Document and Entity Information
Document and Entity Information - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Mar. 01, 2019 | Jun. 30, 2018 | |
Entity Registrant Name | Kimbell Royalty Partners, LP | ||
Entity Central Index Key | 0001657788 | ||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2018 | ||
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 | Accelerated Filer | ||
Entity Public Float | $ 285.7 | ||
Document Fiscal Year Focus | 2018 | ||
Document Fiscal Period Focus | FY | ||
Common Units | |||
Entity Common Stock, Shares Outstanding | 19,495,403 | ||
Class B | |||
Entity Common Stock, Shares Outstanding | 18,014,342 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Current assets | ||
Cash and cash equivalents | $ 15,773,987 | $ 5,625,495 |
Oil, natural gas and NGL receivables | 18,809,170 | 6,792,837 |
Commodity derivative assets | 2,981,117 | |
Accounts receivable and other current assets | 50,551 | 236,673 |
Total current assets | 37,614,825 | 12,655,005 |
Property and equipment, net | 429,602 | 165,232 |
Oil and natural gas properties | ||
Oil and natural gas properties, using full cost method of accounting ($280,304,353 and $0 excluded from depletion at December 31, 2018 and December 31, 2017, respectively) | 818,594,943 | 297,609,797 |
Less: accumulated depreciation, depletion, accretion and impairment | (107,779,453) | (15,394,238) |
Total oil and natural gas properties | 710,815,490 | 282,215,559 |
Commodity derivative assets | 1,246,829 | |
Loan origination costs, net | 3,178,627 | 255,208 |
Total assets | 753,285,373 | 295,291,004 |
Current liabilities | ||
Accounts payable | 1,331,081 | 316,486 |
Other current liabilities | 2,468,945 | 1,746,662 |
Commodity derivative liabilities | 183,957 | |
Total current liabilities | 3,800,026 | 2,247,105 |
Commodity derivative liabilities | 134,872 | |
Long-term debt | 87,309,544 | 30,843,593 |
Total liabilities | 91,109,570 | 33,225,570 |
Commitments and contingencies (Note 15) | ||
Mezzanine equity: | ||
Series A preferred units (110,000 units issued and outstanding as of December 31, 2018 and 0 units issued and outstanding as of December 31, 2017) | 69,449,006 | |
Unitholders' equity | ||
Common units (18,056,487 units issued and outstanding as of December 31, 2018 and 16,509,799 units issued and outstanding as of December 31, 2017) | 293,992,935 | 262,065,434 |
Class B units (19,453,258 units issued and outstanding as of December 31, 2018 and 0 units issued and outstanding as of December 31, 2017) | 972,663 | |
Total unitholders' equity | 294,965,598 | 262,065,434 |
Noncontrolling interest | 297,761,199 | |
Total equity | 592,726,797 | 262,065,434 |
Total liabilities, mezzanine equity and unitholders' equity | $ 753,285,373 | $ 295,291,004 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
CONSOLIDATED BALANCE SHEETS | ||
Oil and natural gas properties excluded from depletion | $ 280,304,353 | $ 0 |
Temporary equity, issued (in units) | 110,000 | 0 |
Temporary equity, outstanding (in units) | 110,000 | 0 |
Common units, issued (in units) | 18,056,487 | 16,509,799 |
Common units, outstanding (in units) | 18,056,487 | 16,509,799 |
Class B units, issued (in units) | 19,453,258 | 0 |
Class B units, outstanding (in units) | 19,453,258 | 0 |
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, 2018 | Dec. 31, 2016 | |
Gain (loss) on commodity derivative instruments | $ (318,829) | $ 3,331,548 | ||
Total revenues | 30,346,263 | 70,258,210 | ||
Costs and expenses | ||||
Production and ad valorem taxes | 2,452,058 | 4,399,667 | ||
Depreciation, depletion and accretion expense | 15,546,341 | 25,213,043 | ||
Impairment of oil and natural gas properties | 0 | 67,311,501 | ||
Marketing and other deductions | 1,648,895 | 4,652,313 | ||
General and administrative expense | 8,191,792 | 16,847,328 | ||
Total costs and expenses | 27,839,086 | 118,423,852 | ||
Operating (loss) income | 2,507,177 | (48,165,642) | ||
Other expense | ||||
Interest expense | 791,437 | 4,091,900 | ||
Net (loss) income before income taxes | 1,715,740 | (52,257,542) | ||
Provision for income taxes | 24,681 | |||
State income taxes | 24,681 | |||
Net (loss) income before Series A preferred unit distribution and accretion | 1,715,740 | (52,282,223) | ||
Distribution and accretion on Series A preferred units | (6,310,040) | |||
Net (loss) income | 1,715,740 | (58,592,263) | ||
Net loss attributable to noncontrolling interests | (1,855,681) | |||
Net (loss) income attributable to Kimbell Royalty Partners LP | 1,715,740 | (56,736,582) | ||
Distribution on Class B units | (30,967) | |||
Net (loss) income attributable to common units | $ 1,715,740 | $ (56,767,549) | ||
Net (loss) income attributable to common units | ||||
Net (loss) income attributable to common units per unit (basic) | $ 0.11 | $ (3.08) | ||
Net (loss) income attributable to common units per unit (diluted) | $ 0.10 | $ (3.08) | ||
Weighted average number of common units outstanding | ||||
Weighted average number of common units outstanding Basic (in units) | 16,336,871 | 18,442,234 | ||
Weighted average number of common units outstanding Diluted (in units) | 16,455,602 | 18,442,234 | ||
Predecessor | ||||
Total revenues | $ 318,310 | $ 3,606,659 | ||
Costs and expenses | ||||
Production and ad valorem taxes | 19,651 | 280,474 | ||
Depreciation, depletion and accretion expense | 113,639 | 1,604,208 | ||
Impairment of oil and natural gas properties | 0 | 4,992,897 | ||
Marketing and other deductions | 110,534 | 750,792 | ||
General and administrative expense | 532,035 | 1,746,218 | ||
Total costs and expenses | 775,859 | 9,374,589 | ||
Operating (loss) income | (457,549) | (5,767,930) | ||
Other expense | ||||
Interest expense | 39,307 | 424,841 | ||
Net (loss) income before income taxes | (496,856) | (6,192,771) | ||
Provision for income taxes | 19,848 | |||
State income taxes | 19,848 | |||
Net (loss) income before Series A preferred unit distribution and accretion | (496,856) | (6,212,619) | ||
Net (loss) income | (496,856) | (6,212,619) | ||
Net (loss) income attributable to Kimbell Royalty Partners LP | (496,856) | (6,212,619) | ||
Net (loss) income attributable to common units | $ (496,856) | $ (6,212,619) | ||
Net (loss) income attributable to common units | ||||
Net (loss) income attributable to common units per unit (basic) | $ (0.82) | $ (10.28) | ||
Net (loss) income attributable to common units per unit (diluted) | $ (0.82) | $ (10.28) | ||
Weighted average number of common units outstanding | ||||
Weighted average number of common units outstanding Basic (in units) | 604,137 | 604,137 | ||
Weighted average number of common units outstanding Diluted (in units) | 604,137 | 604,137 | ||
Oil, natural gas and NGL revenues | ||||
Revenue | $ 29,943,920 | $ 65,713,112 | ||
Oil, natural gas and NGL revenues | Predecessor | ||||
Revenue | $ 318,310 | $ 3,606,659 | ||
Lease bonus and other income | ||||
Revenue | $ 721,172 | $ 1,213,550 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN UNITHOLDERS' EQUITY AND PREDECESSOR MEMBERS' EQUITY - USD ($) | Common Units | Class B Common Units | Non Controlling Interest | Total |
Members' equity, beginning balance (Predecessor) at Dec. 31, 2015 | $ 14,239,422 | $ 14,239,422 | ||
Members' equity, beginning balance (in units) (Predecessor) at Dec. 31, 2015 | 604,137 | |||
Increase (Decrease) in Unitholders' Capital | ||||
Unit-based compensation | Predecessor | $ 605,059 | 605,059 | ||
Net loss before Series A preferred unit distribution and accretion | Predecessor | (6,212,619) | (6,212,619) | ||
Members' equity, ending balance (Predecessor) at Dec. 31, 2016 | $ 8,631,862 | 8,631,862 | ||
Members' equity, ending balance (in units) (Predecessor) at Dec. 31, 2016 | 604,137 | |||
Increase (Decrease) in Unitholders' Capital | ||||
Unit-based compensation | Predecessor | $ 50,422 | 50,422 | ||
Net loss before Series A preferred unit distribution and accretion | Predecessor | (496,856) | (496,856) | ||
Transfer of membership units to Rivercrest Royalties Holdings, LLC | Predecessor | $ (98,988) | (98,988) | ||
Transfer of membership units to Rivercrest Royalties Holdings, LLC (in units) | Predecessor | (604,137) | |||
Unitholders' capital, ending balance at Feb. 07, 2017 | $ 8,086,440 | 8,086,440 | ||
Increase (Decrease) in Unitholders' Capital | ||||
Common units issued to Predecessor in exchange for oil and natural gas properties (in units) | 1,191,974 | |||
Common units issued for acquisition | $ 169,033,212 | 169,033,212 | ||
Common units issued for acquisition (in units) | 9,390,734 | |||
Common units sold to public | $ 103,500,000 | 103,500,000 | ||
Common units sold to public (in units) | 5,750,000 | |||
Underwriting discount and structuring fee incurred at initial public offering | $ (7,245,000) | (7,245,000) | ||
Unit-based compensation | $ 798,413 | 798,413 | ||
Unit-based compensation (in units) | 177,091 | |||
Distributions to unitholders | $ (13,823,371) | (13,823,371) | ||
Net loss before Series A preferred unit distribution and accretion | 1,715,740 | 1,715,740 | ||
Unitholders' capital, ending balance at Dec. 31, 2017 | 262,065,434 | |||
Unitholders' capital, ending balance at Dec. 31, 2017 | $ 262,065,434 | $ 262,065,434 | ||
Unitholders' capital, ending balance (in units) at Dec. 31, 2017 | 16,509,799 | 16,509,799 | ||
Increase (Decrease) in Unitholders' Capital | ||||
Common units issued for acquisition | $ 235,400,000 | $ 235,400,000 | ||
Common units issued for acquisition (in units) | 10,000,000 | |||
Recapitalization related to tax conversion | $ (209,591,880) | $ 647,663 | $ 209,591,880 | 647,663 |
Recapitalization related to tax conversion (in units) | (12,953,258) | 12,953,258 | ||
Common units sold to public | $ 61,411,708 | 61,411,708 | ||
Common units sold to public (in units) | 3,450,000 | |||
Class B units issued for Drop Down acquisition | $ 325,000 | 90,025,000 | 90,350,000 | |
Class B units issued for Drop Down acquisition (in units) | 6,500,000 | |||
Unit-based compensation | $ 3,170,299 | 3,170,299 | ||
Unit-based compensation (in units) | 1,049,946 | |||
Distributions to unitholders | $ (38,303,043) | (38,303,043) | ||
Issuance of Series A preferred units | 36,607,966 | 36,607,966 | ||
Distributions on Series A redeemable preferred units | (4,510,648) | (1,799,392) | (6,310,040) | |
Distribution on Class B common units | (30,967) | (30,967) | ||
Net loss before Series A preferred unit distribution and accretion | (52,225,934) | (56,289) | (52,282,223) | |
Unitholders' capital, ending balance at Dec. 31, 2018 | 294,965,598 | |||
Unitholders' capital, ending balance at Dec. 31, 2018 | $ 293,992,935 | $ 972,663 | $ 297,761,199 | $ 592,726,797 |
Unitholders' capital, ending balance (in units) at Dec. 31, 2018 | 18,056,487 | 19,453,258 | 18,056,487 |
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, 2018 | Dec. 31, 2016 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||||
Net (loss) income before Series A preferred unit distribution and accretion | $ 1,715,740 | $ (52,282,223) | ||
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | ||||
Depreciation, depletion and accretion expense | 15,546,341 | 25,213,043 | ||
Impairment of oil and natural gas properties | 0 | 67,311,501 | ||
Amortization of loan origination costs | 57,292 | 466,002 | ||
Unit-based compensation | 798,413 | 3,170,299 | ||
(Gain) loss on commodity derivative instruments | 318,829 | (4,546,775) | ||
Changes in operating assets and liabilities: | ||||
Oil, natural gas and NGL receivables | (1,689,609) | (7,041,371) | ||
Accounts receivable and other current assets | (236,673) | 186,122 | ||
Accounts payable | 316,486 | 985,936 | ||
Other current liabilities | 1,746,662 | (259,554) | ||
Net cash provided by operating activities | 18,573,481 | 33,202,980 | ||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||
Purchases of property and equipment | (61,932) | (403,699) | ||
Proceeds from sale of oil and natural gas properties | 10,576,595 | |||
Purchase of oil and natural gas properties | (125,848,776) | (211,101,058) | ||
Net cash used in investing activities | (125,910,708) | (200,928,162) | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||
Proceeds from issuance of Series A preferred units, net of issuance costs | 103,359,603 | |||
Contributions from Class B unitholders | 972,663 | |||
Proceeds from equity offering | 61,411,708 | |||
Proceeds from initial public offering | 96,255,000 | |||
Distributions to unitholders | (13,823,371) | (38,303,043) | ||
Distributions on Series A preferred units | (2,630,834) | |||
Distributions to Class B unitholders | (12,953) | |||
Borrowings on long-term debt | 30,843,593 | 124,336,547 | ||
Repayments on long-term debt | (67,870,596) | |||
Payment of loan origination costs | (312,500) | (3,389,421) | ||
Net cash provided by financing activities | 112,962,722 | 177,873,674 | ||
NET INCREASE IN CASH AND CASH EQUIVALENTS | 5,625,495 | 10,148,492 | ||
CASH AND CASH EQUIVALENTS, beginning of period | 5,625,495 | |||
CASH AND CASH EQUIVALENTS, end of period | 5,625,495 | 15,773,987 | ||
Supplemental cash flow information: | ||||
Cash paid for interest | 455,228 | 3,285,387 | ||
Noncash investing and financing activities: | ||||
Units issued in exchange for oil and natural gas properties | 325,425,000 | |||
Distribution to Class B unitholders in accounts payable | 18,014 | |||
Distribution to Series A preferred unitholders in accounts payable | 981,837 | |||
Non-cash deemed distribution to Series A preferred units | 2,697,369 | |||
Capital expenditures and consideration payable included in accounts payable and other liabilities | 10,645 | |||
Predecessor | ||||
CASH FLOWS FROM OPERATING ACTIVITIES | ||||
Net (loss) income before Series A preferred unit distribution and accretion | $ (496,856) | $ (6,212,619) | ||
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | ||||
Depreciation, depletion and accretion expense | 113,639 | 1,604,208 | ||
Impairment of oil and natural gas properties | 0 | 4,992,897 | ||
Amortization of loan origination costs | 4,241 | 46,969 | ||
Amortization of tenant improvement allowance | (2,864) | (34,369) | ||
Unit-based compensation | 50,422 | 605,059 | ||
Changes in operating assets and liabilities: | ||||
Oil, natural gas and NGL receivables | 14,551 | (66,455) | ||
Accounts receivable and other current assets | 333,056 | 1,027,172 | ||
Accounts payable | 247,972 | (952,800) | ||
Other current liabilities | (77,442) | 76,541 | ||
Net cash provided by operating activities | 186,719 | 1,086,603 | ||
CASH FLOWS FROM INVESTING ACTIVITIES | ||||
Purchases of property and equipment | (19,305) | |||
Purchase of oil and natural gas properties | (523) | (78,159) | ||
Net cash used in investing activities | (523) | (97,464) | ||
CASH FLOWS FROM FINANCING ACTIVITIES | ||||
Repayments on long-term debt | (850,000) | |||
Payment of loan origination costs | (13,000) | |||
Net cash provided by financing activities | (863,000) | |||
NET INCREASE IN CASH AND CASH EQUIVALENTS | 186,196 | 126,139 | ||
CASH AND CASH EQUIVALENTS, beginning of period | 505,880 | 692,076 | $ 505,880 | 379,741 |
CASH AND CASH EQUIVALENTS, end of period | 692,076 | $ 505,880 | 505,880 | |
Supplemental cash flow information: | ||||
Cash paid for interest | 34,505 | 373,513 | ||
Cash paid for taxes | $ 5,355 | 25,892 | ||
Noncash investing and financing activities: | ||||
Capital expenditures and consideration payable included in accounts payable and other liabilities | $ (37) |
ORGANIZATION AND BASIS OF PRESE
ORGANIZATION AND BASIS OF PRESENTATION | 12 Months Ended |
Dec. 31, 2018 | |
