercised — — — Outstanding, February 7, 2017 110,000 $ 100 7.92 years Exercisable, February 7, 2017 — $ — — For the Predecessor 2017 Period and the years ended December 31, 2016 and 2015, total compensation expense for awards under the long-term incentive plan was $0.05 million, $0.6 million and $0.6 million respectively, and is included general and administrative expenses in the consolidated statements of operations. In connection with the transactions that were completed at the closing of the Partnership’s IPO, the outstanding options to purchase membership units under the Predecessor’s long-term incentive plan expired and were not converted to units in the Partnership.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2017
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS	NOTE 10—ASSET RETIREMENT OBLIGATIONS Prior to the transactions that were completed in connection with the IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. As of the closing of its IPO and through the date of this Annual Report, the Partnership did not own any working interests and did not have any ARO or any lease operating expenses as a working interest owner.

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2017
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS	NOTE 11—RELATED PARTY TRANSACTIONS In connection with the IPO, the Partnership entered into a management services agreement with Kimbell Operating, which entered into separate services agreements with Steward Royalties, LLC (“Steward Royalties”), Taylor Companies Mineral Management, LLC (“Taylor Companies”), K3 Royalties, LLC (“K3 Royalties”), Nail Bay Royalties, LLC (“Nail Bay Royalties”) and Duncan Management, LLC (“Duncan Management”) pursuant to which they and Kimbell Operating provide management, administrative and operational services to the Partnership. In addition, under each of their respective services agreements, affiliates of the Partnership’s Sponsors will identify, evaluate and recommend to the Partnership acquisition opportunities and negotiate the terms of such acquisitions. Amounts paid to Kimbell Operating and such other entities under their respective services agreements will reduce the amount of cash available for distribution to the Partnership’s unitholders. During the period from February 8, 2017 to December 31, 2017, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $297,917, $366,667, $110,000, $461,576 and $603,590, respectively. Certain consultants who provide services under the above mentioned management services agreements were granted restricted units under the Partnership’s LTIP on May 12, 2017. During the Predecessor 2017 Period and the years ended December 31, 2016 and 2015, the Predecessor had certain related party receivables and payables; however, such amounts are de minimis at December 31, 2016 and 2015.

ADMINISTRATIVE SERVICES

ADMINISTRATIVE SERVICES	12 Months Ended
	Dec. 31, 2017
ADMINISTRATIVE SERVICES
ADMINISTRATIVE SERVICES	NOTE 12—ADMINISTRATIVE SERVICES The Partnership relies upon its officers, directors, Sponsors and outside consultants to further its business efforts. The Partnership also hires independent contractors and consultants involved in land, technical, regulatory and other disciplines to assist its officers and directors. Certain administrative services are being provided by individuals on the Board of Directors and their affiliated entities. See Note 11―Related Party Transactions.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2017
COMMITMENTS AND CONTINGENCIES.
COMMITMENTS AND CONTINGENCIES	NOTE 13—COMMITMENTS AND CONTINGENCIES Leases The Partnership leases certain office space under non-cancelable operating leases that end at various dates through 2022. The Partnership recognizes rent expense on a straight-line basis over the lease term. Rent expense is included in general and administrative expense and was de minimis for all periods presented on the consolidated statements of operations. Future minimum lease commitments under non-cancelable leases are as follows as of December 31, 2017: Years Ending December 31, 2018 $ 127,506 2019 130,180 2020 91,126 2021 50,784 2022 29,624 Thereafter - Total $ 429,220 Litigation Management is not aware of any legal, environmental or other commitments or contingencies that would have a material effect on the Partnership’s financial condition, results of operations or liquidity.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2017
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS	NOTE 14—SUBSEQUENT EVENTS The Partnership has evaluated events that occurred subsequent to December 31, 2017 in the preparation of its financial statements. On January 26, 2018, the Board of Directors declared a quarterly cash distribution of $0.36 per common unit for the quarter ended December 31, 2017. The distribution was paid on February 14, 2018 to unitholders of record as of the close of business on February 7, 2018. On January 26, 2018, the Board of Directors, upon the advice and recommendation of the Conflicts and Compensation Committee of the Board of Directors, approved the grant of a total of 326,654 restricted units to certain employees, directors and consultants under the LTIP. Such grants were made on January 29, 2018.

