NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Significant Accounting Policies
For a description of the Partnership’s significant accounting policies, see Note 2 of the consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019, as well as the items noted below. There have been no substantial changes in such policies or the application of such policies during the three months ended March 31, 2020, other than those discussed below in Recently Adopted Accounting Pronouncements.
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.
New Accounting Pronouncements
Recently Adopted Pronouncements
In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-13, “Fair Value Measurement (Topic 820): Disclosure Framework — Changes to the Disclosure Requirements for Fair Value Measurement.” This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels. The Partnership adopted this update on January 1, 2020 and applied it prospectively. The adoption of this update did not have a material impact on the Partnership’s results of operations for the three months ended March 31, 2020.
In June 2016, the FASB issued ASU 2016-13, “Financial Instruments —Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments,” which changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard replaced the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The Partnership adopted this update using the modified retrospective approach, effective January 1, 2020. The adoption of this update did not have a material impact on the Partnership’s results of operations for the three months ended March 31, 2020.
Accounting Pronouncements Not Yet Adopted
In December 2019, the FASB issued ASU 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes,” that is expected to reduce cost and complexity related to accounting for income taxes. The amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. 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.
NOTE 3—ACQUISITIONS AND JOINT VENTURES
Acquisitions
On March 25, 2019, the Partnership acquired 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 aggregate consideration for the Phillips Acquisition consisted of 9,400,000 common units of the Operating Company (“OpCo common units”) and an equal number of Class B units representing limited partner interests of the Partnership (“Class B units”). The Class B units and OpCo common units are exchangeable together into an equal number of common units representing limited partner interests in the Partnership (“common units”). The assets acquired in the Phillips Acquisition consisted of approximately 866,528 gross acres and 12,210 net royalty acres.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of financial condition and results of operations should be read together in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10‑Q (this “Quarterly Report”), as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019 (the “2019 Form 10-K”).
Unless the context otherwise requires, references to “Kimbell Royalty Partners, LP,” the “Partnership,” “we” or “us” refer to Kimbell Royalty Partners, LP and its subsidiaries. References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to the “General Partner” refer to Kimbell Royalty GP, LLC. References to the “Sponsors” refer to affiliates of the Partnership’s founders, Ben J. Fortson, Robert D. Ravnaas, Brett G. Taylor and Mitch S. Wynne, respectively. References to the “Contributing Parties” refer to all entities and individuals, including certain affiliates of the Sponsors, that contributed, directly or indirectly, certain mineral and royalty interests to the Partnership.
Cautionary Statement Regarding Forward‑Looking Statements
Certain statements and information in this Quarterly Report may constitute forward‑looking statements. Forward‑looking statements give our current expectations, contain projections of results of operations or of financial condition, or forecasts of future events. Words such as “may,” “assume,” “forecast,” “position,” “predict,” “strategy,” “expect,” “intend,” “plan,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward‑looking statements. They can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward‑looking statements can be guaranteed. When considering these forward‑looking statements, you should keep in mind the risk factors and other cautionary statements in this Quarterly Report. Actual results may vary materially. You are cautioned not to place undue reliance on any forward‑looking statements. You should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of future operations or acquisitions. Factors that could cause our actual results to differ materially from the results contemplated by such forward‑looking statements include:
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our ability to replace our reserves;
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our ability to make, consummate and integrate acquisitions of assets or businesses and realize the benefits or effects of any acquisitions or the timing, final purchase price or consummation of any acquisitions;
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our ability to execute our business strategies;
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the volatility of realized prices for oil, natural gas and natural gas liquids (“NGL”);
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the level of production on our properties;
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the level of drilling and completion activity by the operators of our properties;
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regional supply and demand factors, delays or interruptions of production;
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general economic, business or industry conditions;
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competition in the oil and natural gas industry generally and the mineral and royalty industry in particular;
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the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;
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title defects in the properties in which we acquire an interest;
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uncertainties with respect to identified drilling locations and estimates of reserves on our properties and on properties we seek to acquire;
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the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;
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restrictions on or the availability of the use of water in the business of the operators of our properties;
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the availability of transportation facilities;
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the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
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federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry;
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future operating results;
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exploration and development drilling prospects, inventories, projects and programs;
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operating hazards faced by the operators of our properties;
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the ability of the operators of our properties to keep pace with technological advancements;
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uncertainties regarding United States federal income tax treatment of our future earnings and distributions;
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the effects of weak economic conditions and oil and natural gas market disruptions, including the impacts of the ongoing COVID-19 pandemic;
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our ability to remediate any material weakness in, or to maintain effective, internal controls over financial reporting and disclosure controls and procedures; and
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certain factors discussed elsewhere in this Quarterly Report.
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Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.