ORGANIZATION AND BASIS OF PRESENTATION | |
ORGANIZATION AND BASIS OF PRESENTATION | Unless the context otherwise requi On February 8, 2017, the Partnership completed its initial public offering (“IPO”) of common units representing limited partner interests. The mineral and royalty interests comprising the Partnership’s initial assets were contributed to it by the Contributing Parties at the closing of its 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 periods on or prior to February 7, 2017 refers only to the Partnership’s Predecessor for accounting and financial reporting purposes and does not include the results of the Partnership as a whole. At the time of the Partnership’s IPO, the interests underlying the oil, natural gas and natural gas liquids (“NGLs”) production revenues of the Partnership’s 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. NOTE 1—ORGANIZATION Organization Kimbell Royalty Partners, LP is a Delaware limited partnership formed in 2015 to own and acquire mineral and royalty interests in oil and natural gas properties throughout the United States. Effective as of September 24, 2018, the Partnership has elected to be taxed as a corporation for United States federal income tax purposes. 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 acreage underlying its interests, net of post-production expenses and taxes. The Partnership is not obligated to fund drilling and completion costs, lease operating expenses or plugging and abandonment costs at the end of a well’s productive life. The Partnership’s primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, its Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which it owns an interest. 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. Restructuring, Tax Election and Related Transactions On July 24, 2018, the Partnership entered into a Recapitalization Agreement (the "Recapitalization Agreement"), Haymaker Minerals & Royalties, LLC, EIGF Aggregator III LLC, TE Drilling Aggregator LLC, Haymaker Management, LLC (collectively, the “Haymaker Holders”), the Kimbell Art Foundation, Haymaker Resources, LP, the General Partner and the Operating Company pursuant to which (a) the Partnership's equity interest in the Operating Company was recapitalized into 13,886,204 newly issued common units of the Operating Company ("OpCo Common Units") and 110,000 newly issued Series A Cumulative Convertible Preferred Units in the Operating Company and (b) the 10,000,000 and 2,953,258 common units held by the Haymaker Holders and the Kimbell Art Foundation, respectively, were exchanged for (i) 10,000,000 and 2,953,258 newly issued Class B common units representing limited partner interests of the Partnership ("Class B Units"), respectively, and (ii) 10,000,000 and 2,953,258 newly issued OpCo Common Units, respectively. The Class B Units and OpCo Common Units are exchangeable together into an equal number of common units of the Partnership. In May 2018, the General Partner’s Board of Directors (the “Board of Directors”) unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity via a “check the box” election (the “Tax Election”). The Tax Election became effective on September 24, 2018. In preparation for making this election, on September 23, 2018, the Partnership (i) amended and restated its Second Amended and Restated Limited Partnership Agreement, (ii) amended and restated the Limited Liability Company Agreement of the Operating Company and (iii) entered into an exchange agreement with the Haymaker Holders, the Kimbell Art Foundation, the General Partner and the Operating Company. Simultaneously with the effectiveness of these agreements, the transactions described in the Recapitalization Agreement were consummated. The transactions contemplated by the Recapitalization Agreement are referred to herein as the “Restructuring.” Pursuant to the terms of the Recapitalization Agreement, the Haymaker Holders and the Kimbell Art Foundation each paid five cents per Class B Unit to the Partnership as additional consideration with respect to the Class B Units (the “Class B Contribution”). The Haymaker Holders and the Kimbell Art Foundation, as holders of the Class B Units, are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A Preferred Units (as defined in Note 8—Preferred Units) but prior to distributions on the common units. Following the effectiveness of the Tax Election and the completion of the related transactions, the Partnership’s royalty and minerals business continues to be conducted through the Operating Company, which is taxed as a partnership for federal and state income tax purposes. The Operating Company passes income to the noncontrolling interest and the Partnership, which is treated as a corporation for federal and state income tax purposes. |
SUMMARY OF SIGNIFICANT ACCOUNTI
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2018 | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES 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 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, 2018, and 2017, 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. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within five years. 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 remained effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that the Partnership was required to assess the fair value of the acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of the acquired assets in the full-cost ceiling test would not be appropriate. The Partnership recorded an impairment expense on its oil and natural gas properties of $67.3 million during the year ended December 31, 2018. Of this amount, an impairment expense of $54.8 million was recorded as a result of the Partnership’s quarterly full-cost ceiling analysis for the three months ended March 31, 2018 following the expiration of the aforementioned exemption and an impairment expense booking proved of $12.6 million was recorded for the three months ended December 31, 2018 as a result of the Dropdown (as defined in Note 3—Acquisitions and Divestitures) purchase price exceeding the value of the proved developed reserves added to the full-cost ceiling. As the Partnership does not intend to book proved undeveloped reserves going forward, additional impairment charges could be recorded in connection with future acquisitions. Additional impairments may be required to be recorded due to the Partnership’s decision to voluntarily and ratably eliminate, over time, our existing PUD reserves. Further, if the price of oil, natural gas and NGLs decreases in future periods, the Partnership may be required to record additional impairments as a result of the full-cost ceiling limitation. 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 year ended December 31, 2016, the Predecessor recorded non-cash impairment charges of approximately $5.0 million, primarily due to changes in reserve values resulting from the reduction 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 year ended December 31, 2018, the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the year ended December 31, 2016. 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 year ended December 31, 2018, the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the year ended December 31, 2016. Other Current Liabilities Other current liabilities consist primarily of Series A Preferred Unit and Class B Unit distributions, accrued interest, revenue payable, accrued tax liability and ad valorem taxes. Income Taxes As discussed further in Note 1—Organization and Basis of Presentation, on May 28, 2018, the Partnership announced that the Board of Directors had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018. 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 Predecessor incurred de minimis amounts of state income taxes during the year ended December 31, 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, 2018 and 2017. The Partnership and Predecessor recognize interest and penalties related to uncertain tax positions in income tax expense. For the year ended December 31, 2018, the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, and the year 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. For the Predecessor, 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 year ended December 31, 2018, the Partnership’s top purchaser accounted for approximately 10% of oil, natural gas and NGL sales revenue. 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 from Contracts with Customers Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the operator. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index. Royalty income from oil, natural gas and natural gas liquids sales The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s royalty income contracts. Contract balances Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for one to four months after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. Identified differences between the Partnership’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded. 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—Fair Value Measurements for further discussion of the Partnership’s fair value measurements. New Accounting Pronouncements Recently Adopted Pronouncements In May 2014 the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers (Topic 606),” an ASU on a comprehensive new revenue recognition standard that supersedes Accounting Standards Codification (“ASC”) 605, “Revenue Recognition.” The new accounting guidance creates a framework under which an entity allocates the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities are 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. On January 1, 2018 the Partnership adopted ASU 2014 - 09 using the full retrospective method. The Partnership completed its review of a representative sample of revenue contracts covering its material revenue streams and determined that there is no impact to its consolidated financial statements, results of operations or liquidity. When comparing the Partnership’s historical revenue recognition to the newly applied revenue recognition under ASC 606 , there was no change to the amount or timing of revenue recognized. Therefore, no quantitative adjustment was required to be made to the prior periods presented in the unaudited interim condensed consolidated financial statements after the adoption of ASC 606 . Upon adoption, the Partnership did not alter its existing information technology and internal controls outside of the contract review processes in order to identify impacts of future revenue contracts the Partnership may enter into. In January 2017, the FASB issued 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. The Partnership adopted this update prospectively effective January 1, 2018. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations. In June 2018, the FASB issued ASU 2018-07, “Improvements to Nonemployee Share-Based Payment Accounting.” ASU 2018-07 simplifies the accounting for share-based payments to nonemployees by aligning it with the accounting for share-based payments to employees, with certain exceptions. The amendments in this ASU are effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year, with early adoption permitted. The Partnership early adopted ASU 2018-07 effective January 1, 2018. This standard substantially aligned the accounting for share based payments to employees and nonemployees. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations. Accounting Pronouncements Not Yet Adopted In July 2018, the FASB issued 2018-09, “Codification Improvements.” This update provides clarification and corrects unintended application of the guidance in various sections. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership is currently evaluating the impact of the adoption of this update but does not believe it will have a material impact on its financial position, results of operations or liquidity. The Partnership is still evaluating the impact of this standard. In July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842, Leases.” This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity. In July 2018, the FASB issued ASU 2018-11, “Lease (Topic 842): Targeted Improvements.” This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity. 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 adoption of this update will have a $3.4 million to $4.2 million impact on its financial position, results of operations or liquidity. |
ACQUISITIONS AND DIVESTITURES
ACQUISITIONS AND DIVESTITURES | 12 Months Ended |
Dec. 31, 2018 | |
ACQUISITIONS AND DIVESTITURES | |
ACQUISITIONS AND DIVESTITURES | NOTE 3—ACQUISITIONS AND DIVESTITURES 2018 Activity In May 2018, the Partnership executed two purchase and sale agreements to sell a small portion of its Delaware Basin acreage for $10.6 million, which was recorded as a reduction in the full-cost pool, with no gain or loss recorded on the sale. At the time of the divestiture, the sales represented approximately 29 barrels of equivalent (“Boe”) per day of production, less than 0.8% of total production and 59 net royalty acres, approximately 0.08% of total net royalty acres. On July 12, 2018, the Partnership completed the acquisition (the “Haymaker Acquisition”) of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, LP (together, “Haymaker”). The purchase price for the Haymaker Acquisition was comprised of (i) cash consideration of approximately $216.8 million, which was reduced by approximately $6.4 million of cash acquired and by approximately $9.3 million for net cash received or receivable by the Partnership for oil and natural gas production revenue occurring prior to the closing date of July 12, 2018 and increased by approximately $7.5 million in capitalized transaction costs for a net amount of approximately $208.6 million (the “Cash Consideration”), and (ii) 10,000,000 common units of the Partnership, valued at approximately $235.4 million based on the closing price of $23.54 on July 12, 2018. The Partnership funded the Cash Consideration with borrowings under the Amended Credit Agreement (as defined in Note 7 — Long Term Debt) and net proceeds from the Preferred Unit Transaction (as defined in Note 8 — Preferred Units). The assets acquired in the Haymaker Acquisition consist of approximately 5.4 million gross acres and 43,000 net royalty acres. The following unaudited pro forma results of operations reflect the Partnership’s results as if the Haymaker Acquisition had occurred on January 1, 2017. In the Partnership’s opinion, all significant adjustments necessary to reflect the effects of the acquisitions have been made. Pro forma data may not be indicative of the results that would have been obtained had these events occurred at the beginning of the periods presented, nor is it intended to be a projection of future results. Year Ended December 31, Year Ended December 31, 2018 2017 Total revenues $ 70,258,210 $ 80,292,349 Net (loss) income attributable to common units $ (56,767,549) $ 922,095 Net (loss) income attributable to common units Basic $ (3.08) $ 0.04 Diluted $ (3.08) $ 0.03 On December 20, 2018, the Partnership completed the acquisition (the “Dropdown”) of (i) certain overriding royalty, royalty and other mineral interests from Rivercrest Capital Partners LP, the Kimbell Art Foundation, and Cupola Royalty Direct, LLC, as well as all of the interests of a subsidiary of Rivercrest Royalties Holdings II, LLC in exchange for a total of 6,500,000 OpCo Common Units and an equal number of Class B Units. The assets acquired in the Dropdown consist of approximately 1.0 million gross acres and 16,700 net royalty acres. 2017 Activity 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, 2018 | |