SUPPLEMENTAL OIL AND GAS RESERV

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)	12 Months Ended
	Dec. 31, 2017
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)	NOTE 15—SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) The Partnership has only one reportable operating segment, which is oil and gas producing activities in the United States. See the Partnership’s accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities. Capitalized oil and natural gas costs Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion and amortization are as follows: Partnership Predecessor December 31, December 31, 2017 2016 Oil, natural gas and NGL interests Proved $ 297,609,797 $ 70,888,121 Total oil, natural gas and NGL interests 297,609,797 70,888,121 Accumulated depreciation, depletion, accretion and impairment (15,394,238) (51,948,355) Net oil, natural gas and NGL interests capitalized $ 282,215,559 $ 18,939,766 Costs incurred in oil and natural gas activities Costs incurred in oil, natural gas and NGL acquisition and development activities are as follows: Partnership Predecessor Period from February 8, 2017 to December 31, Period from January 1, 2017 to February 7, Year Ended December 31, 2017 2017 2016 2015 Acquisition costs Proved properties $ 297,609,797 $ — $ — $ 42,000 Total 297,609,797 — — 42,000 Development costs Proved properties — — 78,159 464,680 Total — — 78,159 464,680 Total costs incurred on oil, natural gas and NGL activities $ 297,609,797 $ — $ 78,159 $ 506,680 Results of Operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and NGLs. It does not include any interest costs or general and administrative costs and, therefore, is not necessarily indicative of the contribution to the net operating results of the Partnership or Predecessor’s oil, natural gas and NGL operations. Partnership Predecessor Period from February 8, 2017 to December 31, Period from January 1, 2017 to February 7, Year Ended December 31, 2017 2017 2016 2015 Oil, natural gas and NGL revenues $ 30,665,092 $ 318,310 $ 3,606,659 $ 4,684,923 Production and ad valorem taxes (2,452,058) (19,651) (280,474) (426,885) Depreciation, depletion and accretion expense (15,394,238) (113,639) (1,604,208) (4,008,730) Impairment of oil and natural gas properties - - (4,992,897) (28,673,166) Marketing and other deductions (1,648,895) (110,534) (750,792) (747,264) Results of operations from oil, natural gas and NGLs $ 11,169,901 $ 74,486 $ (4,021,712) $ (29,171,122) The following tables summarize the net ownership interest in the proved oil, natural gas and NGL reserves and the standardized measure of discounted future net cash flows related to the proved oil, natural gas and NGL reserves, and the estimates were prepared by the Partnership based on reserve reports prepared by Ryder Scott for the years ended December 31, 2017 and 2016. The standardized measure presented here excludes income taxes, as the tax basis for the properties is not applicable on a go-forward basis. The proved oil, natural gas and NGL reserve estimates and other components of the standardized measure were determined in accordance with the authoritative guidance of the FASB and the SEC. Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. A barrel of equivalent (‘‘Boe’’) conversion ratio of six thousand cubic feet per barrel (6mcf/bbl) of natural gas to barrels of oil equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All Boe conversions in the report are derived from converting gas to oil in the ratio mix of six thousand cubic feet of gas to one barrel of oil. The Partnership’s net proved oil, natural gas and NGL reserves and changes in net proved oil, natural gas and NGL reserves attributable to the oil, natural gas and NGL properties, which are located in multiple states are summarized below: Crude Oil and Natural Gas Condensate Natural Gas Liquids Total (MBbls) (MMcf) (MBbls) (MBOE) Net proved reserves at January 1, 2016 6,827 51,734 1,647 17,096 Revisions of previous estimates (1) 131 (852) 335 324 Purchase of minerals in place (2) 45 90 9 69 Extensions, discoveries and other additions (3) 637 2,851 115 1,227 Production (430) (3,433) (124) (1,126) Net proved reserves at December 31, 2016 7,210 50,390 1,982 17,590 Revisions of previous estimates (1) (193) (1,535) 666 217 Purchase of minerals in place (4) 362 16,312 274 3,355 Extensions, discoveries and other additions (5) 505 2,261 91 973 Production (421) (3,512) (175) (1,181) Net proved reserves at December 31, 2017 7,463 63,916 2,838 20,954 Net Proved Developed Reserves December 31, 2016 4,879 35,172 1,416 12,157 December 31, 2017 5,284 47,501 2,202 15,403 Net Proved Undeveloped Reserves December 31, 2016 2,331 15,218 566 5,433 December 31, 2017 2,179 16,415 636 5,551 (1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. (2) Includes the acquisition of three contiguous Eagle Ford drilling units in Karnes County, Texas. (3) Includes discoveries and additions primarily related to active drilling on our acreage primarily in the Permian Basin. (4) Includes the acquisition of $29.3 million of mineral and royalty interests, the largest of which being a package in the Anadarko Basin, and also includes additional mineral and royalty interests in Texas, Louisiana, Wyoming, California, North Dakota, Utah, New Mexico, Arkansas, and Kansas. (5) Includes discoveries and additions primarily related to active drilling on our acreage primarily in the Permian Basin, Eagle Ford Shale. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. Standardized Measure The standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and natural gas liquids reserves of the properties is as follows (in thousands): Year Ended December 31, 2017 2016 Future cash inflows $ 562,967 $ 414,004 Future production costs (45,652) (32,034) Future state margin taxes (2,790) (2,051) Future net cash flows 514,525 379,919 Less 10% annual discount to reflect timing of cash flows (298,973) (220,643) Standard measure of discounted future net cash flows $ 215,552 $ 159,276 Reserve estimates and future cash flows are based on the average market prices for sales of oil, natural gas and NGL adjusted for basis differentials, on the first calendar day of each month during the year. The average prices used for 2017 and 2016 were $51.34 and $42.75 per barrel for crude oil and $2.98 and $2.49 per Mcf for natural gas, respectively. Future production costs are computed primarily by the Partnership’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. As mentioned above, the standardized measure presented here does not include the effects of income taxes, as the tax basis for the properties is not applicable on a go-forward basis. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil, natural gas and NGL reserve estimates. Changes in Standardized Measure Changes in the standardized measure of discounted future net cash flows before income taxes related to the proved oil, natural gas and NGL reserves of the properties are as follows (in thousands): Year Ended December 31, 2017 2016 Standardized measure - beginning of year $ 159,275 $ 180,083 Sales, net of production costs (29,288) (24,280) Net changes of prices and production costs related to future production 21,946 (23,321) Extensions, discoveries and improved recovery, net of future production costs 10,064 11,253 Revisions of previous quantity estimates, net of related costs 2,248 2,974 Net changes in state margin taxes 301 (112) Accretion of discount 15,928 18,008 Purchases of reserves in place 23,309 1,097 Timing differences and other 11,769 (6,426) Standardized measure - end of year $ 215,552 $ 159,276