Overview
We are 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, we have elected to be taxed as a corporation for United States federal income tax purposes. As an owner of mineral and royalty interests, we are entitled to a portion of the revenues received from the production of oil, natural gas and associated NGLs from the acreage underlying our interests, net of post‑production expenses and taxes. We are 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. Our primary business objective is to provide increasing cash distributions to unitholders resulting from acquisitions from third parties, our Sponsors and the Contributing Parties and from organic growth through the continued development by working interest owners of the properties in which we own an interest.
As of March 31, 2020, we owned mineral and royalty interests in approximately 8.8 million gross acres and overriding royalty interests in approximately 4.6 million gross acres, with approximately 60% of our aggregate acres located in the Permian Basin, Mid-Continent and Bakken/Williston Basin. We refer to these non‑cost‑bearing interests collectively as our “mineral and royalty interests.” As of March 31, 2020, over 98% of the acreage subject to our mineral and royalty interests was leased to working interest owners, including 100% of our overriding royalty interests, and substantially all of those leases were held by production. Our mineral and royalty interests are located in 28 states and in every major onshore basin across the continental United States and include ownership in over 94,000 gross wells, including over 40,000 wells in the Permian Basin. Subsequent to the Springbok Acquisition (as defined below), our mineral and royalty interests include ownership in over 96,000 gross wells.
The following table summarizes our ownership in United States basins and producing regions, information about the wells in which we have a mineral or royalty interest and the number of active rigs operating on acreage in which we have a mineral or royalty interest as of March 31, 2020:
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Average Daily
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Average Daily
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Production
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Production
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Basin or Producing Region
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Gross Acreage
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Net Acreage
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(Boe/d)(6:1)(1)
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(Boe/d)(20:1)(2)
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Well Count
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Permian Basin
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|
2,627,226
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22,606
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|
2,483
|
|
1,988
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|
40,416
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Mid‑Continent
|
|
3,870,076
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|
40,881
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|
1,790
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|
1,105
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|
10,905
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Haynesville
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745,807
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7,058
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2,043
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637
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|
8,535
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Appalachia
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721,656
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23,074
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1,976
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847
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|
3,065
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Bakken
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|
1,555,557
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5,959
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|
603
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|
524
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|
3,916
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Eagle Ford
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|
618,085
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6,683
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1,671
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1,298
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2,973
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Rockies
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46,328
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829
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398
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202
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12,089
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Other
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3,221,334
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36,687
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2,394
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1,290
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12,928
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Total
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13,406,069
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143,777
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13,358
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7,891
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94,827
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(1)
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“Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per barrel of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between oil and natural gas. Please read “Business—Oil and Natural Gas Data—Proved Reserves—Summary of Estimated Proved Reserves” in our Annual Report on Form 10-K for the year ended December 31, 2019.
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(2)
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“Value-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of 20 Mcf of natural gas per barrel of “oil equivalent,” which is the conversion factor we use in our business.
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Recent Developments
Springbok Acquisition
On April 17, 2020, we completed the acquisition of the equity interests in Springbok Energy Partners, LLC and Springbok Energy Partners II, LLC (the “Springbok Acquisition”) from the owners of such entities. The aggregate consideration for the Springbok Acquisition consisted of (i) $95.0 million in cash, subject to standard pre-closing adjustments, (ii) the issuance of 2,224,358 common units and (iii) the issuance of 2,497,134 OpCo common units and an equal number of Class B units. The cash portion of the acquisition was funded by borrowings under our secured revolving credit facility.
As of March 31, 2020, the acreage acquired in the Springbok Acquisition had over 90 operators on 2,160 net royalty acres across core areas of the Delaware Basin, DJ Basin, Haynesville, STACK, Eagle Ford and other leading basins. In addition, the acreage acquired in the Springbok Acquisition produced 2,586 Boe/d (56% natural gas, 34% oil and 10% NGLs) (6:1) as of March 31, 2020. The following table summarizes information about the number of drilled but uncompleted wells (“DUCs”) and permitted locations on acreage in which we have a mineral or royalty interest as of March 31, 2020 after giving effect to the Springbok Acquisition:
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Basin or Producing Region(1)
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Gross DUCs
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Gross Permits
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Net DUCs
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Net Permits
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Permian Basin
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|
168
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|
111
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|
0.85
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|
0.53
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Mid‑Continent
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|
142
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|
88
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|
0.30
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|
0.10
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Haynesville
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|
67
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|
20
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0.40
|
|
0.19
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Appalachia
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|
51
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|
54
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|
0.21
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|
0.20
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Bakken
|
|
221
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|
86
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|
0.22
|
|
0.26
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Eagle Ford
|
|
144
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|
50
|
|
0.88
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|
0.33
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Rockies
|
|
89
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|
67
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|
0.10
|
|
0.74
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Total
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|
882
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|
476
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|
2.96
|
|
2.35
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|
(1)
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The above table represents drilled but uncompleted wells and permitted locations only, and there is no guarantee that the drilled but uncompleted wells or permitted locations will be developed into producing wells in the future.