DERIVATIVES | |
DERIVATIVES | NOTE 4—DERIVATIVES The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts, and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. At December 31, 2018 , 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. The Partnership hedges its daily production based on the amount of debt and/or preferred equity as a percent of its enterprise value. This amount constitutes approximately 24% of daily oil and natural gas production. The Partnership’s oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and its 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. 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: Year Ended December 31, Period from 2018 2017 Beginning fair value of commodity derivative instruments $ (318,829) $ — Gain (loss) on commodity derivative instruments 3,331,548 (318,829) Net cash paid on settlements of derivative instruments 1,215,227 — Ending fair value of commodity derivative instruments $ 4,227,946 $ (318,829) The following table presents the fair value of the Partnership’s derivative contracts as of December 31, 2018 and 2017: December 31, December 31, Classification Balance Sheet Location 2018 2017 Assets: Current asset Commodity derivative assets $ 2,981,117 $ — Long-term asset Commodity derivative assets 1,246,829 — Liabilities: Current liability Commodity derivative liabilities — (183,957) Long-term liability Commodity derivative liabilities — (134,872) $ 4,227,946 $ (318,829) At December 31, 2018, the Partnership’s open commodity derivative contracts consisted of the following: Oil Price Swaps Notional Weighted Average Range (per Bbl) Volumes (Bbl) Fixed Price (per Bbl) Low High December 2018 19,034 $ 64.28 $ 56.00 $ 66.25 January 2019 - December 2019 224,110 $ 61.47 $ 53.07 $ 63.47 January 2020 - December 2020 224,356 $ 55.48 $ 50.45 $ 61.43 Natural Gas Price Swaps Notional Weighted Average Range (per MMBtu) Volumes (MMBtu) Fixed Price (per MMBtu) Low High January 2019 - December 2019 3,859,145 $ 2.74 $ 2.74 $ 2.76 January 2020 - December 2020 3,582,862 $ 2.64 $ 2.51 $ 2.94 |
FAIR VALUE MEASUREMENTS
FAIR VALUE MEASUREMENTS | 12 Months Ended |
Dec. 31, 2018 | |
FAIR VALUE MEASUREMENTS | |
FAIR VALUE MEASUREMENTS | NOTE 5—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 noted below. The carrying values of cash, oil, natural gas and NGL receivables, accounts receivable and other current assets and current and long-term liabilities included in the consolidated balance sheets approximated fair value at December 31, 2018 and 2017. As a result, these financial assets and liabilities are not discussed below. · Level 1—Unadjusted quoted market prices for identical assets or liabilities in active markets. · Level 2—Quoted prices for similar assets or liabilities in non-active markets, or inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the asset or liability. · Level 3— Measurement based on prices or valuations models that require inputs that are both unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value). Assets and liabilities that are measured at fair value are classified based on the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The Partnership recognizes transfers between fair value hierarchy levels as of the end of the reporting period in which the event or change in circumstances causing the transfer occurred. The Partnership did not have any transfers between Level 1, Level 2 or Level 3 fair value measurements during the years ended December 31, 2018 and 2017. 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. |
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES | 12 Months Ended |
Dec. 31, 2018 | |
OIL AND NATURAL GAS PROPERTIES | |
OIL AND NATURAL GAS PROPERTIES | NOTE 6—OIL AND NATURAL GAS PROPERTIES Oil and natural gas properties consists of the following: December 31, December 31, 2018 2017 Oil and natural gas properties Proved properties $ 538,290,590 $ 297,609,797 Unevaluated properties 280,304,353 — Less: accumulated depreciation, depletion and impairment (107,779,453) (15,394,238) Total oil and natural gas properties $ 710,815,490 $ 282,215,559 Costs associated with unevaluated properties are excluded from the full cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within five years. Costs associated with unevaluated properties are excluded from the full cost pool until the Partnership has made a determination as to the existence of proved reserves. The Partnership assesses all items classified as unevaluated property on an annual basis for possible impairment. The Partnership assesses properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: operators’ intent to drill; remaining lease term; geological and geophysical evaluations; operators’ drilling results and activity; the assignment of proved reserves; and the economic viability of operator development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. The Partnership recorded an impairment expense on its oil and natural gas properties of $67.3 million during the year ended December 31, 2018, as a result of its quarterly full cost ceiling analysis during the three months ended March 31, 2018 and December 31, 2018. No impairment expense was recorded for the period from February 8, 2017 to December 31, 2017 or for the Predecessor 2017 Period. During the year ended December 31, 2016, the Predecessor recorded a non-cash impairment charge of $5.0 million primarily due to changes in reserve values resulting from the decline in commodity prices and other factors. |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2018 | |
LONG-TERM DEBT. | |
LONG-TERM DEBT | NOTE 7—LONG-TERM DEBT In connection with its IPO, on January 11, 2017, the Partnership entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto, providing for a $50.0 million secured revolving credit facility secured by substantially all of its assets and the assets of its wholly owned subsidiaries. The secured revolving credit facility permitted aggregate commitments under the secured revolving credit facility to be increased up to $100.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. On July 12, 2018, in connection with the Haymaker Acquisition, the Partnership entered into an amendment (the “Credit Agreement Amendment”) to the Partnership’s 2017 Credit Agreement (the 2017 Credit Agreement as amended by the Credit Agreement Amendment, the “Amended Credit Agreement”), by and among the Partnership, certain subsidiaries of the Partnership as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto. The Credit Agreement Amendment increased commitments under the Amended Credit Agreement from $50.0 million to $200.0 million. Under the Amended Credit Agreement, availability under the secured revolving credit facility will equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The borrowing base under the Amended Credit Agreement was set at $200.0 million and was reaffirmed at $200.0 million in connection with the November 1, 2018 redetermination date. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased to $500.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The borrowing base will be redetermined semiannually on November 1 and May 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 the Partnership’s wholly owned subsidiaries and the next redetermination date will be May 1, 2019. The secured revolving credit facility matures on February 8, 2022. The Credit Agreement Amendment amended the 2017 Credit Agreement to provide for, among other things, (i) the addition of the subsidiaries the Partnership acquired in the Haymaker Acquisition, as well as the Operating Company, as guarantors under the Amended Credit Agreement, (ii) limitations on the Partnership’s ability to incur certain debt or issue preferred equity, (iii) limitations on redemptions of the Series A Preferred Units and the ability of the Partnership and the restricted subsidiaries of the Partnership to make distributions and other restricted payments, in each case, unless certain conditions are satisfied, (iv) increased limitations on the Partnership’s ability to dispose of certain assets or encumber certain assets, (v) a decrease in the applicable margin under the 2017 Credit Agreement, which varies based upon the level of borrowing base usage, by 0.25% for each applicable level as set forth in the Amended Credit Agreement, such that the applicable margin will range from 1.00% to 2.00% in the case of ABR Loans (as defined in the Amended Credit Agreement) and 2.00% to 3.00% in the case of LIBOR Loans (as defined in the Amended Credit Agreement) and (vi) the addition of certain restrictions on the Partnership’s and the Operating Company’s ability to take certain actions or amend their organizational documents. The Amended Credit Agreement 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 Amended Credit Agreement 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 Amended Credit Agreement also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control. During the year ended December 31, 2018, the Partnership borrowed an additional $124.4 million under the secured revolving credit facility and repaid $67.9 million of the total outstanding borrowings. As of December 31, 2018, the Partnership’s outstanding balance was $87.3 million. The Partnership was in compliance with all covenants included in the secured revolving credit facility as of December 31, 2018. As of December 31, 2018, borrowings under the secured revolving credit facility bore interest at LIBOR plus a margin of 2.25% or Prime Rate (as defined in the secured revolving credit facility) plus a margin of 1.25%. For the year ended December 31, 2018, the weighted average interest rate on the Partnership’s outstanding borrowings was 4.61%. |
PREFERRED UNITS
PREFERRED UNITS | 12 Months Ended |
Dec. 31, 2018 | |
PREFERRED UNITS | |
PREFERRED UNITS | NOTE 8—PREFERRED UNITS Preferred Purchase Agreement In July 2018, in connection with the closing of the Haymaker Acquisition, the Partnership completed the private placement of 110,000 Series A Preferred Units to certain affiliates of Apollo Capital Management, L.P. (the “Series A Purchasers”) for $1,000 per Series A Preferred Unit, resulting in gross proceeds to the Partnership of $110.0 million. Until the conversion of the Series A Preferred Units into common units or their redemption, holders of the Series A Preferred Units are entitled to receive cumulative quarterly distributions equal to 7.0% per annum plus accrued and unpaid distributions. In connection with the issuance of the Series A Preferred Units, the Partnership granted holders of the Series A Preferred Units board observer rights beginning on the third anniversary of the original issuance date, and board appointment rights beginning the fourth anniversary of the original issuance date and in the case of events of default with respect to the Series A Preferred Units. The following table summarizes the changes in the number of the Series A Preferred Units: Series A Preferred Units Balance at December 31, 2017 — Series A Preferred Units issued 110,000 Balance at December 31, 2018 110,000 |
UNITHOLDERS' EQUITY AND PARTNER
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS | 12 Months Ended |
Dec. 31, 2018 | |
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS | |
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS | NOTE 9—UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS The Partnership has limited partner units. At December 31, 2018, the Partnership had a total of 18,056,487 common units issued and outstanding and 19,453,258 Class B Units outstanding. The following table summarizes the changes in the number of the Partnership’s common units: Common Units Balance at December 31, 2017 16,509,799 Common units issued under the LTIP (1) 1,049,946 Common units issued for acquisition 10,000,000 Common units issued for equity offering (2) 3,450,000 Unit exchange related to tax conversion (12,953,258) Balance at December 31, 2018 18,056,487 (1) Includes 720,283 and 326,654 restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on December 7, 2018 and January 29, 2018, respectively, 4,478 of restricted units granted to a new director under the LTIP on May 9, 2018, and the forfeiture of 1,469 units. (2) On October 1, 2018, the Partnership completed an underwritten public offering of 3,450,000 common units, including an additional 450,000 common units in connection with the exercise of the underwriters’ option to purchase additional common units, for net proceeds of approximately $61.8 million. The Partnership used the net proceeds to purchase OpCo Common Units. The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under the Partnership’s secured revolving credit facility. The following table presents information regarding the common unit cash distributions approved by the Board of Directors for the periods presented: Amount per Date Unitholder Payment Common Unit Declared Record Date Date Q1 2018 $ 0.42 April 27, 2018 May 7, 2018 May 14, 2018 Q2 2018 $ 0.43 July 27, 2018 August 6, 2018 August 13, 2018 Q3 2018 $ 0.45 October 26, 2018 November 5, 2018 November 12, 2018 Q4 2018 $ 0.40 January 25, 2019 February 4, 2019 February 11, 2019 Q1 2017 (1) $ 0.23 May 2, 2017 May 8, 2017 May 15, 2017 Q2 2017 $ 0.30 July 28, 2017 August 7, 2017 August 14, 2017 Q3 2017 $ 0.31 October 27, 2017 November 6, 2017 November 13, 2017 Q4 2017 $ 0.36 January 26, 2018 February 7, 2018 February 14, 2018 (1) 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. The Predecessor made no distributions during the year ended December 31, 2016. The following table summarizes the changes in the number of the Partnership’s Class B Units: Class B Units Balance at December 31, 2017 — Unit exchange related to Tax Election 12,953,258 Class B Units issued for Dropdown (1) 6,500,000 Balance at December 31, 2018 19,453,258 (1) See Note 3—Acquisition and Divestitures for discussion regarding the Dropdown. Pursuant to the terms of the Recapitalization Agreement, the Haymaker Holders and the Kimbell Art Foundation, as holders of the Class B Units, are entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution, subsequent to distributions on the Series A Preferred Units but prior to distributions on the common units. The Class B Units and OpCo Common Units are exchangeable together into an equal number of common units of the Partnership. See Recapitalization Agreement in Note 1 for further detail. |
EARNINGS (LOSS) PER UNIT
EARNINGS (LOSS) PER UNIT | 12 Months Ended |
Dec. 31, 2018 | |
EARNINGS (LOSS) PER UNIT | |
EARNINGS (LOSS) PER UNIT | NOTE 10—EARNINGS (LOSS) PER UNIT Basic earnings (loss) per unit (“EPU”) is calculated by dividing net income (loss) attributable to common units 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, potential conversion of Class B Units and unvested options granted under the Predecessor’s long-term incentive plan as described in Note 11—Unit-Based Compensation. The following table summarizes the calculation of weighted average common shares outstanding used in the computation of diluted earnings (loss) per share: Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Net (loss) income attributable to common units $ (56,767,549) $ 1,715,740 $ (496,856) $ (6,212,619) Weighted average number of common units outstanding: Basic 18,442,234 16,336,871 604,137 604,137 Effect of dilutive securities: Restricted stock units — 118,731 — — Class B units — — — — Diluted 18,442,234 16,455,602 604,137 604,137 Net (loss) income attributable to common units Basic $ (3.08) $ 0.11 $ (0.82) $ (10.28) Diluted $ (3.08) $ 0.10 $ (0.82) $ (10.28) The calculation of diluted net loss per share for the year ended December 31, 2018 excludes the conversion of the Class B Units to common units and 1,157,924 of non-vested shares of restricted stock units issuable upon vesting, because their inclusion in the calculation would be anti-dilutive. For the Predecessor 2017 period and the year ended December 31, 2016, 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. |