SUMMARY OF SIGNIFICANT ACCOUN21

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2017
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation	Basis of Presentation The Partnership’s year-end is December 31. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (‘‘GAAP’’). A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.
Segment Reporting	Segment Reporting The Partnership 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 in deciding how to allocate resources and assess performance. The Partnership’s chief operating decision maker allocates resources and assesses performance based upon financial information of the Partnership as a whole.
Management 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, liabilities, revenues and expenses, as well as certain financial statement disclosures. The Partnership evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates made in preparing these financial statements include the estimate of uncollected revenues and unpaid expenses from mineral and royalty interests in properties operated by nonaffiliated entities, the estimates of proved oil, natural gas and NGL reserves and related present value estimates of future net cash flows from those properties, valuation of commodity derivative financial instruments and equity‑based compensation. The discounted present value of the proved oil, natural gas and NGL reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil, natural gas and NGL reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in ceiling test impairment representing a noncash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.
Reclassification of Prior Period Presentation	Reclassification of Prior Period Presentation Certain prior period amounts have been reclassified for consistency with the current period presentation. These reclassifications had no effect on previously reported net income (loss), total cash flows from operations or working capital.
Cash and Cash Equivalents	Cash and Cash Equivalents The Partnership considers all highly liquid instruments with a maturity date of three months or less at date of purchase to be cash and cash equivalents.
Accounts Receivable	Accounts Receivable Oil, natural gas and NGL receivables consists of revenue payments due to the Partnership from its mineral and royalty interests. Under the terms of the contribution agreement entered into by and among the Partnership and the Contributing Parties prior to the IPO, the Partnership is entitled to receive royalty payments with respect to the acquired properties on and after February 1, 2017. The Predecessor’s other current assets include amounts due as reimbursement for costs incurred by the Predecessor. The Partnership estimates and records an allowance for doubtful accounts when failure to collect the receivable is considered probable based on the relevant facts and circumstances surrounding the receivable. As of December 31, 2017, and 2016, no allowance for doubtful accounts is deemed necessary based upon a review of current receivables and the lack of historical write offs.
Derivative Financial Instruments	Derivative Financial Instruments The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To manage risks related to fluctuations in prices attributable to its projected oil and natural gas production, the Partnership entered into oil and natural gas derivative contracts. Entrance into such contracts is dependent upon prevailing or anticipated market conditions. Derivative instruments are recognized at fair value. If a right of offset exists under master netting arrangements and certain other criteria are met, derivative assets and liabilities with the same counterparty are netted on the consolidated balance sheet. The Partnership does not specifically designate derivative instruments as cash flow hedges, even though they reduce its exposure to changes in oil and natural gas prices; therefore, gains and losses arising from changes in the fair value of derivatives are recognized on a net basis in the consolidated statement of operations within loss on commodity derivative instruments.
Property and Equipment	Property and Equipment Property and equipment includes office furniture and equipment, leasehold improvements, and computer hardware and equipment and is stated at historical cost. Depreciation and amortization are calculated using the straight-line method over expected useful lives ranging from three to seven years. Leasehold improvements are depreciated over the shorter of the expected useful life or the term of the underlying lease.
Oil and Natural Gas Properties	Oil and Natural Gas Properties The Partnership follows the full cost method of accounting for costs related to its oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. The capitalized costs are subject to a ceiling test, which limits capitalized costs to the aggregate of the present value of future net revenues attributable to proved oil, natural gas and NGL reserves discounted at 10% plus the lower of cost or market value of unproved properties. The Partnership has not assigned any value to unproved properties in which it holds an interest. The full cost ceiling is evaluated at the end of each period. While the quantities of proved reserves require substantial judgment, the associated prices of oil, natural gas and NGL reserves that are included in the discounted present value of the reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12‑month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. The present value is not necessarily an indication of the fair value of the reserves. Oil, natural gas and NGL prices have historically been volatile, and the prevailing prices at any given time may not reflect the Partnership’s or the industry’s forecast of future prices. The substantial majority of the Partnership’s proved oil and natural gas properties that were acquired at the time of the IPO were recorded at fair value as of the IPO. The fair value of these acquired assets was based on the common units issued to the Contributing Parties, other than the Predecessor, multiplied by the IPO price per common unit plus the net proceeds of the IPO that were distributed to the Contributing Parties, excluding the value of any common units or net proceeds distributed to the Predecessor. In accordance with SEC guidance, management determined the fair value of the acquired properties clearly exceeded the related full-cost ceiling limitation beyond a reasonable doubt and received an exemption from the SEC to exclude the properties acquired at the closing of the IPO from the ceiling test calculation. This exemption was effective beginning with the period ended March 31, 2017 and will remain effective through December 31, 2017. A component of the exemption received from the SEC is that we were required to assess the fair value of these acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of these acquired assets in the full-cost ceiling test would not be appropriate. As of December 31, 2017, management determined that the exemption to exclude these acquired assets from the full-cost ceiling test was appropriate. In making this determination, management considered that the value was based on a transaction conducted in a public offering and that the common units issued by the Partnership as consideration for the properties were attributed the same value as those purchased in the Partnership’s IPO by third-party investors. Additionally, the fair value of the properties acquired at the closing of our IPO was based on forward strip oil and natural gas pricing existing at the date of the IPO, and management affirmed that there has not been a material decline to the fair value of these acquired assets since the IPO. The properties acquired at the closing of our IPO have an unamortized cost at December 31, 2017 of $237.2 million. Had management not affirmed the lack of material change to the fair value, the impairment charge recorded would have been $64.3 million as of December 31, 2017. The Partnership will recognize an impairment in the first quarter of 2018 after the exemption has expired. All of the Partnership’s oil and natural gas properties are subject to the full-cost ceiling test. No impairment expense was recorded for the period from February 8, 2017 to December 31, 2017. No impairment expense was recorded by the Predecessor for the period from January 1, 2017 to February 7, 2017 (the “Predecessor 2017 Period”). During the years ended December 31, 2016 and 2015, our Predecessor recorded a non-cash impairment charge of $5.0 million and $28.7 million, respectively, primarily due to changes in reserve values resulting from the decline in commodity prices and other factors. The Partnership’s oil and natural gas properties are depleted on the unit-of-production method using estimates of proved oil, natural gas and NGL reserves. Sales or other dispositions of oil and gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to estimated proved reserves would significantly change. No gains or losses were recorded for the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the years ended December 31, 2016 and 2015. Due to the nature of the Partnership’s and the Predecessor’s mineral and royalty interests, there are no exploratory activities pending determination, and no exploratory costs were charged to expense for the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the years ended December 31, 2016 and 2015.
Other Current Liabilities	Other Current Liabilities At December 31, 2017 and 2016, the Partnership’s and Predecessor’s other current liabilities consisted of the following: Partnership Predecessor December 31, December 31, 2017 2016 Accrued ad valorem taxes $ 531,664 $ - Revenue payable 509,125 - Accrued revenue processing fees 344,314 - Accrued interest expense 278,925 - Other current liabilities 82,634 112,508 Total current liabilities $ 1,746,662 $ 112,508
Asset Retirement Obligations	Asset Retirement Obligations Prior to the transactions that were completed in connection with the closing of the Partnership’s IPO, the Predecessor assigned its non-operated working interests and associated ARO to an affiliated entity that was not contributed to the Partnership. The Predecessor’s ARO reflects the present value of estimated costs of dismantlement, removal, site reclamation, and similar activities associated with the Predecessor’s non-operated working interests in oil and natural gas properties. Fair values of legal obligations to retire and remove long-lived assets were recorded when the obligation was incurred. When the liability was initially recorded, the Partnership capitalized this cost by increasing the carrying amount of the related property and equipment. Over time, the liability was accreted for the change in its present value and the capitalized cost in oil and natural gas properties was depleted based on units of production consistent with the related asset.
Other Long-Term Liabilities	Other Long-Term Liabilities The Predecessor’s other long-term liabilities consist of a tenant improvement allowance granted at the effective date of the lease for the Partnership’s office space. This allowance was accounted for as a deferred incentive and was being amortized over the term of the lease as a reduction to rent expense. The deferred incentive was fully realized through the transactions that were completed in connection with the closing of the Partnership’s IPO and is not recognized in the Partnership’s financial statements.
Income Taxes	Income Taxes The Partnership is a master limited partnership and is taxed as a partnership under the Internal Revenue Code whereby the Partnership’s partners are taxed on their proportionate share of taxable income. The financial statements, therefore, do not include a provision for federal income taxes. Texas imposes a franchise tax, commonly referred to as the Texas margin tax, which is considered an income tax, at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Partnership and the Predecessor incurred de minimis amounts of state income taxes during 2017 and 2016. Uncertain tax positions are recognized in the financial statements only if that position is more-likely-than-not of being sustained upon examination by taxing authorities, based on the technical merits of the position. The Partnership and the Predecessor had no uncertain tax positions at December 31, 2017 and 2016. The Partnership and Predecessor recognizes interest and penalties related to uncertain tax positions in income tax expense. For the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, and the years ended December 31, 2016 and 2015, the Partnership and the Predecessor did not recognize any interest or penalty expense related to uncertain tax positions. The Partnership has filed all tax returns to date that are currently due. Tax years after December 31, 2013 remain subject to possible examination by taxing authorities although no such examination has been requested.
Concentration of Credit Risk	Concentration of Credit Risk The Partnership has no involvement or operational control over the volumes and method of sale of oil, natural gas and NGLs produced and sold from the properties. It is believed that the loss of any single purchaser would not have a material adverse effect on the results of operations. At times, the Partnership maintains deposits in federally insured financial institutions in excess of federally insured limits. Management monitors the credit ratings and concentration of risk with these financial institutions on a continuing basis to safeguard cash deposits. The Partnership has not experienced any losses related to amounts in excess of federally insured limits. During the period from February 8, 2017 to December 31, 2017, one purchaser accounted for approximately 14% of oil, natural gas and NGL sales revenue. During the year ended December 31, 2016, three purchasers accounted for approximately 20%, 13% and 10% of oil, natural gas and NGL sales revenue.
Revenue Recognition	Revenue Recognition The Partnership recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured. As an owner of mineral and royalty interests, the Partnership is entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the underlying acreage, net of post-production expenses and taxes. The pricing of oil, natural gas and NGL sales from the properties is primarily determined by supply and demand in the marketplace and can fluctuate considerably. To the extent actual volumes and prices of oil, natural gas and NGLs are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volume and prices for these properties are estimated and recorded within oil, natural gas, and NGL receivables in the accompanying consolidated balance sheets. Differences between estimates of revenue and the actual amounts are adjusted and recorded in the period that the actual amounts are known.
Fair Value Measurements	Fair Value Measurements The Partnership measures and reports certain assets and liabilities on a fair value basis and has classified and disclosed its fair value measurements using the levels of the fair value hierarchy. The carrying amount of cash and cash equivalents, accounts receivable, accounts payable, and other current liabilities as reflected in the consolidated balance sheets, approximate fair value because of the short-term maturity of these instruments. The carrying amount reported for long-term debt represents fair value as the interest rates approximate current market rates. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized or that will be realized in the future. See Note 5 for further discussion of the Partnership’s fair value measurements.
Recently Issued Accounting Pronouncements	Recently Issued Accounting Pronouncements In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-01, “Business Combinations—Clarifying the Definition of a Business.” This update apples to all entities that must determine whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The update requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the transaction should not be accounted for as a business. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years. This update should be and will be applied prospectively on or after the effective date. The adoption of this update will change the process that the Partnership uses to evaluate whether it has acquired a business or an asset. This update is not expected to have a material impact on the Partnership’s financial statements or results of operations. In June 2016, the FASB issued ASU 2016‑13, "Measurement of Credit Losses on Financial Instruments." ASU 2016‑13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. The Partnership does not believe this standard will have a material impact on its financial statements. In April 2016, the FASB issued ASU 2016-10, “Revenue from Contracts with Customers—Identifying Performance Obligations and Licensing.” This update clarifies two principles of Accounting Standards Codification (“ASC”) Topic 606, identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as ASU 2016-08, the revenue recognition standard discussed below. The adoption of this standard is not expected to have a material impact on the Partnership's financial position, results of operations and liquidity. In March 2016, the FASB issued ASU 2016‑09, “Improvements to Employee Share-Based Payment Accounting.” ASU 2016‑09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within that fiscal year. The Partnership adopted this standard effective at the issuance of its restricted units under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (“LTIP”) on May 12, 2017. The Partnership elected to account for forfeitures as they occur as a result of adopting this standard. In February 2016, the FASB issued ASU 2016‑02, "Leases." ASU 2016‑02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses are accounted for. This update is effective for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Partnership believes the primary impact of adopting this standard will be the recognition of assets and liabilities on the balance sheet for current operating leases. In May 2014, the FASB issued ASU 2014-09, “Revenue from Contracts with Customers’ (Topic 606).” an ASU on a comprehensive new revenue recognition standard that will supersede ASC 605, Revenue Recognition. The new accounting guidance creates a framework under which an entity will allocate the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities will be required to use judgment and make estimates, including identifying performance obligations in a contract, estimating the amount of variable consideration to include in the transaction price, allocating the transaction price to each separate performance obligation, and determining when an entity satisfies its performance obligations. The standard allows for either ‘‘full retrospective’’ adoption, meaning that the standard is applied to all of the periods presented with a cumulative catch-up as of the earliest period presented, or ‘‘modified retrospective’’ adoption, meaning the standard is applied only to the most current period presented in the financial statements with a cumulative catch-up as of the current period. As of December 31, 2017, we have substantially completed our evaluation of our sources of revenue and the impact of this accounting standards update on our consolidated results of operations, financial position, cash flows and financial disclosures for 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 Partnership 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 Partnership will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by the Partnership. Additionally, the Partnership does not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how it presents information regarding its revenue streams. The Partnership intends to use the full retrospective approach upon adoption of the new guidance on the effective date of January 1, 2018 and does not anticipate recording or disclosing any material transition adjustments upon adoption.