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2020 Equity Offering
In January 2020, we completed an underwritten public offering of 5,000,000 common units for net proceeds of approximately $73.6 million (the “2020 Equity Offering”). We used the net proceeds from the 2020 Equity Offering to purchase OpCo common units. The Operating Company in turn used the net proceeds to repay approximately $70.0 million of the outstanding borrowings under our secured revolving credit facility. In connection with the 2020 Equity Offering, certain selling unitholders sold 750,000 common units pursuant to the exercise of the underwriters’ option to purchase additional common units. We did not receive any proceeds from the sale of the common units by the selling unitholders.
2020 Partial Redemption of Series A Preferred Units
On February 12, 2020, we completed the redemption of 55,000 Series A preferred units, representing 50% of the then-outstanding Series A preferred units. The Series A preferred units were redeemed at a price of $1,110.72 per Series A preferred unit for an aggregate redemption price of $61.1 million.
First Quarter Distributions
On May 6, 2020, we paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended March 31, 2020.
Each holder of Class B units has paid five cents per Class B unit to us as an additional capital contribution for the Class B units (such aggregate amount, the “Class B Contribution”) in exchange for Class B units. Each holder of Class B units is entitled to receive cash distributions equal to 2.0% per quarter on their respective Class B Contribution. On May 6, 2020, we paid a quarterly cash distribution to each Class B unitholder, resulting in a total quarterly distribution of $20,644 for the quarter ended March 31, 2020.
On April 24, 2020, the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.17 per common unit for the quarter ended Mach 31, 2020. The distribution will be paid on May 11, 2020 to common unitholders and OpCo common unitholders of record as of the close of business on May 4, 2020.
Business Environment
COVID-19 Pandemic and Impact on Global Demand for Oil and Natural Gas
On March 11, 2020, the World Health Organization (the “WHO”) declared the ongoing coronavirus (“COVID-19”) outbreak a pandemic and recommended containment and mitigation measures worldwide. The pandemic has reached more than 200 countries and has resulted in widespread adverse impacts on the global economy, our oil, natural gas, and NGL operators and other parties with whom we have business relations. Our first priority in our response to this crisis has been the health and safety of our employees, the employees of our business counterparties and the community in which we operate. To address these concerns, we have modified certain business practices (including those related to employee travel, employee work locations, and cancellation of physical participation in meetings, events and conferences) to conform to government restrictions and best practices encouraged by the Centers for Disease Control and Prevention, the WHO and other governmental and regulatory authorities. Since mid-March, we have restricted access to our offices to only essential employees, and have directed the remainder of our employees to work from home to the extent possible. These restrictions have had minimal impact on our operations to date and have allowed us to maintain the engagement and connectivity of our personnel, as well as minimize the number of employees required in the office.
There is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental and other measures implemented to try to slow the spread of the virus, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns. One of the largest impacts of the pandemic has been a significant reduction in global demand for oil and, to a lesser extent, natural gas. This significant decline in demand has been met with a sharp decline in oil prices which has been exacerbated by the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries (“OPEC”) and other foreign, oil-exporting countries. The resulting supply/demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from
the COVID-19 pandemic, are expected to lead to significant global economic contraction generally and in our industry in particular.
Oil and natural gas prices have historically been volatile; however, the volatility in the prices for these commodities has substantially increased as a result of COVID-19 and the OPEC decisions mentioned above. While an agreement to cut production has since been announced by OPEC and its allies, the situation, coupled with the impact of COVID-19, has continued to result in a significant downturn in the oil and gas industry. Oil prices declined sharply in April 2020 and have remained low. Although strip pricing for natural gas has increased meaningfully, the impact of these recent developments on our business and the oil and gas industry is unpredictable. Although we derived approximately 32% of our revenues and 58% of our production (6:1) from natural gas for the first quarter of 2020, which we believe presents some downside protection against depressed oil prices, we expect that low oil prices and commodity price volatility will continue through the second quarter of 2020 and perhaps longer.
In April 2020, we have received notices from two operators regarding well shut-ins and curtailments of production on properties in which we own an interest. The properties are primarily located in the Eagle Ford Shale, and the production attributable to such properties on a Boe/d basis (6:1) represented approximately one percent of our total production for the first quarter of 2020. We expect that as the supply/demand imbalance resulting from the COVID-19 outbreak and OPEC decisions mentioned above continues, and as oil storage facilities reach capacity and/or purchasers of crude products cancel previous orders, more of our operators may adjust or reduce their drilling activities, which could have an adverse effect on our business, cash flows, liquidity, financial condition and results of operations in the second quarter of 2020. Due to the expected significant decline in the average of the trailing twelve month first-of-month pricing used in the full-cost ceiling test, we expect to record an impairment to our oil and natural gas properties in the second quarter of 2020 as a result of the full-cost ceiling limitation.