UNIT-BASED COMPENSATION
UNIT-BASED COMPENSATION | 12 Months Ended |
Dec. 31, 2018 | |
UNIT-BASED COMPENSATION | |
UNIT-BASED COMPENSATION | NOTE 11—UNIT-BASED COMPENSATION On September 23, 2018, the General Partner entered into the First Amendment to the LTIP, which increased the number of common units eligible for issuance under the LTIP by 2,500,000 common units for a total of 4,541,600 common units. The Partnership’s LTIP authorizes grants to its employees, directors and consultants. The restricted units issued under the Partnership’s 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. After the adoption of ASU 2018-07, compensation expense for consultants will be treated in the same manner as that of the employees and directors. Distributions related to the restricted units are paid concurrently with the Partnership’s distributions for common units. The fair value of the Partnership’s restricted units issued under the LTIP to the Partnership’s employees, directors and consultants is determined by utilizing the market value of the Partnership’s common units on the respective grant date. Weighted Weighted Average Average Grant-Date Remaining Fair Value Contractual Units per Unit Term Unvested at December 31, 2017 167,571 $ 18.655 1.364 years Granted - service condition employees 622,212 17.894 — Granted - service condition consultants 31,238 17.588 — Granted - non-employee directors 397,965 18.183 — Forfeited (1,469) (17.610) — Vested (59,593) (18.695) — Unvested at December 31, 2018 1,157,924 $ 18.054 2.696 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. For the Predecessor 2017 Period and the year ended December 31, 2016, total compensation expense for awards under the long-term incentive plan was $0.05 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. |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2018 | |
INCOME TAXES | |
INCOME TAXES | NOTE 12—INCOME TAXES As discussed further in Note 1, on May 28, 2018, the Partnership announced that the Board of Directors had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018. Subsequent to the Partnership’s change in tax status, the Partnership’s provision for income taxes for the year ended December 31, 2018 was based on the estimated annual effective tax rate plus discrete items. The Partnership’s effective income tax rate was (0.5)% for the year ended December 31, 2018. The Partnership incurred a tax loss for the current year and thus, no current income taxes will be due. This tax loss results in a net operating loss carryforward at December 31, 2018 for federal and state purposes of $0.6 million and $0.07 million, respectively. Prior to September 24, 2018, the effective date of the Partnership’s change in income tax status, the Partnership was organized as a pass-through entity for income tax purposes. As a result, the Partnership’s partners were responsible for federal income taxes on their share of the Partnership’s taxable income with the exception of any entity-level income taxes such as the Texas margin tax. Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Current Federal $ — $ — $ — $ — State 24,681 — — 19,848 Total Current 24,681 — — 19,848 Deferred Federal — — — — State — — — — Total Deferred — — — — Provision for income taxes $ 24,681 $ — $ — $ 19,848 The Partnership’s income tax expense differs from the amount derived by applying the statutory federal rate to pretax loss principally due the effect of the following items: Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Net (loss) income before taxes $ (52,257,542) $ 1,715,740 $ (496,856) $ (6,192,771) Statutory rate 21 % 35 % 35 % 35 % Income tax expense computed at statutory rate (10,974,084) 600,509 (173,900) (2,167,470) Reconciling items: State income taxes (70,441) — — — Texas margin tax 24,681 — — 19,848 Change in tax status (20,038,820) — — — Noncontrolling interest (360,082) — — — Income (loss) not subject to corporate tax 10,598,375 (600,509) 173,900 2,167,470 Change in valuation allowance - federal 20,771,214 — — — Change in valuation allowance - state 70,441 — — — Other, net 3,397 — — — Provision for income taxes $ 24,681 $ — $ — $ 19,848 Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of the Partnership’s deferred taxes are detailed in the table below. Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Deferred tax asset Outside basis in OpCo $ 21,036,307 $ — $ — $ — Federal tax loss carryforwards 622,775 — — — State tax loss carryforwards 70,441 — — — Deferred tax asset 21,729,523 — — — Valuation allowance (20,841,655) — — — Net deferred tax asset $ 887,868 $ — $ — $ — Deferred tax liability Derivative instruments and other 887,868 — — — Net deferred tax liability $ 887,868 $ — $ — $ — Reflected in the accompanying balance sheet as: Net deferred tax asset $ — $ — $ — $ — Net deferred tax liability $ — $ — $ — $ — The Partnership has United States federal tax loss carryforwards (“NOL”) of approximately $0.6 million as of December 31, 2018. The tax years ended December 31, 2015 through 2018 remain open to examination under the applicable statute of limitations in the United States and other jurisdictions in which the Partnership and its subsidiaries file income tax returns. However, the statute of limitations for examination of NOLs and other similar attribute carryforwards does not commence until the year the attribute is utilized. In some instances, state statutes of limitations are longer than those under United States federal tax law . The Partnership believes that it is more likely than not that the benefit from the outside basis differences in the Partnership’s investment in the Operating Company and certain NOL carryforwards will not be realized. In recognition of this risk, the Partnership has provided a valuation allowance of $17.0 million on the deferred tax assets relating to the outside basis differences in the Partnership’s investment in the Operating Company and the NOL carryforwards. As of December 31, 2018, the Partnership has not recorded a reserve for any uncertain tax positions. No federal income tax payments are expected in the upcoming four quarterly reporting periods. |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2018 | |
RELATED PARTY TRANSACTIONS | |
RELATED PARTY TRANSACTIONS | NOTE 13—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 year ended December 31, 2018, the Partnership made payments to Steward Royalties, Taylor Companies, K3 Royalties, Nail Bay Royalties and Duncan Management in the amount of $130,000, $526,855, $120,000, $356,837 and $521,981, respectively. Certain consultants who provide services under the above mentioned management services agreements are granted restricted units under the Partnership’s LTIP. During the Predecessor 2017 Period and the year ended December 31, 2016, the Predecessor had certain related party receivables and payables; however, such amounts are de minimis. |
ADMINISTRATIVE SERVICES
ADMINISTRATIVE SERVICES | 12 Months Ended |
Dec. 31, 2018 | |
ADMINISTRATIVE SERVICES | |
ADMINISTRATIVE SERVICES | NOTE 14—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 13―Related Party Transactions. Transition Services Agreement On July 12, 2018, pursuant to the Haymaker Acquisition, the Partnership entered into a Transition Services Agreement (the “Transition Services Agreement”) with Haymaker Services, LLC (“Haymaker Services”). Pursuant to the Transition Services Agreement, Haymaker Services provided certain administrative services and accounting assistance on a transitional basis for total compensation of approximately $2.3 million through December 31, 2018, at which point, the Transition Services Agreement terminated. Such costs are included in general and administrative expense in the accompanying consolidated statement of operations. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2018 | |
COMMITMENTS AND CONTINGENCIES. | |
COMMITMENTS AND CONTINGENCIES | NOTE 15—COMMITMENTS AND CONTINGENCIES Leases The Partnership leases certain office space under non-cancelable operating leases that end at various dates through 2029. 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, 2018: f Years Ending December 31, 2019 $ 369,079 2020 522,904 2021 488,253 2022 488,253 2023 492,236 Thereafter 2,761,280 Total $ 5,122,005 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, 2018 | |
SUBSEQUENT EVENTS | |
SUBSEQUENT EVENTS | NOTE 16—SUBSEQUENT EVENTS The Partnership has evaluated events that occurred subsequent to December 31, 2018 in the preparation of its financial statements. On February 6, 2019, the Partnership paid a quarterly cash distribution on the Series A Preferred Units of $17.27 per Series A Preferred Unit, resulting in a total quarterly distribution of approximately $1.9 million for the quarter ended December 31, 2018. On January 25, 2019, the Board of Directors declared a quarterly cash distribution of $0.40 per common unit for the quarter ended December 31, 2018. The distribution was paid on February 11, 2019 to common unitholders of record as of the close of business on February 4, 2019. The difference between the declared distribution and the cash available for distribution is primarily attributable to the assets acquired in the Dropdown being effective on October 1, 2018, but only reflected in the condensed consolidated financial statements from December 20, 2018 onward. On February 6, 2019, the Partnership agreed to acquire all of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC that own oil and natural gas mineral and royalty interests (the “Phillips Acquisition”). The proposed aggregate consideration for the Phillips Acquisition consists of 9,400,000 OpCo Common Units and an equal number of Class B Units, with an approximate value of $151.3 million. At the time of the filing of this Annual Report, the Phillips Acquisition has not closed and is expected to close in late March 2019. The closing of the Phillips Acquisition remains subject to the satisfaction of certain closing conditions, and there can be no assurance that it will be completed as planned or at all . |
SUPPLEMENTAL OIL AND GAS RESERV
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) | 12 Months Ended |
Dec. 31, 2018 | |
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) | |
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) | NOTE 17—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: December 31, December 31, 2018 2017 Oil, natural gas and NGL interests Proved properties $ 538,290,590 $ 297,609,797 Unevaluated properties 280,304,353 — Total oil, natural gas and NGL interests 818,594,943 297,609,797 Accumulated depreciation, depletion, accretion and impairment (107,779,453) (15,394,238) Net oil, natural gas and NGL interests capitalized $ 710,815,490 $ 282,215,559 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 Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2018 2016 Acquisition costs Proved properties $ 243,227,632 $ 297,609,797 $ — $ — Unevaluated properties 288,334,110 — — — Total 531,561,742 297,609,797 — — Development costs Proved properties — — — 78,159 Total — — — 78,159 Total costs incurred on oil, natural gas and NGL activities $ 531,561,742 $ 297,609,797 $ — $ 78,159 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’s or Predecessor’s oil, natural gas and NGL operations. Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Oil, natural gas and NGL revenues $ 65,713,112 $ 29,943,920 $ 318,310 $ 3,606,659 Lease bonus and other income 1,213,550 721,172 — — Production and ad valorem taxes (4,399,667) (2,452,058) (19,651) (280,474) Depreciation, depletion and accretion expense (25,213,043) (15,394,238) (113,639) (1,604,208) Impairment of oil and natural gas properties (67,311,501) — — (4,992,897) Marketing and other deductions (4,652,313) (1,648,895) (110,534) (750,792) Results of operations from oil, natural gas and NGLs $ (34,649,862) $ 11,169,901 $ 74,486 $ (4,021,712) 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, 2018, 2017 and 2016. 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 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 Revisions of previous estimates (1) 194 1,754 952 1,437 Purchase of minerals in place (6) 3,729 69,465 2,166 17,473 Production (591) (7,874) (310) (2,213) Net proved reserves at December 31, 2018 10,795 127,261 5,646 37,651 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 December 31, 2018 9,183 116,321 5,063 33,633 Net Proved Undeveloped Reserves December 31, 2016 2,331 15,218 566 5,433 December 31, 2017 2,179 16,415 636 5,551 December 31, 2018 1,612 10,940 583 4,018 (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 the Partnership’s 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 the Partnership’s acreage primarily in the Permian Basin, Eagle Ford Shale. (6) Includes the acquisition of two packages of diverse mineral and royalty interests for a total of $243.2 million. The first acquisition totaling $155.7 million consists of mineral and royalty interests primarily in the Permian Basin, Haynesville Shale, Mid-Continent Area and Appalachia Region. The second acquisition totaling $87.5 million consists of mineral and royalty interests primarily in the Permian Basin, Eagle Ford Shale and Appalachia Region. 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, 2018 2017 2016 Future cash inflows $ 1,056,464 $ 562,967 $ 414,004 Future production costs (79,724) (45,652) (32,034) Future state margin taxes (32,885) (2,790) (2,051) Future income tax expense (41,241) — — Future net cash flows 902,614 514,525 379,919 Less 10% annual discount to reflect timing of cash flows (504,247) (298,973) (220,643) Standard measure of discounted future net cash flows $ 398,367 $ 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 2018, 2017 and 2016 were $65.56, $51.34 and $42.75 per barrel for crude oil and $3.10, $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 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. 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, 2018 2017 2016 Standardized measure - beginning of year $ 215,552 $ 159,275 $ 180,083 Sales, net of production costs (56,661) (29,288) (24,280) Net changes of prices and production costs related to future production 11,355 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 16,385 2,248 2,974 Net changes in state margin taxes (13,271) 301 (112) Net changes in income taxes (17,232) — — Accretion of discount 21,555 15,928 18,008 Purchases of reserves in place 175,885 23,309 1,097 Timing differences and other 44,799 11,769 (6,426) Standardized measure - end of year $ 398,367 $ 215,552 $ 159,276 |
SELECTED QUARTERLY FINANCIAL IN
SELECTED QUARTERLY FINANCIAL INFORMATION - Unaudited | 12 Months Ended |
Dec. 31, 2018 | |
Selected Quarterly Financial information - Unaudited | |