SUMMARY OF SIGNIFICANT ACCOUN22

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2017
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Schedule of other current liabilities	Partnership Predecessor December 31, December 31, 2017 2016 Accrued ad valorem taxes $ 531,664 $ - Revenue payable 509,125 - Accrued revenue processing fees 344,314 - Accrued interest expense 278,925 - Other current liabilities 82,634 112,508 Total current liabilities $ 1,746,662 $ 112,508

DERIVATIVES (Tables)

DERIVATIVES (Tables)	12 Months Ended
	Dec. 31, 2017
DERIVATIVES
Schedule of changes in fair value of derivative instruments	Period from February 8, 2017 to December 31, 2017 Beginning fair value of commodity derivative instruments $ — Loss on commodity derivative instruments (318,829) Ending fair value of commodity derivative instruments $ (318,829)
Schedule of commodity derivative contracts	At December 31, 2017, the Partnership’s open commodity derivative contracts consisted of the following: Oil Price Swaps Notional Weighted Average Volumes (MBbls) Fixed Price (per Bbl) January 2018 - December 2018 43,070 $ 56.00 January 2019 - December 2019 43,070 $ 53.07 Natural Gas Price Swaps Notional Weighted Average Volumes (MMBtu) Fixed Price (per MMBtu) January 2018 - December 2018 352,590 $ 2.71 January 2019 - December 2019 352,590 $ 2.76