The ultimate impacts of COVID-19 and the volatility currently being experienced in the oil and natural gas markets on our business, cash flows, liquidity, financial condition and results of operations will depend on future developments, including, among others, the ultimate geographic spread of the virus, the consequences of governmental and other measures designed to prevent the spread of the virus, the development of effective treatments, the duration of the outbreak, actions taken by members of OPEC and other foreign, oil-exporting countries, governmental authorities and other thirds parties, workforce availability, and the timing and extent to which normal economic and operating conditions resume. For additional discussion regarding the risks associated with the COVID-19 pandemic, see Item 1A “Risk Factors” in this report.
Commodity Prices and Demand
Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (“EIA”).
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Three Months Ended
March 31, 2020
|
|
Three Months Ended
March 31, 2019
|
|
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High
|
|
Low
|
|
High
|
|
Low
|
Oil ($/Bbl)
|
|
$
|
63.27
|
|
$
|
14.10
|
|
$
|
60.19
|
|
$
|
46.31
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Natural gas ($/MMBtu)
|
|
$
|
2.17
|
|
$
|
1.65
|
|
$
|
4.25
|
|
$
|
2.54
|
On May 1, 2020, the West Texas Intermediate posted price for crude oil was $19.72 per Bbl and the Henry Hub spot market price of natural gas was $1.69 per MMBtu.
The following table, as reported by the EIA, sets forth the average daily prices for oil and natural gas.
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|
|
|
|
|
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|
Three Months Ended March 31,
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|
2020
|
|
2019
|
Oil ($/Bbl)
|
|
$
|
45.54
|
|
$
|
54.82
|
Natural gas ($/MMBtu)
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|
$
|
1.90
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|
$
|
2.92
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Rig Count
Drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. As such, we monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.
The Baker Hughes United States Rotary Rig count decreased by 27.6% from 1,006 active rigs as of March 31, 2019 to 728 active rigs as of March 31, 2020.
According to the Baker Hughes United States Rotary Rig count, rig activity in the 28 states in which we own mineral and royalty interests included 718 active rigs as of March 31, 2020 compared to 1,000 active rigs as of March 31, 2019. Rig activity in the 28 states in which we own mineral and royalty interests declined further to 404 active rigs as of May 1, 2020, and there were 70 active rigs operating on our acreage, inclusive of acreage we acquired in the Springbok Acquisition, as of April 17, 2020.
The following table summarizes the number of active rigs operating on our acreage by United States basins and producing regions for the periods indicated:
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March 31,
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Basin or Producing Region
|
|
2020
|
|
2019
|
Permian Basin
|
|
30
|
|
26
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Mid‑Continent
|
|
13
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|
19
|
Haynesville
|
|
8
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|
10
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Appalachia
|
|
3
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|
4
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Bakken
|
|
11
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|
12
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Eagle Ford
|
|
8
|
|
11
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Rockies
|
|
2
|
|
7
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Other
|
|
-
|
|
-
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Total
|
|
75
|
|
89
|
Sources of Our Revenue
Our revenues are derived from royalty payments we receive from our operators based on the sale of oil, natural gas and NGL production, as well as the sale of NGLs that are extracted from natural gas during processing. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.
The following table presents the breakdown of our operating income for the following periods:
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|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
Royalty income
|
|
|
|
|
|
|
Oil sales
|
|
58
|
%
|
|
50
|
%
|
Natural gas sales
|
|
32
|
%
|
|
39
|
%
|
NGL sales
|
|
9
|
%
|
|
10
|
%
|
Lease bonus and other income
|
|
1
|
%
|
|
1
|
%
|
|
|
100
|
%
|
|
100
|
%
|
We entered into oil and natural gas commodity derivative agreements with Frost Bank, beginning January 1, 2018 which extend through March 2022, to establish, in advance, a price for the sale of a portion of the oil, natural gas and NGLs produced from our mineral and royalty interests.
Non‑GAAP Financial Measures
Adjusted EBITDA and Cash Available for Distribution
Adjusted EBITDA and cash available for distribution are used as supplemental non-GAAP financial measures (as defined below) by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA and cash available for distribution are useful because they allow us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our unitholders.
We define Adjusted EBITDA as net income (loss), net of non‑cash unit‑based compensation, change in fair value of open commodity derivative instruments, transaction costs, impairment of oil and natural gas properties, income taxes, interest expense and depreciation and depletion expense. Adjusted EBITDA is not a measure of net income (loss) as determined by generally accepted accounting principles in the United States (“GAAP”). We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets, none of which are components of Adjusted EBITDA. We define cash available for distribution as Adjusted EBITDA, less cash needed for debt service and other contractual obligations, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.
Adjusted EBITDA and cash available for distribution should not be considered an alternative to net income (loss), oil, natural gas and NGL revenues, net cash flows provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA and cash available for distribution may not be comparable to other similarly titled measures of other companies.