Selected Quarterly Financial Information - Unaudited | KIMBELL ROYALTY PARTNERS, LP SELECTED QUARTERLY FINANCIAL DATA - UNAUDITED Selected Quarterly Financial Information—Unaudited Quarterly financial data was as follows for the periods indicated. Partnership First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Total revenue $ 10,891,338 $ 10,707,898 $ 18,407,956 $ 30,251,018 Net (loss) income attributable to common units $ (52,824,471) $ 1,378,295 $ (3,711,798) $ (1,609,575) Net (loss) income attributable to common units Basic $ (3.23) $ 0.08 $ (0.15) $ (0.10) Diluted $ (3.23) $ 0.08 $ (0.15) $ (0.10) Cash distributions declared and paid $ 0.42 $ 0.43 $ 0.45 $ 0.40 Total assets $ 237,201,565 $ 249,318,570 $ 683,893,161 $ 753,285,373 Long-term debt $ 30,843,593 $ 42,972,997 $ 148,309,544 $ 87,309,544 Mezzanine equity $ — $ — $ 67,904,422 $ 69,449,006 Partners' capital / unitholders' equity $ 203,848,774 $ 198,879,415 $ 247,441,471 $ 294,965,598 Noncontrolling interest $ — $ — $ 209,450,877 $ 297,761,199 Predecessor Partnership First Quarter First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Total revenue $ 318,310 $ 4,553,344 $ 7,751,998 $ 8,351,399 $ 9,689,522 Net (loss) income $ (496,856) $ 283,218 $ 251,651 $ 119,029 $ 1,061,842 Net (loss) income attributable to common units Basic $ (0.82) $ 0.02 $ 0.02 $ 0.01 $ 0.06 Diluted $ (0.82) $ 0.02 $ 0.02 $ 0.01 $ 0.06 Cash distributions declared and paid $ * $ 0.23 $ 0.30 $ 0.31 $ 0.36 Total assets $ * $ 279,419,440 $ 289,918,996 $ 290,406,599 $ 295,291,004 Long-term debt $ * $ 3,877,500 $ 18,265,090 $ 22,214,090 $ 30,843,593 Partners' capital $ * $ 273,657,870 $ 270,288,690 $ 265,893,106 $ 262,065,434 * Information is not applicable for the periods prior to the initial public offering. |
SUMMARY OF SIGNIFICANT ACCOUN_2
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2018 | |
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 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, 2018, and 2017, 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. Costs associated with unevaluated properties are excluded from the full-cost pool until a determination as to the existence of proved reserves is able to be made. The inclusion of the Partnership’s unevaluated costs into the amortization base is expected to be completed within five years. 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 remained effective through all financial reporting periods through December 31, 2017. A component of the exemption received from the SEC is that the Partnership was required to assess the fair value of the acquired assets at each reporting period through the term of the exemption to ensure that the inclusion of the acquired assets in the full-cost ceiling test would not be appropriate. The Partnership recorded an impairment expense on its oil and natural gas properties of $67.3 million during the year ended December 31, 2018. Of this amount, an impairment expense of $54.8 million was recorded as a result of the Partnership’s quarterly full-cost ceiling analysis for the three months ended March 31, 2018 following the expiration of the aforementioned exemption and an impairment expense booking proved of $12.6 million was recorded for the three months ended December 31, 2018 as a result of the Dropdown (as defined in Note 3—Acquisitions and Divestitures) purchase price exceeding the value of the proved developed reserves added to the full-cost ceiling. As the Partnership does not intend to book proved undeveloped reserves going forward, additional impairment charges could be recorded in connection with future acquisitions. Additional impairments may be required to be recorded due to the Partnership’s decision to voluntarily and ratably eliminate, over time, our existing PUD reserves. Further, if the price of oil, natural gas and NGLs decreases in future periods, the Partnership may be required to record additional impairments as a result of the full-cost ceiling limitation. 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 year ended December 31, 2016, the Predecessor recorded non-cash impairment charges of approximately $5.0 million, primarily due to changes in reserve values resulting from the reduction 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 year ended December 31, 2018, the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the year ended December 31, 2016. 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 year ended December 31, 2018, the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, or the year ended December 31, 2016. |
Other Current Liabilities | Other Current Liabilities Other current liabilities consist primarily of Series A Preferred Unit and Class B Unit distributions, accrued interest, revenue payable, accrued tax liability and ad valorem taxes. |
Income Taxes | Income Taxes As discussed further in Note 1—Organization and Basis of Presentation, on May 28, 2018, the Partnership announced that the Board of Directors had unanimously approved a change of the Partnership’s federal income tax status from that of a pass-through partnership to that of a taxable entity, which became effective on September 24, 2018. 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 Predecessor incurred de minimis amounts of state income taxes during the year ended December 31, 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, 2018 and 2017. The Partnership and Predecessor recognize interest and penalties related to uncertain tax positions in income tax expense. For the year ended December 31, 2018, the period from February 8, 2017 to December 31, 2017, the Predecessor 2017 Period, and the year 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. For the Predecessor, 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 year ended December 31, 2018, the Partnership’s top purchaser accounted for approximately 10% of oil, natural gas and NGL sales revenue. 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 from Contracts with Customers | Revenue from Contracts with Customers Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the operator. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index. Royalty income from oil, natural gas and natural gas liquids sales The Partnership’s oil, natural gas and natural gas liquids sales contracts are generally structured whereby the producer of the properties in which the Partnership owns a royalty interest sells the Partnership’s proportionate share of oil, natural gas and natural gas liquids production to the purchaser and the Partnership collects its percentage royalty based on the revenue generated by the sale of the oil, natural gas and natural gas liquids. In this scenario, the Partnership recognizes revenue when control transfers to the operator at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Transaction price allocated to remaining performance obligations The Partnership’s right to royalty income does not originate until production occurs and, therefore, is not considered to exist beyond each day’s production. Therefore, there are no remaining performance obligation under any of the Partnership’s royalty income contracts. Contract balances Under the Partnership’s royalty income contracts, it would have the right to receive royalty income from the producer once production has occurred, at which point payment is unconditional. Accordingly, the Partnership’s royalty income contracts do not give rise to contract assets or liabilities. Prior-period performance obligations The Partnership records revenue in the month production is delivered to the purchaser. However, settlement statements for certain natural gas and natural gas liquids sales may not be received for one to four months after the date production is delivered, and as a result, the Partnership is required to estimate the amount of royalty income to be received based upon the Partnership’s interest. The Partnership records the differences between its estimates and the actual amounts received for royalties in the month that payment is received from the producer. Identified differences between the Partnership’s revenue estimates and actual revenue received historically have not been significant. For the year ended December 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. The Partnership believes that the pricing provisions of its oil, natural gas and natural gas liquids contracts are customary in the industry. To the extent actual volumes and prices of oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the royalties related to expected sales volumes and prices for those properties are estimated and recorded. |
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—Fair Value Measurements for further discussion of the Partnership’s fair value measurements. |
New Accounting Pronouncements | New Accounting Pronouncements Recently Adopted Pronouncements In May 2014 the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers (Topic 606),” an ASU on a comprehensive new revenue recognition standard that supersedes Accounting Standards Codification (“ASC”) 605, “Revenue Recognition.” The new accounting guidance creates a framework under which an entity allocates the transaction price to separate performance obligations and recognize revenue when each performance obligation is satisfied. Under the new standard, entities are 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. On January 1, 2018 the Partnership adopted ASU 2014 - 09 using the full retrospective method. The Partnership completed its review of a representative sample of revenue contracts covering its material revenue streams and determined that there is no impact to its consolidated financial statements, results of operations or liquidity. When comparing the Partnership’s historical revenue recognition to the newly applied revenue recognition under ASC 606 , there was no change to the amount or timing of revenue recognized. Therefore, no quantitative adjustment was required to be made to the prior periods presented in the unaudited interim condensed consolidated financial statements after the adoption of ASC 606 . Upon adoption, the Partnership did not alter its existing information technology and internal controls outside of the contract review processes in order to identify impacts of future revenue contracts the Partnership may enter into. In January 2017, the FASB issued 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. The Partnership adopted this update prospectively effective January 1, 2018. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations. In June 2018, the FASB issued ASU 2018-07, “Improvements to Nonemployee Share-Based Payment Accounting.” ASU 2018-07 simplifies the accounting for share-based payments to nonemployees by aligning it with the accounting for share-based payments to employees, with certain exceptions. The amendments in this ASU are effective for public companies for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year, with early adoption permitted. The Partnership early adopted ASU 2018-07 effective January 1, 2018. This standard substantially aligned the accounting for share based payments to employees and nonemployees. The adoption of this update did not have a material impact on the Partnership’s financial statements or results of operations. Accounting Pronouncements Not Yet Adopted In July 2018, the FASB issued 2018-09, “Codification Improvements.” This update provides clarification and corrects unintended application of the guidance in various sections. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership is currently evaluating the impact of the adoption of this update but does not believe it will have a material impact on its financial position, results of operations or liquidity. The Partnership is still evaluating the impact of this standard. In July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842, Leases.” This update provides clarification and corrects unintended application of certain sections in the new lease guidance. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity. In July 2018, the FASB issued ASU 2018-11, “Lease (Topic 842): Targeted Improvements.” This update provides another transition method of allowing entities to initially apply the new lease standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Partnership believes the adoption of this update will not have an impact on its financial position, results of operations or liquidity. 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 adoption of this update will have a $3.4 million to $4.2 million impact on its financial position, results of operations or liquidity. |
ACQUISITIONS AND DIVESTITURES (
ACQUISITIONS AND DIVESTITURES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Haymaker | |
Schedule of pro forma results | Year Ended December 31, Year Ended December 31, 2018 2017 Total revenues $ 70,258,210 $ 80,292,349 Net (loss) income attributable to common units $ (56,767,549) $ 922,095 Net (loss) income attributable to common units Basic $ (3.08) $ 0.04 Diluted $ (3.08) $ 0.03 |
DERIVATIVES (Tables)
DERIVATIVES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
DERIVATIVES | |
Schedule of changes in fair value of derivative instruments | Year Ended December 31, Period from 2018 2017 Beginning fair value of commodity derivative instruments $ (318,829) $ — Gain (loss) on commodity derivative instruments 3,331,548 (318,829) Net cash paid on settlements of derivative instruments 1,215,227 — Ending fair value of commodity derivative instruments $ 4,227,946 $ (318,829) |
Schedule of derivative contracts | December 31, December 31, Classification Balance Sheet Location 2018 2017 Assets: Current asset Commodity derivative assets $ 2,981,117 $ — Long-term asset Commodity derivative assets 1,246,829 — Liabilities: Current liability Commodity derivative liabilities — (183,957) Long-term liability Commodity derivative liabilities — (134,872) $ 4,227,946 $ (318,829) |
Schedule of commodity derivative contracts | At December 31, 2018, the Partnership’s open commodity derivative contracts consisted of the following: Oil Price Swaps Notional Weighted Average Range (per Bbl) Volumes (Bbl) Fixed Price (per Bbl) Low High December 2018 19,034 $ 64.28 $ 56.00 $ 66.25 January 2019 - December 2019 224,110 $ 61.47 $ 53.07 $ 63.47 January 2020 - December 2020 224,356 $ 55.48 $ 50.45 $ 61.43 Natural Gas Price Swaps Notional Weighted Average Range (per MMBtu) Volumes (MMBtu) Fixed Price (per MMBtu) Low High January 2019 - December 2019 3,859,145 $ 2.74 $ 2.74 $ 2.76 January 2020 - December 2020 3,582,862 $ 2.64 $ 2.51 $ 2.94 |
OIL AND NATURAL GAS PROPERTIES
OIL AND NATURAL GAS PROPERTIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
OIL AND NATURAL GAS PROPERTIES | |
Schedule of oil and natural gas properties | December 31, December 31, 2018 2017 Oil and natural gas properties Proved properties $ 538,290,590 $ 297,609,797 Unevaluated properties 280,304,353 — Less: accumulated depreciation, depletion and impairment (107,779,453) (15,394,238) Total oil and natural gas properties $ 710,815,490 $ 282,215,559 |
PREFERRED UNITS (Tables)
PREFERRED UNITS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Series A Preferred Units | |
Class of Stock [Line Items] | |
Summary of the changes in the number of the Series A Preferred Units | Series A Preferred Units Balance at December 31, 2017 — Series A Preferred Units issued 110,000 Balance at December 31, 2018 110,000 |
UNITHOLDERS' EQUITY AND PARTN_2
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Common units | |