EARNINGS PER UNIT (Tables)

EARNINGS PER UNIT (Tables)	12 Months Ended
	Dec. 31, 2017
EARNINGS PER UNIT
Schedule of earnings (loss) per unit	Partnership Predecessor Period from February 8, 2017 to December 31, Period from January 1, 2017 to February 7, Year Ended December 31, 2017 2017 2016 2015 Net income (loss) $ 1,715,740 $ (496,856) $ (6,212,619) $ (31,313,926) Net income (loss) attributable to common units Basic $ 0.11 $ (0.82) $ (10.28) $ (51.83) Diluted $ 0.10 $ (0.82) $ (10.28) $ (51.83) Weighted average number of common units outstanding Basic 16,336,871 604,137 604,137 604,137 Diluted 16,455,602 604,137 604,137 604,137

UNIT-BASED COMPENSATION (Tables

UNIT-BASED COMPENSATION (Tables)	12 Months Ended
	Dec. 31, 2017
UNIT-BASED COMPENSATION
Schedule of unvested restricted stock activity	Weighted Weighted Weighted Average Average Average Grant-Date Market-Date Remaining Fair Value Fair Value Contractual Units per Unit per Unit Term Unvested at February 8, 2017 — $ — $ — — Granted - service condition employees 143,318 18.655 — — Granted - service condition consultants 24,253 — 16.250 — Granted - non-employee directors 9,520 16.250 Vested (9,520) — — — Forfeited — — — — Exercised — — — — Unvested at December 31, 2017 167,571 $ 18.655 $ 16.250 1.364 years
Schedule of unit option activity	Weighted Weighted Average Average Remaining Exercise Contractual Units Price Term Outstanding, December 31, 2016 110,000 $ 100 8.00 years Granted — — — Forfeited — — — Exercised — — — Outstanding, February 7, 2017 110,000 $ 100 7.92 years Exercisable, February 7, 2017 — $ — —

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2017
COMMITMENTS AND CONTINGENCIES.
Schedule of operating lease commitments	Future minimum lease commitments under non-cancelable leases are as follows as of December 31, 2017: Years Ending December 31, 2018 $ 127,506 2019 130,180 2020 91,126 2021 50,784 2022 29,624 Thereafter - Total $ 429,220

SUPPLEMENTAL OIL AND GAS RESE27

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2017
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
Schedule of oil and natural gas aggregate capitalized costs and applicable accumulated depreciation, depletion and amortization	Partnership Predecessor December 31, December 31, 2017 2016 Oil, natural gas and NGL interests Proved $ 297,609,797 $ 70,888,121 Total oil, natural gas and NGL interests 297,609,797 70,888,121 Accumulated depreciation, depletion, accretion and impairment (15,394,238) (51,948,355) Net oil, natural gas and NGL interests capitalized $ 282,215,559 $ 18,939,766
Schedule of costs incurred in oil and natural gas activities	Partnership Predecessor Period from February 8, 2017 to December 31, Period from January 1, 2017 to February 7, Year Ended December 31, 2017 2017 2016 2015 Acquisition costs Proved properties $ 297,609,797 $ — $ — $ 42,000 Total 297,609,797 — — 42,000 Development costs Proved properties — — 78,159 464,680 Total — — 78,159 464,680 Total costs incurred on oil, natural gas and NGL activities $ 297,609,797 $ — $ 78,159 $ 506,680
Results of operations from oil, natural gas and natural gas liquids	Partnership Predecessor Period from February 8, 2017 to December 31, Period from January 1, 2017 to February 7, Year Ended December 31, 2017 2017 2016 2015 Oil, natural gas and NGL revenues $ 30,665,092 $ 318,310 $ 3,606,659 $ 4,684,923 Production and ad valorem taxes (2,452,058) (19,651) (280,474) (426,885) Depreciation, depletion and accretion expense (15,394,238) (113,639) (1,604,208) (4,008,730) Impairment of oil and natural gas properties - - (4,992,897) (28,673,166) Marketing and other deductions (1,648,895) (110,534) (750,792) (747,264) Results of operations from oil, natural gas and NGLs $ 11,169,901 $ 74,486 $ (4,021,712) $ (29,171,122)
Schedule of net proved oil, natural gas and natural gas liquids reserves and changes	Crude Oil and Natural Gas Condensate Natural Gas Liquids Total (MBbls) (MMcf) (MBbls) (MBOE) Net proved reserves at January 1, 2016 6,827 51,734 1,647 17,096 Revisions of previous estimates (1) 131 (852) 335 324 Purchase of minerals in place (2) 45 90 9 69 Extensions, discoveries and other additions (3) 637 2,851 115 1,227 Production (430) (3,433) (124) (1,126) Net proved reserves at December 31, 2016 7,210 50,390 1,982 17,590 Revisions of previous estimates (1) (193) (1,535) 666 217 Purchase of minerals in place (4) 362 16,312 274 3,355 Extensions, discoveries and other additions (5) 505 2,261 91 973 Production (421) (3,512) (175) (1,181) Net proved reserves at December 31, 2017 7,463 63,916 2,838 20,954 Net Proved Developed Reserves December 31, 2016 4,879 35,172 1,416 12,157 December 31, 2017 5,284 47,501 2,202 15,403 Net Proved Undeveloped Reserves December 31, 2016 2,331 15,218 566 5,433 December 31, 2017 2,179 16,415 636 5,551 (1) Revisions of previous estimates include technical revisions due to changes in commodity prices, historical and projected performance and other factors. (2) Includes the acquisition of three contiguous Eagle Ford drilling units in Karnes County, Texas. (3) Includes discoveries and additions primarily related to active drilling on our acreage primarily in the Permian Basin. (4) Includes the acquisition of $29.3 million of mineral and royalty interests, the largest of which being a package in the Anadarko Basin, and also includes additional mineral and royalty interests in Texas, Louisiana, Wyoming, California, North Dakota, Utah, New Mexico, Arkansas, and Kansas. (5) Includes discoveries and additions primarily related to active drilling on our acreage primarily in the Permian Basin, Eagle Ford Shale.
Schedule of standardized measure related to proved oil, natural gas and natural gas liquids reserves	Year Ended December 31, 2017 2016 Future cash inflows $ 562,967 $ 414,004 Future production costs (45,652) (32,034) Future state margin taxes (2,790) (2,051) Future net cash flows 514,525 379,919 Less 10% annual discount to reflect timing of cash flows (298,973) (220,643) Standard measure of discounted future net cash flows $ 215,552 $ 159,276
Schedule of changes in standardized measure related to proved oil, natural gas and natural gas liquids reserves	Year Ended December 31, 2017 2016 Standardized measure - beginning of year $ 159,275 $ 180,083 Sales, net of production costs (29,288) (24,280) Net changes of prices and production costs related to future production 21,946 (23,321) Extensions, discoveries and improved recovery, net of future production costs 10,064 11,253 Revisions of previous quantity estimates, net of related costs 2,248 2,974 Net changes in state margin taxes 301 (112) Accretion of discount 15,928 18,008 Purchases of reserves in place 23,309 1,097 Timing differences and other 11,769 (6,426) Standardized measure - end of year $ 215,552 $ 159,276