The tables below present a reconciliation of Adjusted EBITDA to net loss and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated (unaudited).
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|
|
|
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|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
Reconciliation of net loss to Adjusted EBITDA:
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|
|
|
|
|
|
Net loss
|
|
$
|
(59,784,399)
|
|
$
|
(5,345,363)
|
Depreciation and depletion expense
|
|
|
13,270,683
|
|
|
10,281,008
|
Interest expense
|
|
|
1,421,304
|
|
|
1,422,563
|
EBITDA
|
|
|
(45,092,412)
|
|
|
6,358,208
|
Impairment of oil and natural gas properties
|
|
|
70,925,731
|
|
|
2,802,198
|
Unit‑based compensation
|
|
|
2,107,587
|
|
|
1,770,410
|
(Gain) loss on commodity derivative instruments, net of settlements
|
|
|
(8,978,861)
|
|
|
5,165,884
|
Cash distribution from equity method investee
|
|
|
17,961
|
|
|
—
|
Equity income in affiliate
|
|
|
(163,554)
|
|
|
—
|
Consolidated Adjusted EBITDA
|
|
|
18,816,452
|
|
|
16,096,700
|
Adjusted EBITDA attributable to noncontrolling interest
|
|
|
(7,059,747)
|
|
|
(9,407,010)
|
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP
|
|
|
11,756,705
|
|
|
6,689,690
|
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
|
|
|
|
|
|
|
Cash interest expense
|
|
|
703,952
|
|
|
624,289
|
Cash distributions on Series A preferred units
|
|
|
1,202,759
|
|
|
800,018
|
Distributions on Class B units
|
|
|
24,807
|
|
|
23,814
|
Cash available for distribution on common units
|
|
$
|
9,825,187
|
|
$
|
5,241,569
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
20,787,606
|
|
$
|
15,812,332
|
Interest expense
|
|
|
1,421,304
|
|
|
1,422,563
|
Impairment of oil and natural gas properties
|
|
|
(70,925,731)
|
|
|
(2,802,198)
|
Amortization of right-of-use assets
|
|
|
(67,470)
|
|
|
(11,204)
|
Amortization of loan origination costs
|
|
|
(266,318)
|
|
|
(257,727)
|
Equity income in affiliate
|
|
|
163,554
|
|
|
—
|
Unit-based compensation
|
|
|
(2,107,587)
|
|
|
(1,770,410)
|
Gain (loss) on commodity derivative instruments, net of settlements
|
|
|
8,978,861
|
|
|
(5,165,884)
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
Oil, natural gas and NGL receivables
|
|
|
(4,913,049)
|
|
|
(1,294,164)
|
Accounts receivable and other current assets
|
|
|
508,985
|
|
|
492,900
|
Accounts payable
|
|
|
450,579
|
|
|
692,149
|
Other current liabilities
|
|
|
809,594
|
|
|
(776,928)
|
Operating lease liabilities
|
|
|
67,260
|
|
|
16,779
|
EBITDA
|
|
|
(45,092,412)
|
|
|
6,358,208
|
Add:
|
|
|
|
|
|
|
Impairment of oil and natural gas properties
|
|
|
70,925,731
|
|
|
2,802,198
|
Unit‑based compensation
|
|
|
2,107,587
|
|
|
1,770,410
|
(Gain) loss on commodity derivative instruments, net of settlements
|
|
|
(8,978,861)
|
|
|
5,165,884
|
Cash distribution from equity method investee
|
|
|
17,961
|
|
|
—
|
Equity income in affiliate
|
|
|
(163,554)
|
|
|
—
|
Consolidated Adjusted EBITDA
|
|
|
18,816,452
|
|
|
16,096,700
|
Adjusted EBITDA attributable to noncontrolling interest
|
|
|
(7,059,747)
|
|
|
(9,407,010)
|
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP
|
|
$
|
11,756,705
|
|
$
|
6,689,690
|
Factors Affecting the Comparability of Our Results to Our Historical Results
Our historical financial condition and results of operations may not be comparable, either from period to period or going forward, to our future financial condition and results of operations, for the reasons described below.
Ongoing Acquisition Activities
Acquisitions are an important part of our growth strategy, and we expect to pursue acquisitions of mineral and royalty interests from third parties, affiliates of our Sponsors and the Contributing Parties. As a part of these efforts, we often engage in discussions with potential sellers or other parties regarding the possible purchase of or investment in mineral and royalty interests, including in connection with a dropdown of assets from affiliates of our Sponsors and the Contributing Parties. Such efforts may involve participation by us in processes that have been made public and involve a number of potential buyers or investors, commonly referred to as "auction" processes, as well as situations in which we believe we are the only party or one of a limited number of parties who are in negotiations with the potential seller or other party. These acquisition and investment efforts often involve assets which, if acquired or constructed, could have a material effect on our financial condition and results of operations. Material acquisitions that would impact the comparability of our results for the three months ended March 31, 2020 and 2019 include the acquisition of 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”) and the acquisition of certain mineral and royalty assets from certain affiliates of Buckhorn Resources GP, LLC (the “Buckhorn Acquisition”).