Schedule of distributions approved by the Board of Directors | Amount per Date Unitholder Payment Common Unit Declared Record Date Date Q1 2018 $ 0.42 April 27, 2018 May 7, 2018 May 14, 2018 Q2 2018 $ 0.43 July 27, 2018 August 6, 2018 August 13, 2018 Q3 2018 $ 0.45 October 26, 2018 November 5, 2018 November 12, 2018 Q4 2018 $ 0.40 January 25, 2019 February 4, 2019 February 11, 2019 Q1 2017 (1) $ 0.23 May 2, 2017 May 8, 2017 May 15, 2017 Q2 2017 $ 0.30 July 28, 2017 August 7, 2017 August 14, 2017 Q3 2017 $ 0.31 October 27, 2017 November 6, 2017 November 13, 2017 Q4 2017 $ 0.36 January 26, 2018 February 7, 2018 February 14, 2018 (1) 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. |
Common Units | |
Common units | |
Schedule of changes in Partnership's units | Common Units Balance at December 31, 2017 16,509,799 Common units issued under the LTIP (1) 1,049,946 Common units issued for acquisition 10,000,000 Common units issued for equity offering (2) 3,450,000 Unit exchange related to tax conversion (12,953,258) Balance at December 31, 2018 18,056,487 (1) Includes 720,283 and 326,654 restricted units granted to certain employees, directors and consultants under the Kimbell Royalty GP, LLC 2017 Long-Term Incentive Plan (as amended, the “LTIP”) on December 7, 2018 and January 29, 2018, respectively, 4,478 of restricted units granted to a new director under the LTIP on May 9, 2018, and the forfeiture of 1,469 units. (2) On October 1, 2018, the Partnership completed an underwritten public offering of 3,450,000 common units, including an additional 450,000 common units in connection with the exercise of the underwriters’ option to purchase additional common units, for net proceeds of approximately $61.8 million. The Partnership used the net proceeds to purchase OpCo Common Units. The Operating Company in turn used the net proceeds to repay a portion of the outstanding borrowings under the Partnership’s secured revolving credit facility. |
Class B | |
Common units | |
Schedule of changes in Partnership's units | Class B Units Balance at December 31, 2017 — Unit exchange related to Tax Election 12,953,258 Class B Units issued for Dropdown (1) 6,500,000 Balance at December 31, 2018 19,453,258 (1) See Note 3—Acquisition and Divestitures for discussion regarding the Dropdown. |
EARNINGS (LOSS) PER UNIT (Table
EARNINGS (LOSS) PER UNIT (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
EARNINGS (LOSS) PER UNIT | |
Schedule of earnings (loss) per unit | Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Net (loss) income attributable to common units $ (56,767,549) $ 1,715,740 $ (496,856) $ (6,212,619) Weighted average number of common units outstanding: Basic 18,442,234 16,336,871 604,137 604,137 Effect of dilutive securities: Restricted stock units — 118,731 — — Class B units — — — — Diluted 18,442,234 16,455,602 604,137 604,137 Net (loss) income attributable to common units Basic $ (3.08) $ 0.11 $ (0.82) $ (10.28) Diluted $ (3.08) $ 0.10 $ (0.82) $ (10.28) |
UNIT-BASED COMPENSATION (Tables
UNIT-BASED COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
UNIT-BASED COMPENSATION | |
Schedule of unvested restricted stock activity | Weighted Weighted Average Average Grant-Date Remaining Fair Value Contractual Units per Unit Term Unvested at December 31, 2017 167,571 $ 18.655 1.364 years Granted - service condition employees 622,212 17.894 — Granted - service condition consultants 31,238 17.588 — Granted - non-employee directors 397,965 18.183 — Forfeited (1,469) (17.610) — Vested (59,593) (18.695) — Unvested at December 31, 2018 1,157,924 $ 18.054 2.696 years |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
INCOME TAXES | |
Schedule of income tax expense | Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Current Federal $ — $ — $ — $ — State 24,681 — — 19,848 Total Current 24,681 — — 19,848 Deferred Federal — — — — State — — — — Total Deferred — — — — Provision for income taxes $ 24,681 $ — $ — $ 19,848 |
Schedule of effective income expense | Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Net (loss) income before taxes $ (52,257,542) $ 1,715,740 $ (496,856) $ (6,192,771) Statutory rate 21 % 35 % 35 % 35 % Income tax expense computed at statutory rate (10,974,084) 600,509 (173,900) (2,167,470) Reconciling items: State income taxes (70,441) — — — Texas margin tax 24,681 — — 19,848 Change in tax status (20,038,820) — — — Noncontrolling interest (360,082) — — — Income (loss) not subject to corporate tax 10,598,375 (600,509) 173,900 2,167,470 Change in valuation allowance - federal 20,771,214 — — — Change in valuation allowance - state 70,441 — — — Other, net 3,397 — — — Provision for income taxes $ 24,681 $ — $ — $ 19,848 |
Schedule of components of deferred tax assets and liabilities | Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Deferred tax asset Outside basis in OpCo $ 21,036,307 $ — $ — $ — Federal tax loss carryforwards 622,775 — — — State tax loss carryforwards 70,441 — — — Deferred tax asset 21,729,523 — — — Valuation allowance (20,841,655) — — — Net deferred tax asset $ 887,868 $ — $ — $ — Deferred tax liability Derivative instruments and other 887,868 — — — Net deferred tax liability $ 887,868 $ — $ — $ — Reflected in the accompanying balance sheet as: Net deferred tax asset $ — $ — $ — $ — Net deferred tax liability $ — $ — $ — $ — |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
COMMITMENTS AND CONTINGENCIES. | |
Schedule of operating lease commitments | f Years Ending December 31, 2019 $ 369,079 2020 522,904 2021 488,253 2022 488,253 2023 492,236 Thereafter 2,761,280 Total $ 5,122,005 |
SUPPLEMENTAL OIL AND GAS RESE_2
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) | |
Schedule of oil and natural gas aggregate capitalized costs and applicable accumulated depreciation, depletion and amortization | December 31, December 31, 2018 2017 Oil, natural gas and NGL interests Proved properties $ 538,290,590 $ 297,609,797 Unevaluated properties 280,304,353 — Total oil, natural gas and NGL interests 818,594,943 297,609,797 Accumulated depreciation, depletion, accretion and impairment (107,779,453) (15,394,238) Net oil, natural gas and NGL interests capitalized $ 710,815,490 $ 282,215,559 |
Schedule of costs incurred in oil and natural gas activities | Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2018 2016 Acquisition costs Proved properties $ 243,227,632 $ 297,609,797 $ — $ — Unevaluated properties 288,334,110 — — — Total 531,561,742 297,609,797 — — Development costs Proved properties — — — 78,159 Total — — — 78,159 Total costs incurred on oil, natural gas and NGL activities $ 531,561,742 $ 297,609,797 $ — $ 78,159 |
Results of operations from oil, natural gas and natural gas liquids | Partnership Predecessor Year Ended December 31, Period from Period from Year Ended December 31, 2018 2017 2017 2016 Oil, natural gas and NGL revenues $ 65,713,112 $ 29,943,920 $ 318,310 $ 3,606,659 Lease bonus and other income 1,213,550 721,172 — — Production and ad valorem taxes (4,399,667) (2,452,058) (19,651) (280,474) Depreciation, depletion and accretion expense (25,213,043) (15,394,238) (113,639) (1,604,208) Impairment of oil and natural gas properties (67,311,501) — — (4,992,897) Marketing and other deductions (4,652,313) (1,648,895) (110,534) (750,792) Results of operations from oil, natural gas and NGLs $ (34,649,862) $ 11,169,901 $ 74,486 $ (4,021,712) |
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 Revisions of previous estimates (1) 194 1,754 952 1,437 Purchase of minerals in place (6) 3,729 69,465 2,166 17,473 Production (591) (7,874) (310) (2,213) Net proved reserves at December 31, 2018 10,795 127,261 5,646 37,651 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 December 31, 2018 9,183 116,321 5,063 33,633 Net Proved Undeveloped Reserves December 31, 2016 2,331 15,218 566 5,433 December 31, 2017 2,179 16,415 636 5,551 December 31, 2018 1,612 10,940 583 4,018 (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 the Partnership’s 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 the Partnership’s acreage primarily in the Permian Basin, Eagle Ford Shale. (6) Includes the acquisition of two packages of diverse mineral and royalty interests for a total of $243.2 million. The first acquisition totaling $155.7 million consists of mineral and royalty interests primarily in the Permian Basin, Haynesville Shale, Mid-Continent Area and Appalachia Region. The second acquisition totaling $87.5 million consists of mineral and royalty interests primarily in the Permian Basin, Eagle Ford Shale and Appalachia Region. |
Schedule of standardized measure related to proved oil, natural gas and natural gas liquids reserves | Year Ended December 31, 2018 2017 2016 Future cash inflows $ 1,056,464 $ 562,967 $ 414,004 Future production costs (79,724) (45,652) (32,034) Future state margin taxes (32,885) (2,790) (2,051) Future income tax expense (41,241) — — Future net cash flows 902,614 514,525 379,919 Less 10% annual discount to reflect timing of cash flows (504,247) (298,973) (220,643) Standard measure of discounted future net cash flows $ 398,367 $ 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, 2018 2017 2016 Standardized measure - beginning of year $ 215,552 $ 159,275 $ 180,083 Sales, net of production costs (56,661) (29,288) (24,280) Net changes of prices and production costs related to future production 11,355 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 16,385 2,248 2,974 Net changes in state margin taxes (13,271) 301 (112) Net changes in income taxes (17,232) — — Accretion of discount 21,555 15,928 18,008 Purchases of reserves in place 175,885 23,309 1,097 Timing differences and other 44,799 11,769 (6,426) Standardized measure - end of year $ 398,367 $ 215,552 $ 159,276 |
SELECTED QUARTERLY FINANCIAL _2
SELECTED QUARTERLY FINANCIAL INFORMATION - Unaudited (Tables) | 12 Months Ended |
Dec. 31, 2018 | |
Selected Quarterly Financial information - Unaudited | |
Schedule of quarterly financial data | Quarterly financial data was as follows for the periods indicated. Partnership First Quarter Second Quarter Third Quarter Fourth Quarter 2018 Total revenue $ 10,891,338 $ 10,707,898 $ 18,407,956 $ 30,251,018 Net (loss) income attributable to common units $ (52,824,471) $ 1,378,295 $ (3,711,798) $ (1,609,575) Net (loss) income attributable to common units Basic $ (3.23) $ 0.08 $ (0.15) $ (0.10) Diluted $ (3.23) $ 0.08 $ (0.15) $ (0.10) Cash distributions declared and paid $ 0.42 $ 0.43 $ 0.45 $ 0.40 Total assets $ 237,201,565 $ 249,318,570 $ 683,893,161 $ 753,285,373 Long-term debt $ 30,843,593 $ 42,972,997 $ 148,309,544 $ 87,309,544 Mezzanine equity $ — $ — $ 67,904,422 $ 69,449,006 Partners' capital / unitholders' equity $ 203,848,774 $ 198,879,415 $ 247,441,471 $ 294,965,598 Noncontrolling interest $ — $ — $ 209,450,877 $ 297,761,199 Predecessor Partnership First Quarter First Quarter Second Quarter Third Quarter Fourth Quarter 2017 Total revenue $ 318,310 $ 4,553,344 $ 7,751,998 $ 8,351,399 $ 9,689,522 Net (loss) income $ (496,856) $ 283,218 $ 251,651 $ 119,029 $ 1,061,842 Net (loss) income attributable to common units Basic $ (0.82) $ 0.02 $ 0.02 $ 0.01 $ 0.06 Diluted $ (0.82) $ 0.02 $ 0.02 $ 0.01 $ 0.06 Cash distributions declared and paid $ * $ 0.23 $ 0.30 $ 0.31 $ 0.36 Total assets $ * $ 279,419,440 $ 289,918,996 $ 290,406,599 $ 295,291,004 Long-term debt $ * $ 3,877,500 $ 18,265,090 $ 22,214,090 $ 30,843,593 Partners' capital $ * $ 273,657,870 $ 270,288,690 $ 265,893,106 $ 262,065,434 * Information is not applicable for the periods prior to the initial public offering. |
ORGANIZATION AND BASIS OF PRE_2
ORGANIZATION AND BASIS OF PRESENTATION (Details) | Jul. 24, 2018$ / sharesshares | Dec. 31, 2018segment | Dec. 31, 2016 |
Organization | |||
Percentage of future undiscounted cash flows from predecessor | 11.00% | ||
Segment Reporting | |||
Number of operating units | segment | 1 | ||
Number of reporting units | segment | 1 | ||
Haymaker Holdings | Common Units | Kimbell Royalty Operating, LLC | |||
Organization | |||
Number of units held by investor that were exchanged (in units) | 10,000,000 | ||
Haymaker Holdings | Class B Common Units | |||
Organization | |||
Distribution rate (as a percent) | 2.00% | ||
Additional consideration paid per unit (in dollars per unit) | $ / shares | $ 5 | ||
Haymaker Holdings | Class B Common Units | Kimbell Royalty Operating, LLC | |||
Organization | |||
Units issued (in units) | 10,000,000 | ||
Haymaker Holdings | OpCo Units | Kimbell Royalty Operating, LLC | |||
Organization | |||
Units issued (in units) | 10,000,000 | ||
Haymaker Foundation | Common Units | Kimbell Royalty Operating, LLC | |||
Organization | |||
Number of units held by investor that were exchanged (in units) | 2,953,258 | ||
Haymaker Foundation | Class B Common Units | |||
Organization | |||
Distribution rate (as a percent) | 2.00% | ||
Additional consideration paid per unit (in dollars per unit) | $ / shares | $ 0.05 | ||
Haymaker Foundation | Class B Common Units | Kimbell Royalty Operating, LLC | |||
Organization | |||
Units issued (in units) | 2,953,258 | ||
Haymaker Foundation | OpCo Units | Kimbell Royalty Operating, LLC | |||
Organization | |||
Units issued (in units) | 2,953,258 | ||
Kimbell Royalty Operating, LLC | Series A Preferred Units | |||
Organization | |||
Units owned in subsidiary (in units) | 110,000 | ||
Kimbell Royalty Operating, LLC | Common Units | |||
Organization | |||
Units owned in subsidiary (in units) | 13,886,204 |
SUMMARY OF SIGNIFICANT ACCOUN_3
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES -Other Disclosures (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 |
Accounts Receivable | ||
Allowance for doubtful accounts receivable | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_4
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Property and Equipment (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Minimum | |
Oil and natural gas properties | |
Useful life | 3 years |
Maximum | |
Oil and natural gas properties | |
Useful life | 7 years |
SUMMARY OF SIGNIFICANT ACCOUN_5
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Natural Gas Properties (Details) - USD ($) | Feb. 07, 2017 | Mar. 31, 2017 | Feb. 28, 2017 | Feb. 07, 2017 | Dec. 31, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2016 |
Oil and Natural Gas Properties | ||||||||||
Period for completion of unevaluated costs into the amortization base | 5 years | |||||||||
Impairment of oil and natural gas properties | $ 12,600,000 | $ 54,800,000 | $ 0 | $ 67,311,501 | ||||||
Gain (loss) recorded on disposition of oil, natural gas and natural gas liquid properties | $ 0 | $ 0 | $ 0 | 0 | ||||||
Number of exploratory activities pending determination | 0 | 0 | 0 | 0 | ||||||
Exploratory costs charged | $ 0 | $ 0 | $ 0 | $ 0 | ||||||
Predecessor | ||||||||||
Oil and Natural Gas Properties | ||||||||||
Impairment of oil and natural gas properties | $ 0 | $ 4,992,897 | ||||||||
Gain (loss) recorded on disposition of oil, natural gas and natural gas liquid properties | $ 0 | 0 | ||||||||
Number of exploratory activities pending determination | 0 | 0 | ||||||||
Exploratory costs charged | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_6
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Income Taxes (Details) - USD ($) | Feb. 07, 2017 | Mar. 31, 2017 | Feb. 28, 2017 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2016 | Dec. 31, 2015 |
Income Taxes | |||||||
Texas franchise tax (as a percent) | 0.75% | ||||||
Uncertain tax positions | $ 0 | $ 0 | |||||
Interest and penalties | $ 0 | $ 0 | $ 0 | $ 0 | |||
Predecessor | |||||||
Income Taxes | |||||||
Interest and penalties | $ 0 | $ 0 | $ 0 |
SUMMARY OF SIGNIFICANT ACCOUN_7
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentration of Credit Risk (Details) - Sales - Customer - item | 11 Months Ended | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2016 | |