ORGANIZATION (Details)

ORGANIZATION (Details) - shares	Feb. 08, 2017	Dec. 31, 2016
Organization
Percentage of future undiscounted cash flows from predecessor		11.00%
IPO
Organization
Common units issued in initial public offering	5,750,000
Underwriter's option
Organization
Common units issued in initial public offering	750,000

SUMMARY OF SIGNIFICANT ACCOUN29

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -Other Disclosures (Details)	12 Months Ended
	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)
Segment Reporting
Number of operating units | segment	1
Number of reporting units | segment	1
Accounts Receivable
Allowance for doubtful accounts receivable | $	$ 0
Predecessor
Accounts Receivable
Allowance for doubtful accounts receivable | $		$ 0

SUMMARY OF SIGNIFICANT ACCOUN30

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property and Equipment (Details)	12 Months Ended
	Dec. 31, 2016
Minimum
Property and Equipment
Useful life	3 years
Maximum
Property and Equipment
Useful life	7 years

SUMMARY OF SIGNIFICANT ACCOUN31

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) - USD ($)	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Oil and Natural Gas Properties
Value of unproved properties		$ 0	$ 0
Value of acquired properties excluded from ceiling test calculation		237,200,000	237,200,000
Impairment charge if the ceiling test would have been performed		64,300,000	64,300,000
Impairment of oil and natural gas properties			$ 0
Gain (loss) recorded on disposition of oil, natural gas and natural gas liquid properties		0
Number of exploratory activities pending determination		0
Exploratory costs charged		$ 0
Predecessor
Oil and Natural Gas Properties
Value of unproved properties				$ 0
Impairment of oil and natural gas properties	$ 0			4,992,897	$ 28,673,166
Gain (loss) recorded on disposition of oil, natural gas and natural gas liquid properties	0			0
Number of exploratory activities pending determination	0			0	0
Exploratory costs charged	$ 0			$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN32

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Current Liabilities (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Accrued ad valorem taxes	$ 531,664
Revenue payable	509,125
Accrued revenue processing fees	344,314
Accrued interest expense	278,925
Other current liabilities	82,634
Total current liabilities	$ 1,746,662
Predecessor
Other current liabilities		$ 112,508
Total current liabilities		$ 112,508

SUMMARY OF SIGNIFICANT ACCOUN33

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($)	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes
Provision for federal income taxes			$ 0
Texas franchise tax (as a percent)			0.75%
Uncertain tax positions		$ 0	$ 0
Interest and penalties		$ 0
Predecessor
Income Taxes
Provision for federal income taxes				$ 0	$ 0
Uncertain tax positions				0
Interest and penalties	$ 0			$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN34

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentration of Credit Risk (Details) - Sales - Customer - item	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Concentration of Credit Risk
Number of significant purchasers	1
Purchaser 1
Concentration of Credit Risk
Purchaser percentage	14.00%
Predecessor
Concentration of Credit Risk
Number of significant purchasers		3
Predecessor | Purchaser 1
Concentration of Credit Risk
Purchaser percentage		20.00%
Predecessor | Purchaser 2
Concentration of Credit Risk
Purchaser percentage		13.00%
Predecessor | Purchaser 3
Concentration of Credit Risk
Purchaser percentage		10.00%

ACQUISITIONS (Details)

ACQUISITIONS (Details) - Mineral And Royalty Interests $ in Millions	Dec. 13, 2017USD ($)	Nov. 08, 2017USD ($)a	Oct. 09, 2017USD ($)a	Jun. 30, 2017USD ($)a
ACQUISITIONS
Gross acres acquired		71,410	8,460	1,100,000
Net Acres Land Acquired		2,757	983	6,881
Aggregate purchase price | $	$ 1.3	$ 7.3	$ 3.9	$ 16.8

DERIVATIVES (Details)

DERIVATIVES (Details)	11 Months Ended
	Dec. 31, 2017USD ($)$ / bbl
Change in fair values of derivative instruments
Loss on commodity derivative instruments	$ (318,829)
Ending fair value of commodity derivative instruments	318,829
Oil Price Swaps - January 2018 - December 2018
Derivatives
Notional	$ 43,070
Weighted Average Fixed Price | $ / bbl	56
Oil Price Swaps - January 2019 - December 2019
Derivatives
Notional	$ 43,070
Weighted Average Fixed Price | $ / bbl	53.07
Natural Gas Price Swaps - January 2018 - December 2018
Derivatives
Notional	$ 352,590
Weighted Average Fixed Price | $ / bbl	2.71
Natural Gas Price Swaps - January 2019 - December 2019
Derivatives
Notional	$ 352,590
Weighted Average Fixed Price | $ / bbl	2.76

LONG-TERM DEBT (Details)

LONG-TERM DEBT (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Aug. 01, 2017	Feb. 08, 2017	Dec. 31, 2016	Jan. 31, 2014
Long-term debt
Long-term debt outstanding	$ 30,843,593
Revolving credit facility
Long-term debt
Revolving credit facility maximum borrowings			$ 50,000,000
Revolving credit facility increased maximum borrowing capacity			$ 100,000,000
Revolving credit facility outstanding	$ 30,800,000
Interest rate on outstanding borrowings (as a percent)	3.94%
Amended borrowing base		$ 100,000,000
Revolving credit facility | LIBOR
Long-term debt
Variable rate	LIBOR
Margin (as a percent)	2.25%
Revolving credit facility | Prime
Long-term debt
Variable rate	Prime Rate
Margin (as a percent)	1.25%
Revolving credit facility | Maximum
Long-term debt
Debt to EBITDAX ratio			400.00%
Revolving credit facility | Minimum
Long-term debt
Debt to EBITDAX ratio			100.00%
Predecessor
Long-term debt
Long-term debt outstanding				$ 10,598,860
Predecessor | Revolving credit facility
Long-term debt
Revolving credit facility maximum borrowings					$ 50,000,000
Initial borrowing base					$ 20,000,000