Further, the affiliates of our Sponsors and Contributing Parties have no obligation to sell any assets to us or to accept any offer that we may make for such assets, and we may decide not to acquire such assets even if such parties offer them to us. We may decide to fund any acquisition, including any potential dropdowns, with cash, common units, other equity securities, proceeds from borrowings under our secured revolving credit facility or the issuance of debt securities, or any combination thereof. In addition to acquisitions, we also consider from time to time divestitures that may benefit us and our unitholders.
We typically do not announce a transaction until after we have executed a definitive agreement. Past experience has demonstrated that discussions and negotiations regarding a potential transaction can advance or terminate in a short period of time. Moreover, the closing of any transaction for which we have entered into a definitive agreement may be subject to customary and other closing conditions, which may not ultimately be satisfied or waived. Accordingly, we can give no assurance that our current or future acquisition or investment efforts will be successful or that our strategic asset divestitures will be completed. Although we expect the acquisitions and investments we make to be accretive in the long term, we can provide no assurance that our expectations will ultimately be realized. We will not know the immediate results of any acquisition until after the acquisition closes, and we will not know the long term results for some time thereafter.
Impairment of Oil and Natural Gas Properties
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. The net capitalized costs of proved oil and natural gas properties are subject to a full-cost ceiling limitation for which the costs are not allowed to exceed their related estimated future net revenues discounted at 10%. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment, exceed estimated discounted future net revenues of proved oil and natural gas reserves, the excess capitalized costs are charged to expense. The risk that we will be required to recognize impairments of our oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and natural gas prices increase the cost center ceiling applicable to the subsequent period.
We recorded an impairment on our oil and natural gas properties of $70.9 million and $2.8 million for the three months ended March 31, 2020 and 2019, respectively. The impairment recorded during the three months ended March 31, 2020 was due to the recent significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks related to reduced demand for oil and natural gas as a result of COVID-19 and other supply factors. After evaluating these external factors, we determined that significant drilling uncertainty existed regarding our proved undeveloped (“PUD”) reserves that were included in our total estimated proved reserves as of December 31, 2019, as well as our unevaluated oil and natural gas properties. Specifically, with respect to our PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), we determined that we did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties. We similarly recorded an impairment on the value of our unevaluated oil and natural gas properties, which primarily were acquired in various acquisitions since our initial public offering. We intend not to book PUD reserves going forward. The impairment recorded for the three months ended March 31, 2019 was primarily a result of a decline in the 12-month average price of oil and natural gas.
As discussed in our Annual Report on Form 10-K for the year ended December 31, 2019, we do not intend to book proved undeveloped reserves going forward. As such, additional impairment charges could be recorded in connection with future acquisitions. Further, due to the expected significant decline in the average of the trailing twelve month first-of-month pricing used in the full-cost ceiling test, we expect to record an impairment to our oil and natural gas properties in the second quarter of 2020 as a result of the full-cost ceiling limitation. If the expected significant decline in the price of oil, natural gas and NGLs continues through future periods or if prices decrease further in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.
Results of Operations
The table below summarizes our revenue and expenses and production data for the periods indicated (unaudited).
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
Operating Results:
|
|
|
|
|
|
|
Revenue
|
|
|
|
|
|
|
Oil, natural gas and NGL revenues
|
|
$
|
25,585,439
|
|
$
|
22,833,393
|
Lease bonus and other income
|
|
|
229,319
|
|
|
83,606
|
Gain (loss) on commodity derivative instruments, net
|
|
|
10,132,613
|
|
|
(4,969,790)
|
Total revenues
|
|
|
35,947,371
|
|
|
17,947,209
|
Costs and expenses
|
|
|
|
|
|
|
Production and ad valorem taxes
|
|
|
1,621,743
|
|
|
1,596,394
|
Depreciation and depletion expense
|
|
|
13,270,683
|
|
|
10,281,008
|
Impairment of oil and natural gas properties
|
|
|
70,925,731
|
|
|
2,802,198
|
Marketing and other deductions
|
|
|
2,131,552
|
|
|
1,857,043
|