Concentration of Credit Risk | |||
Number of significant purchasers | 1 | 1 | |
Purchaser 1 | |||
Concentration of Credit Risk | |||
Purchaser percentage | 14.00% | 10.00% | |
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% |
SUMMARY OF SIGNIFICANT ACCOUN_8
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue from Contracts with Customers (Details) | 12 Months Ended |
Dec. 31, 2018 | |
Minimum | |
Settlement period for certain natural gas and natural gas liquids sales | 1 month |
Maximum | |
Settlement period for certain natural gas and natural gas liquids sales | 4 months |
SUMMARY OF SIGNIFICANT ACCOUN_9
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - New Accounting Pronouncements (Details) - Accounting Standards Update 2016-02 - Forecast Adjustment $ in Millions | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Minimum | |
New Accounting Pronouncements | |
Impact on financial position, results of operations or liquidity | $ 3.4 |
Maximum | |
New Accounting Pronouncements | |
Impact on financial position, results of operations or liquidity | $ 4.2 |
ACQUISITIONS AND DIVESTITURES -
ACQUISITIONS AND DIVESTITURES - Divestitures (Details) | 1 Months Ended |
May 31, 2018USD ($)aitem | |
ACQUISITIONS AND DIVESTITURES | |
Number of purchase and sale agreements executed | item | 2 |
The sale price of asset | $ | $ 10,600,000 |
Gain loss on sale | $ | $ 0 |
Number of Boe per day sold | item | 29 |
Boe per day sold to total Boe per day (as a percent) | 0.80% |
Net royalty acres land sold (in acres) | a | 59 |
Net royalty acres land sold to total net royalty acres land (as a percent) | 0.08% |
ACQUISITIONS AND DIVESTITURES_2
ACQUISITIONS AND DIVESTITURES - Acquisitions (Details) $ / shares in Units, $ in Millions | Dec. 20, 2018ashares | Jul. 12, 2018USD ($)a$ / sharesshares | Dec. 13, 2017USD ($) | Nov. 08, 2017USD ($)a | Oct. 09, 2017USD ($)a | Jun. 30, 2017USD ($)a |
Haymaker | ||||||
Acquisitions | ||||||
Purchase price cash, gross | $ 216.8 | |||||
Cash acquired from acquisition | 6.4 | |||||
Net cash received or receivable from revenue prior to closing date | 9.3 | |||||
Acquisition related costs | 7.5 | |||||
Cash paid to acquire businesses, net of cash acquired and transaction costs | $ 208.6 | |||||
Purchase price units (in units) | shares | 10,000,000 | |||||
Purchase price units value | $ 235.4 | |||||
Share price (in dollars per unit) | $ / shares | $ 23.54 | |||||
Gross acres acquired (in acres) | a | 5,400,000 | |||||
Net royalty acres acquired (in acres) | a | 43,000 | |||||
The Dropdown | ||||||
Acquisitions | ||||||
Gross acres acquired (in acres) | a | 1,000,000 | |||||
Net royalty acres acquired (in acres) | a | 16,700 | |||||
The Dropdown | OpCo Units | ||||||
Acquisitions | ||||||
Purchase price units (in units) | shares | 6,500,000 | |||||
The Dropdown | Class B Common Units | ||||||
Acquisitions | ||||||
Purchase price units (in units) | shares | 6,500,000 | |||||
Mineral And Royalty Interests | ||||||
Acquisitions | ||||||
Transaction value of acquisition | $ 1.3 | $ 7.3 | $ 3.9 | $ 16.8 | ||
Gross acres acquired (in acres) | a | 71,410 | 8,460 | 1,100,000 | |||
Net royalty acres acquired (in acres) | a | 2,757 | 983 | 6,881 |
ACQUISITIONS AND DIVESTITURES_3
ACQUISITIONS AND DIVESTITURES - Pro forma (Details) - Haymaker - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Pro forma results | ||
Total revenue | $ 70,258,210 | $ 80,292,349 |
Net (loss) income attributable to common units | $ (56,767,549) | $ 922,095 |
Net (loss) income attributable to common units - basic (in dollar per unit) | $ (3.08) | $ 0.04 |
Net (loss) income attributable to common units - Diluted (in dollar per unit) | $ (3.08) | $ 0.03 |
DERIVATIVES (Details)
DERIVATIVES (Details) | 11 Months Ended | 12 Months Ended | |||
Dec. 31, 2017USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2018USD ($)$ / bblMMBbls | Jul. 11, 2018 | Dec. 31, 2017USD ($) | |
Derivatives | |||||
Daily oil and natural gas production (as a percent) | 24.00% | ||||
Change in fair values of derivative instruments | |||||
Beginning fair value of commodity derivative instruments | $ | $ (318,829) | ||||
Gain (loss) on commodity derivative instruments | $ | $ (318,829) | 3,331,548 | |||
Net cash paid on settlements of derivative instruments | $ | 1,215,227 | ||||
Ending fair value of commodity derivative instruments | $ | (318,829) | 4,227,946 | |||
Assets: | |||||
Current asset | $ | $ 2,981,117 | ||||
Long-term asset | $ | 1,246,829 | ||||
Liabilities: | |||||
Current liability | $ | $ (183,957) | ||||
Long-term liability | $ | (134,872) | ||||
Derivative assets (liabilities) | $ | $ (318,829) | $ (318,829) | $ 4,227,946 | $ (318,829) | |
Oil Price Swaps - December 2018 | |||||
Derivatives | |||||
Notional Volumes | MMBbls | 19,034 | ||||
Weighted Average Fixed Price | 64.28 | ||||
Oil Price Swaps - January 2019 - December 2019 | |||||
Derivatives | |||||
Notional Volumes | MMBbls | 224,110 | ||||
Weighted Average Fixed Price | 61.47 | ||||
Oil Price Swaps - January 2020 - June 2020 | |||||
Derivatives | |||||
Notional Volumes | MMBbls | 224,356 | ||||
Weighted Average Fixed Price | 55.48 | ||||
Natural Gas Price Swaps - January 2019 - December 2019 | |||||
Derivatives | |||||
Notional Volumes | MMBbls | 3,859,145 | ||||
Weighted Average Fixed Price | 2.74 | ||||
Natural Gas Price Swaps - January 2020 - June 2020 | |||||
Derivatives | |||||
Notional Volumes | MMBbls | 3,582,862 | ||||
Weighted Average Fixed Price | 2.64 | ||||
Minimum | Oil Price Swaps - December 2018 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 56 | ||||
Minimum | Oil Price Swaps - January 2019 - December 2019 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 53.07 | ||||
Minimum | Oil Price Swaps - January 2020 - June 2020 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 50.45 | ||||
Minimum | Natural Gas Price Swaps - January 2019 - December 2019 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 2.74 | ||||
Minimum | Natural Gas Price Swaps - January 2020 - June 2020 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 2.51 | ||||
Maximum | Oil Price Swaps - December 2018 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 66.25 | ||||
Maximum | Oil Price Swaps - January 2019 - December 2019 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 63.47 | ||||
Maximum | Oil Price Swaps - January 2020 - June 2020 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 61.43 | ||||
Maximum | Natural Gas Price Swaps - January 2019 - December 2019 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 2.76 | ||||
Maximum | Natural Gas Price Swaps - January 2020 - June 2020 | |||||
Derivatives | |||||
Weighted Average Fixed Price | 2.94 |
OIL AND NATURAL GAS PROPERTIE_2
OIL AND NATURAL GAS PROPERTIES (Details) - USD ($) | 1 Months Ended | 3 Months Ended | 11 Months Ended | 12 Months Ended | ||
Feb. 07, 2017 | Dec. 31, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2016 | |
Oil and natural gas properties | ||||||
Proved properties | $ 538,290,590 | $ 297,609,797 | $ 538,290,590 | |||
Unevaluated properties | 280,304,353 | 0 | 280,304,353 | |||
Less: accumulated depreciation, depletion, and impairment | (107,779,453) | (15,394,238) | (107,779,453) | |||
Total oil and natural gas properties | 710,815,490 | 282,215,559 | $ 710,815,490 | |||
Useful life | 5 years | |||||
Impairment of oil and natural gas properties | $ 12,600,000 | $ 54,800,000 | $ 0 | $ 67,311,501 | ||
Predecessor | ||||||
Oil and natural gas properties | ||||||
Impairment of oil and natural gas properties | $ 0 | $ 4,992,897 |
LONG-TERM DEBT (Details)
LONG-TERM DEBT (Details) - USD ($) | Jul. 12, 2018 | Dec. 31, 2017 | Dec. 31, 2018 | Nov. 01, 2018 | Jul. 11, 2018 | Feb. 08, 2017 | Jan. 11, 2017 |
Long-term debt | |||||||
Borrowings of debt | $ 30,843,593 | $ 124,336,547 | |||||
Repayment of debt | 67,870,596 | ||||||
Revolving credit facility | |||||||
Long-term debt | |||||||
Revolving credit facility maximum borrowings | $ 200,000,000 | $ 50,000,000 | $ 50,000,000 | ||||
Revolving credit facility increased maximum borrowing capacity if certain conditions are met | 500,000,000 | $ 100,000,000 | |||||
Revolving credit facility outstanding | $ 87,300,000 | ||||||
Interest rate on outstanding borrowings (as a percent) | 4.61% | ||||||
Initial borrowing base | $ 200,000,000 | $ 200,000,000 | |||||
Amount of applicable margin decrease for each applicable level (as a percent) | 0.25% | ||||||
Borrowings of debt | $ 124,400,000 | ||||||
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 | Maximum | LIBOR | |||||||
Long-term debt | |||||||
Margin (as a percent) | 3.00% | ||||||
Revolving credit facility | Maximum | Prime | |||||||
Long-term debt | |||||||
Margin (as a percent) | 2.00% | ||||||
Revolving credit facility | Minimum | |||||||
Long-term debt | |||||||
Debt to EBITDAX ratio | 100.00% | ||||||
Revolving credit facility | Minimum | LIBOR | |||||||
Long-term debt | |||||||
Margin (as a percent) | 2.00% | ||||||
Revolving credit facility | Minimum | Prime | |||||||
Long-term debt | |||||||
Margin (as a percent) | 1.00% |
PREFERRED UNITS (Details)
PREFERRED UNITS (Details) - Series A Preferred Units - USD ($) $ / shares in Units, $ in Millions | 1 Months Ended | 12 Months Ended |
Jul. 31, 2018 | Dec. 31, 2018 | |
Preferred units | ||
Series A preferred units issued | 110,000 | |
Affiliates of Apollo Capital Management, L.P. | ||
Preferred units | ||
Series A preferred units issued | 110,000 | |
Share price (in dollars per unit) | $ 1,000 | |
Proceeds from the issuance of preferred units | $ 110 | |
Distribution rate (as a percent) | 7.00% |
PREFERRED UNITS - Rollforward (
PREFERRED UNITS - Rollforward (Details) - Series A Preferred Units | 12 Months Ended |
Dec. 31, 2018shares | |
Preferred units | |
Series A preferred units issued | 110,000 |
Balance at end of period | 110,000 |
UNITHOLDERS' EQUITY AND PARTN_3
UNITHOLDERS' EQUITY AND PARTNERSHIP DISTRIBUTIONS (Details) - USD ($) | Dec. 07, 2018 | Oct. 01, 2018 | May 09, 2018 | Jan. 29, 2018 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2016 | Dec. 31, 2018 | Dec. 31, 2017 |
Common units | ||||||||||||||||
Units issued (in units) | 18,056,487 | 16,509,799 | ||||||||||||||
Units outstanding (in units) | 18,056,487 | 16,509,799 | 16,509,799 | 16,509,799 | 18,056,487 | 16,509,799 | ||||||||||
Capital rollforward | ||||||||||||||||
Unitholders' capital, beginning balance (in units) | 16,509,799 | 16,509,799 | ||||||||||||||
Unitholders' capital, ending balance (in units) | 18,056,487 | 16,509,799 | 18,056,487 | |||||||||||||
Proceeds from equity offering | $ 61,800,000 | |||||||||||||||
Cash distributions declared and paid (in dollars per unit) | $ 0.40 | $ 0.45 | $ 0.43 | $ 0.42 | $ 0.36 | $ 0.31 | $ 0.30 | $ 0.23 | ||||||||
Member distributions | $ 30,967 | |||||||||||||||
Long-Term Incentive Plan | Restricted Units | ||||||||||||||||
Common units | ||||||||||||||||
Restricted units forfeited (in units) | 1,469 | |||||||||||||||
Common Units | ||||||||||||||||
Common units | ||||||||||||||||
Units outstanding (in units) | 18,056,487 | 16,509,799 | 16,509,799 | 16,509,799 | 18,056,487 | 16,509,799 | ||||||||||
Capital rollforward | ||||||||||||||||
Unitholders' capital, beginning balance (in units) | 16,509,799 | 16,509,799 | ||||||||||||||
Common units issued under the LTIP (in units) | 1,049,946 | |||||||||||||||
Common units issued for acquisition (in units) | 10,000,000 | |||||||||||||||
Common units issued for equity offering (in units) | 3,450,000 | |||||||||||||||
Unit exchange related to tax conversion (in units) | (12,953,258) | |||||||||||||||
Unitholders' capital, ending balance (in units) | 18,056,487 | 16,509,799 | 18,056,487 | |||||||||||||
Class B | ||||||||||||||||
Common units | ||||||||||||||||
Units issued (in units) | 18,056,487 | |||||||||||||||
Units outstanding (in units) | 19,453,258 | 19,453,258 | 19,453,258 | |||||||||||||
Capital rollforward | ||||||||||||||||
Unit exchange related to tax conversion (in units) | 12,953,258 | |||||||||||||||
Class B units issued for Drop Down acquisition | 6,500,000 | |||||||||||||||
Unitholders' capital, ending balance (in units) | 19,453,258 | 19,453,258 | ||||||||||||||
Cash distributions (as a percent) | 2.00% | |||||||||||||||
Public Offering | Common Units | ||||||||||||||||
Capital rollforward | ||||||||||||||||
Common units issued for equity offering (in units) | 3,450,000 | |||||||||||||||
Underwriters' option | Common Units | ||||||||||||||||
Capital rollforward | ||||||||||||||||
Common units issued for equity offering (in units) | 450,000 | |||||||||||||||
Certain Employees, Directors and Consultants | Long-Term Incentive Plan | Restricted Units | ||||||||||||||||
Capital rollforward | ||||||||||||||||
Common units issued under the LTIP (in units) | 720,283 | 326,654 | ||||||||||||||
Directors | Long-Term Incentive Plan | Restricted Units | ||||||||||||||||
Capital rollforward | ||||||||||||||||
Common units issued under the LTIP (in units) | 4,478 | |||||||||||||||
Predecessor | ||||||||||||||||
Capital rollforward | ||||||||||||||||
Member distributions | $ 0 |
EARNINGS (LOSS) PER UNIT (Detai
EARNINGS (LOSS) PER UNIT (Details) - USD ($) | Feb. 07, 2017 | Feb. 07, 2017 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2016 |
Earnings per unit | |||||||||||||
Net (loss) income attributable to common units | $ 1,715,740 | $ (56,767,549) | |||||||||||
Net (loss) income attributable to common units per unit (basic) | $ (0.10) | $ (0.15) | $ 0.08 | $ (3.23) | $ 0.06 | $ 0.01 | $ 0.02 | $ 0.02 | $ 0.11 | $ (3.08) | |||
Weighted average number of common units outstanding Basic (in units) | 16,336,871 | 18,442,234 | |||||||||||
Net (loss) income attributable to common units per unit (diluted) | $ (0.10) | $ (0.15) | $ 0.08 | $ (3.23) | $ 0.06 | $ 0.01 | $ 0.02 | $ 0.02 | $ 0.10 | $ (3.08) | |||
Weighted average number of common units outstanding Diluted (in units) | 16,455,602 | 18,442,234 | |||||||||||
Restricted Units | |||||||||||||
Earnings per unit | |||||||||||||
Anti-dilutive options outstanding | 1,157,924 | ||||||||||||
Weighted average number of common units outstanding (in units) | 118,731 | ||||||||||||
Predecessor | |||||||||||||
Earnings per unit | |||||||||||||
Net (loss) income attributable to common units | $ (496,856) | $ (6,212,619) | |||||||||||
Net (loss) income attributable to common units per unit (basic) | $ (0.82) | $ (10.28) | |||||||||||
Weighted average number of common units outstanding Basic (in units) | 604,137 | 604,137 | |||||||||||
Net (loss) income attributable to common units per unit (diluted) | $ (0.82) | $ (10.28) | |||||||||||
Weighted average number of common units outstanding Diluted (in units) | 604,137 | 604,137 | |||||||||||
Predecessor | Options | |||||||||||||
Earnings per unit | |||||||||||||
Anti-dilutive options outstanding | 110,000 | 110,000 |
UNIT-BASED COMPENSATION (Detail
UNIT-BASED COMPENSATION (Details) | Sep. 23, 2018shares | Feb. 07, 2017USD ($)shares | Dec. 31, 2017USD ($)$ / sharesshares | Dec. 31, 2018USD ($)$ / sharesshares | Dec. 31, 2017$ / sharesshares | Dec. 31, 2016USD ($) |
Weighted Average Remaining Contractual Term | ||||||
Share-based compensation | $ | $ 798,413 | $ 3,170,299 | ||||
Long-Term Incentive Plan | ||||||
Unit-based compensation | ||||||
Authorized issuance of units | 4,541,600 | |||||
Additional common units authorized for issuance | 2,500,000 | |||||
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 | ||||||
Unvested at beginning of period (in units) | 167,571 | |||||