COMMON UNITS (Details)

COMMON UNITS (Details) - USD ($)	Oct. 27, 2017	Aug. 09, 2017	Jul. 28, 2017	May 12, 2017	May 02, 2017	Feb. 08, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017
Common units
Common units outstanding									16,509,799
Cash distributions declared per limited partner unit (in dollars per unit)	$ 0.31		$ 0.30		$ 0.23
Restricted Units
Common units
Restricted units granted				163,324
IPO
Common units
Common units issued in initial public offering						5,750,000
Underwriter's option
Common units
Common units issued in initial public offering						750,000
Directors | Long Term Incentive Plan | Restricted Units
Common units
Value of individual grants to certain directors		$ 30,000
Consultants | Long Term Incentive Plan | Restricted Units
Common units
Restricted units granted		4,247
Predecessor
Common units
Member distributions							$ 0	$ 3,200,000

EARNINGS PER UNIT (Details)

EARNINGS PER UNIT (Details) - USD ($)	Feb. 07, 2017	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings per unit
Net income (loss)			$ 1,715,740
Net income (loss) attributable to common units per unit (basic)			$ 0.11
Weighted average number of common units outstanding Basic (in units)			16,336,871
Net income (loss) attributable to common units per unit (diluted)			$ 0.10
Weighted average number of common units outstanding Diluted (in units)			16,455,602
Predecessor
Earnings per unit
Net income (loss)		$ (496,856)		$ (6,212,619)	$ (31,313,926)
Net income (loss) attributable to common units per unit (basic)		$ (0.82)		$ (10.28)	$ (51.83)
Weighted average number of common units outstanding Basic (in units)		604,137		604,137	604,137
Net income (loss) attributable to common units per unit (diluted)		$ (0.82)		$ (10.28)	$ (51.83)
Weighted average number of common units outstanding Diluted (in units)		604,137		604,137	604,137
Predecessor | Options
Earnings per unit
Antidilutive options outstanding	110,000			110,000	110,000

UNIT-BASED COMPENSATION (Detail

UNIT-BASED COMPENSATION (Details) - USD ($)	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Weighted-Average Exercise Price
Share-based compensation		$ 798,413
Long Term Incentive Plan
Unit-based compensation
Authorized issuance of units		2,041,600	2,041,600
Vesting period			3 years
Long Term Incentive Plan | First Anniversary
Unit-based compensation
Vesting percent			33.30%
Long Term Incentive Plan | Second Anniversary
Unit-based compensation
Vesting percent			33.30%
Long Term Incentive Plan | Third Anniversary
Unit-based compensation
Vesting percent			33.30%
Long Term Incentive Plan | Restricted Units
Unvested Units
Granted - service condition employees (in units)		143,318
Granted - service condition consultants (in units)		24,253
Granted - non-employee directors		9,520
Vested (in units)		(9,520)
Unvested at end of period (in units)		167,571	167,571
Unvested Weighted-Average Grant-Date Fair Value
Granted - service condition employees (in dollars per unit)		$ 18.655
Unvested at end of period (in dollars per unit)		18.655	$ 18.655
Weighted-Average Market-date Fair Value
Granted - service condition consultants (in dollars per unit)		$ 16.250
Granted - non-employee directors (in dollars per unit)		16.250
Unvested at end of period (in dollars per unit)		$ 16.250	$ 16.250
Weighted Average Remaining Contractual Term
Unvested contractual term, at end of period		1 year 4 months 11 days
Predecessor
Weighted-Average Exercise Price
Share-based compensation	$ 50,422			$ 605,059	$ 605,059
Predecessor | Long Term Incentive Plan
Unit-based compensation
Authorized issuance of units	110,000
Units
Outstanding, at beginning of period (in shares)	110,000	110,000	110,000
Outstanding, at end of period (in shares)	110,000			110,000
Weighted-Average Exercise Price
Outstanding, at beginning of period (dollars per unit)	$ 100	$ 100	$ 100
Outstanding, at end of period (dollars per unit)	$ 100			$ 100
Weighted-Average Remaining Contractual Term	7 years 11 months 1 day			8 years
Share-based compensation	$ 50,000			$ 600,000	$ 600,000

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($)	11 Months Ended
	Dec. 31, 2017	Feb. 08, 2017
Asset Retirement Obligations
Working interests	$ 0	$ 0
Asset Retirement Obligation	0	$ 0
Lease operating expense	$ 0

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details)	11 Months Ended
	Dec. 31, 2017USD ($)
Related Party Transactions
Outstanding receivable from certain employees	$ 12,550
Steward Royalties
Related Party Transactions
Payments made to related parties	297,917
Taylor Companies
Related Party Transactions
Payments made to related parties	366,667
K3 Royalties
Related Party Transactions
Payments made to related parties	110,000
Nail Bay Royalties
Related Party Transactions
Payments made to related parties	461,576
Duncan Management
Related Party Transactions
Payments made to related parties	$ 603,590

COMMITMENTS AND CONTINGENCIES43

COMMITMENTS AND CONTINGENCIES (Details)	Dec. 31, 2017USD ($)
COMMITMENTS AND CONTINGENCIES.
2,018	$ 127,506
2,019	130,180
2,020	91,126
2,021	50,784
2,022	29,624
Total	$ 429,220

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - $ / shares	Jan. 26, 2018	Oct. 27, 2017	Jul. 28, 2017	May 02, 2017
Subsequent events
Cash distributions declared per limited partner unit (in dollars per unit)		$ 0.31	$ 0.30	$ 0.23
Subsequent Event
Subsequent events
Cash distributions declared per limited partner unit (in dollars per unit)	$ 0.36
Subsequent Event | Long Term Incentive Plan | Restricted Units
Subsequent events
Number of common units allocated to the Partnership's long term incentive plan	326,654