General and administrative expenses
|
|
|
6,524,311
|
|
|
5,333,366
|
Total costs and expenses
|
|
|
94,474,020
|
|
|
21,870,009
|
Operating loss
|
|
|
(58,526,649)
|
|
|
(3,922,800)
|
Other income (expense)
|
|
|
|
|
|
|
Equity income in affiliate
|
|
|
163,554
|
|
|
—
|
Interest expense
|
|
|
(1,421,304)
|
|
|
(1,422,563)
|
Net loss
|
|
|
(59,784,399)
|
|
|
(5,345,363)
|
Distribution and accretion on Series A preferred units
|
|
|
(3,076,684)
|
|
|
(3,469,584)
|
Net loss attributable to noncontrolling interests
|
|
|
23,584,856
|
|
|
5,151,509
|
Distribution on Class B units
|
|
|
(24,807)
|
|
|
(23,814)
|
Net loss attributable to common units
|
|
$
|
(39,301,034)
|
|
$
|
(3,687,252)
|
Production Data:
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
334,149
|
|
|
226,601
|
Natural gas (Mcf)
|
|
|
4,264,345
|
|
|
3,336,723
|
Natural gas liquids (Bbls)
|
|
|
170,689
|
|
|
120,155
|
Combined volumes (Boe) (6:1)
|
|
|
1,215,562
|
|
|
902,877
|
Comparison of the Three Months Ended March 31, 2020 to the Three Months Ended March 31, 2019
Oil, Natural Gas and NGL Revenues
For the three months ended March 31, 2020, our oil, natural gas and NGL revenues were $25.6 million, an increase of $2.8 million from $22.8 million for the three months ended March 31, 2019. The increase in revenues was primarily attributable to the revenues from additional production associated with the Phillips Acquisition, which contributed approximately $3.6 million to the overall increase, and to a lesser extent, the revenues associated with the Buckhorn Acquisition and the acquisition of various mineral and royalty interests in Oklahoma, which together contributed approximately $1.2 million to the increase. Partially offsetting the increase in oil, natural gas and NGL revenues was a decrease in the average prices we received for oil and NGL production.
Our revenues are a function of oil, natural gas, and NGL production volumes sold and average prices received for those volumes. The production volumes were 1,215,562 Boe or 13,358 Boe/d, for the three months ended March 31, 2020, an increase of 312,685 Boe or 3,326 Boe/d, from 902,877 Boe or 10,032 Boe/d, for the three months ended March 31, 2019.
The increase in production was primarily attributable to production associated with the Phillips Acquisition, which accounted for 150,557 Boe. Also contributing to the increase was production associated with the Haymaker assets, which accounted for 102,619 Boe and was primarily related to additional upside production that was previously unknown and recognized in the current quarter.
Our operators received an average of $45.25 per Bbl of oil, $1.93 per Mcf of natural gas and $13.17 per Bbl of NGL for the volumes sold during the three months ended March 31, 2020 and $50.89 per Bbl of oil, $2.68 per Mcf of natural gas and $19.70 per Bbl of NGL for the volumes sold during the three months ended March 31, 2019. The three months ended March 31, 2020 decreased 11.1% or $5.64 per Bbl of oil and 28.0% or $0.75 per Mcf of natural gas as compared to the three months ended March 31, 2019. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 16.9% or $9.28 per Bbl of oil and 34.9% or $1.02 per Mcf of natural gas for the comparable periods.
Gain (Loss) on Commodity Derivative Instruments
Gain on commodity derivative instruments for the three months ended March 31, 2020 included $9.0 million of mark-to-market gains and $1.1 million of gains on the settlement of commodity derivative instruments compared to $5.2 million of mark-to-market losses and $0.2 million of gains on the settlement of commodity derivative instruments for the three months ended March 31, 2019. We recorded a mark-to-market gain for the three months ended March 31, 2020 as a result of the decrease in the price of oil and natural gas contracts relative to the fixed-price in our open derivative contracts.
Production and Ad Valorem Taxes
Our production and ad valorem taxes remained flat at $1.6 million for both the three months ended March 31, 2020 and 2019.
Depreciation and Depletion Expense
Depreciation and depletion expense for the three months ended March 31, 2020 was $13.3 million, an increase of $3.0 million from $10.3 million for the three months ended March 31, 2019. The increase in the depreciation and depletion expense was primarily attributable to the acquisition of various mineral and royalty interests in Oklahoma and the Buckhorn Acquisition, which together added approximately $45.5 million of depletable costs to the full-cost pool.
Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of hydrocarbons extracted during such period, calculated on a units‑of‑production basis. Estimates of proved developed reserves are a major component in the calculation of depletion. Our average depletion rate per barrel was $10.86 for the three months ended March 31, 2020, a decrease of $0.52 per barrel from the $11.38 average depletion rate per barrel for the three months ended March 31, 2019. The decrease in the depletion rate was due to the significant impairment
that was recorded during the three months ended December 31, 2019, which significantly reduced our net capitalized oil and natural gas properties.