Granted - service condition employees (in units) | 622,212 | |||||
Granted - service condition consultants (in units) | 31,238 | |||||
Granted - non-employee directors | 397,965 | |||||
Forfeited (in units) | (1,469) | |||||
Vested (in units) | (59,593) | |||||
Unvested at end of period (in units) | 167,571 | 1,157,924 | 167,571 | |||
Unvested Weighted Average Grant-Date Fair Value | ||||||
Unvested at beginning of period (in dollars per unit) | $ / shares | $ 18.655 | |||||
Granted - service condition employees (in dollars per unit) | $ / shares | $ 17.894 | |||||
Granted - service condition consultants (in dollars per unit) | 17.588 | |||||
Granted - non-employee directors | $ / shares | 18.183 | |||||
Forfeited (in dollars per unit) | $ / shares | $ (17.610) | |||||
Vested (in dollars per unit) | $ / shares | (18.695) | |||||
Unvested at end of period (in dollars per unit) | $ / shares | $ 18.655 | $ 18.054 | $ 18.655 | |||
Weighted Average Remaining Contractual Term | ||||||
Unvested contractual term, at end of period | 2 years 8 months 11 days | 1 year 4 months 11 days | ||||
Predecessor | ||||||
Weighted Average Remaining Contractual Term | ||||||
Share-based compensation | $ | $ 50,422 | $ 605,059 | ||||
Predecessor | Long-Term Incentive Plan | ||||||
Unit-based compensation | ||||||
Authorized issuance of units | 110,000 | |||||
Weighted Average Remaining Contractual Term | ||||||
Share-based compensation | $ | $ 50,000 | $ 600,000 |
INCOME TAXES - Other (Details)
INCOME TAXES - Other (Details) | 12 Months Ended |
Dec. 31, 2018USD ($) | |
INCOME TAXES | |
Effective income tax rate (as a percent) | (0.50%) |
Current income taxes payable | $ 0 |
Federal tax loss carryforwards | 622,775 |
State tax loss carryforwards | $ 70,441 |
INCOME TAXES - Expense (Details
INCOME TAXES - Expense (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2016 | |
Current | ||
State | $ 24,681 | |
Total Current | 24,681 | |
Deferred | ||
Provision for income taxes | $ 24,681 | |
Predecessor | ||
Current | ||
State | $ 19,848 | |
Total Current | 19,848 | |
Deferred | ||
Provision for income taxes | $ 19,848 |
INCOME TAXES - Reconciliation (
INCOME TAXES - Reconciliation (Details) - USD ($) | 1 Months Ended | 11 Months Ended | 12 Months Ended | |
Feb. 07, 2017 | Dec. 31, 2017 | Dec. 31, 2018 | Dec. 31, 2016 | |
Reconciliation of the provision for income taxes at statutory rates to the provision for income taxes at the effective tax rate | ||||
Net (loss) income before taxes | $ 1,715,740 | $ (52,257,542) | ||
Statutory rate (as a percent) | 35.00% | 21.00% | ||
Income tax expense computed at statutory rate | $ 600,509 | $ (10,974,084) | ||
State income taxes | (70,441) | |||
Texas margins tax | 24,681 | |||
Change in tax status | (20,038,820) | |||
Non-controlling interest | (360,082) | |||
Income (loss) not subject to corporate tax | $ (600,509) | 10,598,375 | ||
Change in valuation allowance - federal | 20,771,214 | |||
Change in valuation allowance - state | 70,441 | |||
Other, net | 3,397 | |||
Provision for income taxes | $ 24,681 | |||
Predecessor | ||||
Reconciliation of the provision for income taxes at statutory rates to the provision for income taxes at the effective tax rate | ||||
Net (loss) income before taxes | $ (496,856) | $ (6,192,771) | ||
Statutory rate (as a percent) | 35.00% | 35.00% | ||
Income tax expense computed at statutory rate | $ (173,900) | $ (2,167,470) | ||
Texas margins tax | 19,848 | |||
Income (loss) not subject to corporate tax | $ 173,900 | 2,167,470 | ||
Provision for income taxes | $ 19,848 |
INCOME TAXES - Deferred Taxes (
INCOME TAXES - Deferred Taxes (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Deferred tax asset | ||
Outside basis in OpCo | $ 21,036,307 | |
Federal tax loss carryforwards | 622,775 | |
State tax loss carryforwards | 70,441 | |
Deferred tax assets | 21,729,523 | |
Valuation allowance | (20,841,655) | |
Net deferred tax assets | 887,868 | |
Deferred tax liability | ||
Derivative instruments and other | 887,868 | |
Net deferred tax liability | 887,868 | |
Operating Loss Carryforwards | 600,000 | |
Outside basis investment in operating company valuation allowance | 17,000,000 | |
Uncertain tax positions | $ 0 | $ 0 |
RELATED PARTY TRANSACTIONS (Det
RELATED PARTY TRANSACTIONS (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2018 | Dec. 31, 2017 | |
Related Party Transactions | ||
Outstanding receivable from Rivercrest Capital Management and certain employees | $ 7,773 | $ 12,550 |
Steward Royalties | ||
Related Party Transactions | ||
Payments made to related parties | 130,000 | |
Taylor Companies | ||
Related Party Transactions | ||
Payments made to related parties | 526,855 | |
K3 Royalties | ||
Related Party Transactions | ||
Payments made to related parties | 120,000 | |
Nail Bay Royalties | ||
Related Party Transactions | ||
Payments made to related parties | 356,837 | |
Duncan Management | ||
Related Party Transactions | ||
Payments made to related parties | $ 521,981 |
ADMINISTRATIVE SERVICES (Detail
ADMINISTRATIVE SERVICES (Details) $ in Millions | Jul. 12, 2018USD ($) |
Haymaker | |
Transition Service Agreement amount of administrative services to be received | $ 2.3 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES (Details) | Dec. 31, 2018USD ($) |
COMMITMENTS AND CONTINGENCIES. | |
2019 | $ 369,079 |
2020 | 522,904 |
2021 | 488,253 |
2022 | 488,253 |
2023 | 492,236 |
Thereafter | 2,761,280 |
Total | $ 5,122,005 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - USD ($) | Feb. 06, 2019 | Jan. 25, 2019 | Dec. 31, 2018 |
Subsequent events | |||
Distributions on Series A redeemable preferred units | $ 2,630,834 | ||
Subsequent Event | |||
Subsequent events | |||
Distribution on Series A redeemable preferred units (in dollars per unit) | $ 17.27 | ||
Distributions on Series A redeemable preferred units | $ 1,900,000 | ||
Cash distributions declared (in dollars per unit) | $ 0.40 | ||
Subsequent Event | PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLLC | |||
Subsequent events | |||
Business Combination, Consideration Transferred | $ 151,300,000 | ||
Subsequent Event | PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLLC | OpCo Units | |||
Subsequent events | |||
Purchase price units (in units) | 9,400,000 | ||
Subsequent Event | PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLLC | Class B Common Units | |||
Subsequent events | |||
Purchase price units (in units) | 9,400,000 |
SUPPLEMENTAL OIL AND GAS RESE_3
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, 2018USD ($)segment | Dec. 31, 2016USD ($) | |
Number of reporting segments | segment | 1 | |||
Oil, natural gas and NGL interests | ||||
Proved | $ 297,609,797 | $ 538,290,590 | ||
Unevaluated properties | 280,304,353 | |||
Total oil, natural gas and NGL interest | 297,609,797 | 818,594,943 | ||
Less: accumulated depreciation, depletion and impairment | (15,394,238) | (107,779,453) | ||
Net oil and natural gas properties | 282,215,559 | 710,815,490 | ||
Acquisition costs | ||||
Proved properties | 297,609,797 | 243,227,632 | ||
Unevaluated properties | 288,334,110 | |||
Total | 297,609,797 | 531,561,742 | ||
Developed costs | ||||
Total costs incurred on oil, natural gas and NGL activities | 297,609,797 | 531,561,742 | ||
Results of operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities | ||||
Oil, natural gas and NGL revenue | 29,943,920 | 65,713,112 | ||
Lease bonus and other income | 721,172 | 1,213,550 | ||
Production and ad valorem taxes | (2,452,058) | (4,399,667) | ||
Depreciation, depletion and accretion expense | (15,394,238) | (25,213,043) | ||
Impairment of oil and natural properties | (67,311,501) | |||
Marketing and other deductions | (1,648,895) | (4,652,313) | ||
Results of operations form oil, natural gas and NGLs | $ 11,169,901 | $ (34,649,862) | ||
Predecessor | ||||
Developed costs | ||||
Proved properties | $ 78,159 | |||
Total | 78,159 | |||
Total costs incurred on oil, natural gas and NGL activities | 78,159 | |||
Results of operations from Oil, Natural Gas and Natural Gas Liquids Producing Activities | ||||
Oil, natural gas and NGL revenue | $ 318,310 | 3,606,659 | ||
Production and ad valorem taxes | (19,651) | (280,474) | ||
Depreciation, depletion and accretion expense | (113,639) | (1,604,208) | ||
Impairment of oil and natural properties | (4,992,897) | |||
Marketing and other deductions | (110,534) | (750,792) | ||
Results of operations form oil, natural gas and NGLs | $ 74,486 | $ (4,021,712) |
SUPPLEMENTAL OIL AND GAS RESE_4
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Proved Oil, Natural Gas and Natural Liquids Reserve Quantities (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018USD ($)itemMMcfMBbls | Dec. 31, 2017USD ($)MMcfMBbls | Dec. 31, 2016itemMMcfMBbls | |
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Net proved reserves at beginning of period | 20,954 | ||
Revisions of previous estimates | 1,437 | 217 | |
Purchase of minerals in place | 17,473 | 3,355 | |
Extensions, discoveries and other additions | 973 | ||
Production | (2,213) | (1,181) | |
Net proved reserves at end of period | 37,651 | 20,954 | |
Net Proved Developed Reserves | 33,633 | 15,403 | |
Net Proved Undeveloped Reserves | 4,018 | 5,551 | |
Crude Oil and Condensate | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Net proved reserves at beginning of period | 7,463 | ||
Revisions of previous estimates | 194 | (193) | |
Purchase of minerals in place | 3,729 | 362 | |
Extensions, discoveries and other additions | 505 | ||
Production | (591) | (421) | |
Net proved reserves at end of period | 10,795 | 7,463 | |
Net Proved Developed Reserves | 9,183 | 5,284 | |
Net Proved Undeveloped Reserves | 1,612 | 2,179 | |
Natural Gas | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Net proved reserves at beginning of period | MMcf | 63,916 | ||
Revisions of previous estimates | MMcf | 1,754 | (1,535) | |
Purchase of minerals in place | MMcf | 69,465 | 16,312 | |
Extensions, discoveries and other additions | MMcf | 2,261 | ||
Production | MMcf | (7,874) | (3,512) | |
Net proved reserves at end of period | MMcf | 127,261 | 63,916 | |
Net Proved Developed Reserves | MMcf | 116,321 | 47,501 | |
Net Proved Undeveloped Reserves | MMcf | 10,940 | 16,415 | |
Natural Gas Liquids | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Net proved reserves at beginning of period | 2,838 | ||
Revisions of previous estimates | 952 | 666 | |
Purchase of minerals in place | 2,166 | 274 | |
Extensions, discoveries and other additions | 91 | ||
Production | (310) | (175) | |
Net proved reserves at end of period | 5,646 | 2,838 | |
Net Proved Developed Reserves | 5,063 | 2,202 | |
Net Proved Undeveloped Reserves | 583 | 636 | |
Mineral And Royalty Interests | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Purchase of mineral and royalty interests | $ | $ 29.3 | ||
Permian Basis, Haynesville Shale, Mid-Continent Area, Appalachia Region and Eagle Ford Shale | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Purchase of mineral and royalty interests | $ | $ 243.2 | ||
Number of packages of diverse mineral and royalty interests acquired | item | 2 | ||
Permian Basin, Haynesville Shale, Mid Continent Area and Appalachia Region | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Purchase of mineral and royalty interests | $ | $ 155.7 | ||
Permian Basin, Eagle Ford Shale and Appalachia Region | |||
Proved Oil, Natural Gas and Natural Gas Liquids Reserve Quantities | |||
Purchase of mineral and royalty interests | $ | $ 87.5 | ||
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 | ||
Number of contiguous Eagle Ford drilling units acquired | item | 3 | ||
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 RESE_5
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Standardized Measure (Details) - USD ($) | Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Standardized Measure | ||||
Future cash inflows | $ 1,056,464 | $ 562,967 | ||
Future production costs | (79,724) | (45,652) | ||
Future state margin taxes | (32,885) | (2,790) | ||
Future income tax expense | (41,241) | |||
Future net cash flows | 902,614 | 514,525 | ||
Less 10% annual discount to reflect timing of cash flows | (504,247) | (298,973) | ||
Standard measure of discounted future net cash flows | $ 398,367 | $ 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 RESE_6
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Average Market Prices (Details) - $ / bbl | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Crude Oil and Condensate | |||
Average Sales Prices | |||
Average sales prices | 65.56 | 51.34 | |
Natural Gas | |||
Average Sales Prices | |||
Average sales prices | 3.10 | 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 RESE_7
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED) - Changes in Standardized Measure (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | |
Changes in Standardized Measure | |||
Standardized measure - beginning of period | $ 215,552 | $ 159,275 | |
Sales, net of production costs | (56,661) | (29,288) | |
Net changes of prices and production costs related to future production | 11,355 | 21,946 | |
Extensions, discoveries and improved recovery, net of future production costs | 10,064 | ||
Revisions of previous quantity estimates, net of related costs | 16,385 | 2,248 | |
Net changes in state margin taxes | (13,271) | 301 | |
Net changes in income taxes | (17,232) | ||
Accretion of discount | 21,555 | 15,928 | |
Purchases of reserves in place | 175,885 | 23,309 | |
Timing differences and other | 44,799 | 11,769 | |
Standardized measure - end of period | $ 398,367 | 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 |
SELECTED QUARTERLY FINANCIAL _3
SELECTED QUARTERLY FINANCIAL INFORMATION - Unaudited (Details) - USD ($) | 3 Months Ended | 11 Months Ended | 12 Months Ended | |||||||
Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2018 | |
Total revenue | $ 30,251,018 | $ 18,407,956 | $ 10,707,898 | $ 10,891,338 | $ 9,689,522 | $ 8,351,399 | $ 7,751,998 | $ 4,553,344 | ||
Net (loss) income | $ (1,609,575) | $ (3,711,798) | $ 1,378,295 | $ (52,824,471) | $ 1,061,842 | $ 119,029 | $ 251,651 | $ 283,218 | ||
Net (loss) income attributable to common units per unit (basic) | $ (0.10) | $ (0.15) | $ 0.08 | $ (3.23) | $ 0.06 | $ 0.01 | $ 0.02 | $ 0.02 | $ 0.11 | $ (3.08) |
Net (loss) income attributable to common units per unit (diluted) | (0.10) | (0.15) | 0.08 | (3.23) | 0.06 | 0.01 | 0.02 | 0.02 | $ 0.10 | $ (3.08) |
Cash distributions declared and paid (in dollars per unit) | $ 0.40 | $ 0.45 | $ 0.43 | $ 0.42 | $ 0.36 | $ 0.31 | $ 0.30 | $ 0.23 | ||
Total assets | $ 753,285,373 | $ 683,893,161 | $ 249,318,570 | $ 237,201,565 | $ 295,291,004 | $ 290,406,599 | $ 289,918,996 | $ 279,419,440 | $ 295,291,004 | $ 753,285,373 |
Long-term debt | 87,309,544 | 148,309,544 | 42,972,997 | 30,843,593 | 30,843,593 | 22,214,090 | 18,265,090 | 3,877,500 | 30,843,593 | 87,309,544 |
Mezzanine equity | 69,449,006 | 67,904,422 | 69,449,006 | |||||||
Partners' capital/unitholder's equity | 294,965,598 | 247,441,471 | $ 198,879,415 | $ 203,848,774 | $ 262,065,434 | $ 265,893,106 | $ 270,288,690 | 273,657,870 | $ 262,065,434 | 294,965,598 |
Noncontrolling interest | $ 297,761,199 | $ 209,450,877 | $ 297,761,199 | |||||||
Predecessor | ||||||||||
Total revenue | 318,310 | |||||||||
Net (loss) income | $ (496,856) | |||||||||
Net (loss) income attributable to common units per unit (basic) | $ (0.82) | |||||||||
Net (loss) income attributable to common units per unit (diluted) | $ (0.82) |