SUPPLEMENTAL OIL AND GAS RESE45

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Other Disclosures (Details)	1 Months Ended	11 Months Ended	12 Months Ended
	Feb. 07, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017USD ($)segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Number of reporting segments | segment			1
Oil, natural gas and NGL interests
Proved		$ 297,609,797	$ 297,609,797
Total oil, natural gas and NGL interest		297,609,797	297,609,797
Accumulated depreciation, depletion, accretion and impairment		(15,394,238)	(15,394,238)
Net oil, natural gas and NGL interests capitalized		282,215,559	$ 282,215,559
Acquisition costs
Proved properties		297,609,797
Total		297,609,797
Developed costs
Total costs incurred on oil, natural gas and NGL activities		297,609,797
Results of operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities
Oil, natural gas and NGL revenue		30,665,092
Production and ad valorem taxes		(2,452,058)
Depreciation, depletion and accretion expense		(15,394,238)
Marketing and other deductions		(1,648,895)
Results of operations form oil, natural gas and NGLs		$ 11,169,901
Predecessor
Oil, natural gas and NGL interests
Proved				$ 70,888,121
Total oil, natural gas and NGL interest				70,888,121
Accumulated depreciation, depletion, accretion and impairment				(51,948,355)
Net oil, natural gas and NGL interests capitalized				18,939,766
Acquisition costs
Proved properties					$ 42,000
Total					42,000
Developed costs
Proved properties				78,159	464,680
Total				78,159	464,680
Total costs incurred on oil, natural gas and NGL activities				78,159	506,680
Results of operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities
Oil, natural gas and NGL revenue	$ 318,310			3,606,659	4,684,923
Production and ad valorem taxes	(19,651)			(280,474)	(426,885)
Depreciation, depletion and accretion expense	(113,639)			(1,604,208)	(4,008,730)
Impairment of oil and natural properties				(4,992,897)	(28,673,166)
Marketing and other deductions	(110,534)			(750,792)	(747,264)
Results of operations form oil, natural gas and NGLs	$ 74,486			$ (4,021,712)	$ (29,171,122)

SUPPLEMENTAL OIL AND GAS RESE46

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Proved Oil, Natural Gas and Natural Liquids Reserve Quantities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MMcfMBbls	Dec. 31, 2016MMcfMBbls
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Revisions of previous estimates	217
Purchase of minerals in place	3,355
Extensions, discoveries and other additions	973
Production	(1,181)
Net proved reserves at end of period	20,954
Net Proved Developed Reserves	15,403
Net Proved Undeveloped Reserves	5,551
Purchase of mineral and royalty interests | $	$ 29.3
Crude Oil and Condensate
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Revisions of previous estimates	(193)
Purchase of minerals in place	362
Extensions, discoveries and other additions	505
Production	(421)
Net proved reserves at end of period	7,463
Net Proved Developed Reserves	5,284
Net Proved Undeveloped Reserves	2,179
Natural Gas
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Revisions of previous estimates | MMcf	(1,535)
Purchase of minerals in place | MMcf	16,312
Extensions, discoveries and other additions | MMcf	2,261
Production | MMcf	(3,512)
Net proved reserves at end of period | MMcf	63,916
Net Proved Developed Reserves | MMcf	47,501
Net Proved Undeveloped Reserves | MMcf	16,415
Natural Gas Liquids
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Revisions of previous estimates	666
Purchase of minerals in place	274
Extensions, discoveries and other additions	91
Production	(175)
Net proved reserves at end of period	2,838
Net Proved Developed Reserves	2,202
Net Proved Undeveloped Reserves	636
Predecessor
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	17,590	17,096
Revisions of previous estimates		324
Purchase of minerals in place		69
Extensions, discoveries and other additions		1,227
Production		(1,126)
Net proved reserves at end of period		17,590
Net Proved Developed Reserves		12,157
Net Proved Undeveloped Reserves		5,433
Predecessor | Crude Oil and Condensate
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	7,210	6,827
Revisions of previous estimates		131
Purchase of minerals in place		45
Extensions, discoveries and other additions		637
Production		(430)
Net proved reserves at end of period		7,210
Net Proved Developed Reserves		4,879
Net Proved Undeveloped Reserves		2,331
Predecessor | Natural Gas
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period | MMcf	50,390	51,734
Revisions of previous estimates | MMcf		(852)
Purchase of minerals in place | MMcf		90
Extensions, discoveries and other additions | MMcf		2,851
Production | MMcf		(3,433)
Net proved reserves at end of period | MMcf		50,390
Net Proved Developed Reserves | MMcf		35,172
Net Proved Undeveloped Reserves | MMcf		15,218
Predecessor | Natural Gas Liquids
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities
Net proved reserves at beginning of period	1,982	1,647
Revisions of previous estimates		335
Purchase of minerals in place		9
Extensions, discoveries and other additions		115
Production		(124)
Net proved reserves at end of period		1,982
Net Proved Developed Reserves		1,416
Net Proved Undeveloped Reserves		566

SUPPLEMENTAL OIL AND GAS RESE47

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Standardized Measure (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Standardized Measure
Future cash inflows	$ 562,967
Future production costs	(45,652)
Future state margin taxes	(2,790)
Future net cash flows	514,525
Less 10% annual discount to reflect timing of cash flows	(298,973)
Standard measure of discounted future net cash flows	$ 215,552	$ 159,275
Predecessor
Standardized Measure
Future cash inflows		414,004
Future production costs		(32,034)
Future state margin taxes		(2,051)
Future net cash flows		379,919
Less 10% annual discount to reflect timing of cash flows		(220,643)
Standard measure of discounted future net cash flows		$ 159,276	$ 180,083

SUPPLEMENTAL OIL AND GAS RESE48

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Average Market Prices (Details)	12 Months Ended
	Dec. 31, 2017$ / Mcf$ / bbl	Dec. 31, 2016$ / bbl
Crude Oil and Condensate
Average Sales Prices
Average sales prices	51.34
Natural Gas
Average Sales Prices
Average sales prices | $ / Mcf	2.98
Predecessor | Crude Oil and Condensate
Average Sales Prices
Average sales prices		42.75
Predecessor | Natural Gas
Average Sales Prices
Average sales prices		2.49

SUPPLEMENTAL OIL AND GAS RESE49

SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Changes in Standardized Measure (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Changes in Standardized Measure
Standardized measure - beginning of period	$ 159,275
Sales, net of production costs	(29,288)
Net changes of prices and production costs related to future production	21,946
Extensions, discoveries and improved recovery, net of future production costs	10,064
Revisions of previous quantity estimates, net of related costs	2,248
Net changes in state margin taxes	301
Accretion of discount	15,928
Purchases of reserves in place	23,309
Timing differences and other	11,769
Standardized measure - end of period	215,552	$ 159,275
Predecessor
Changes in Standardized Measure
Standardized measure - beginning of period	$ 159,276	180,083
Sales, net of production costs		(24,280)
Net changes of prices and production costs related to future production		(23,321)
Extensions, discoveries and improved recovery, net of future production costs		11,253
Revisions of previous quantity estimates, net of related costs		2,974
Net changes in state margin taxes		(112)
Accretion of discount		18,008
Purchases of reserves in place		1,097
Timing differences and other		(6,426)
Standardized measure - end of period		$ 159,276