Impairment of Oil, Natural Gas and Natural Gas Liquids Expense
We recorded an impairment expense on our oil and natural gas properties of $70.9 million and $2.8 million during the three months ended March 31, 2020 and 2019, respectively. The impairment recorded during the three months ended March 31, 2020 was due to the recent significant decline in oil and natural gas prices, as well as longer-term commodity price outlooks related to reduced demand for oil and natural gas as a result of COVID-19 and other supply factors. After evaluating these external factors, we determined that significant drilling uncertainty existed regarding our PUD reserves that were included in our total estimated proved reserves as of December 31, 2019, as well as our unevaluated oil and natural gas properties. Specifically, with respect to our PUD reserves (which accounted for approximately 6.1% of total estimated proved reserves as of December 31, 2019), we determined that we did not have reasonable certainty as to the timing of the development of the PUD reserves and, therefore, recorded an impairment on such properties. We similarly recorded an impairment on the value of our unevaluated oil and natural gas properties, which primarily were acquired in various acquisitions since our initial public offering. We intend not to book PUD reserves going forward. The impairment recorded for the three months ended March 31, 2019 was primarily a result of a decline in the 12-month average price of oil and natural gas.
Marketing and Other Deductions
Our marketing and other deductions include product marketing expense, which is a post‑production expense. Marketing and other deductions for the three months ended March 31, 2020 were $2.1 million, an increase of $0.2 million from $1.9 million for the three months ended March 31, 2019.
General and Administrative Expenses
General and administrative expenses for the three months ended March 31, 2020 were $6.5 million, an increase of $1.2 million from $5.3 million for the three months ended March 31, 2019. Included within general and administrative expenses are non-cash expenses for unit-based compensation as a result of the amortization of restricted units that have been issued by us over various periods. The increase in general and administrative expenses was partially attributable to a $0.3 million increase in unit-based compensation expense. Also contributing to the increase were cash general and administrative expenses resulting from an increase in salaries and wages as a result of executive bonuses paid in the first quarter of 2020.
Interest Expense
Interest expense for both the three months ended March 31, 2020 and 2019 was $1.4 million.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash flows from operations and equity and debt financings and our primary uses of cash are for distributions to our unitholders and for growth capital expenditures, including the acquisition of mineral and royalty interests in oil and natural gas properties. Total commitments under our secured revolving credit facility are set at $225.0 million and the borrowing base is set at $300.0 million. The secured revolving credit facility permits aggregate commitments under the secured revolving credit facility to be increased to up to $500.0 million, subject to the limitations of our borrowing base and the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders, to be used for general partnership purposes, including working capital and acquisitions, among other things. As of May 1, 2020, we had an outstanding balance of $186.7 million under our secured revolving credit facility.
Cash Distribution Policy
The limited liability company agreement of the Operating Company requires it to distribute all of its cash on hand at the end of each quarter in an amount equal to its available cash for such quarter. In turn, our partnership agreement
requires us to distribute all of our cash on hand at the end of each quarter in an amount equal to our available cash for such quarter. Available cash for each quarter will be determined by the Board of Directors following the end of such quarter. “Available cash,” as used in this context, is defined in the limited liability company agreement of the Operating Company and our partnership agreement. We expect that the Operating Company’s available cash for each quarter will generally equal its Adjusted EBITDA for the quarter, less cash needed for debt service and other contractual obligations and fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate, and we expect that our available cash for each quarter will generally equal our Adjusted EBITDA for the quarter (and will be our proportional share of the available cash distributed by the Operating Company for that quarter), less cash needs for debt service and other contractual obligations and fixed charges, tax obligations and reserves for future operating or capital needs that the Board of Directors may determine is appropriate.
In light of the unprecedented global economic impact resulting from the COVID-19 pandemic, the related impact to the United States oil and natural gas markets and the potential for further curtailments of production, during its determination of “available cash” for the first quarter of 2020, our Board of Directors approved the allocation of 50% of our cash available for distribution for the first quarter of 2020, together with certain cash received at the closing of the Springbok Acquisition and other cash reserves, for the repayment of $15.0 million in outstanding borrowings under our secured revolving credit facility. With respect to future quarters, our Board of Directors may continue to allocate cash generated by our business to the repayment of outstanding borrowings under our secured revolving credit facility or in other manners in which our Board of Directors determines to be appropriate at the time, and our Board of Directors may further change its policy with respect to cash distributions in the future.
We do not currently maintain a material reserve of cash for the purpose of maintaining stability or growth in our quarterly distribution, nor do we intend to incur debt to pay quarterly distributions, although the Board of Directors may change this policy.
It is our intent, subject to market conditions, to finance acquisitions of mineral and royalty interests that increase our asset base largely through external sources, such as borrowings under our secured revolving credit facility and the issuance of equity and debt securities. For example, we financed the Phillips Acquisition with equity consideration of 9,400,000 OpCo common units and an equal number of Class B units, the Buckhorn Acquisition with equity consideration of 2,169,348 OpCo common units and an equal number of Class B units, and the Springbok Acquisition with a combination of cash consideration funded with borrowings of $95.0 million under our secured revolving credit facility and equity consideration of 2,224,358 common units and 2,497,134 OpCo common units and an equal number of Class B units. The Board of Directors may choose to reserve a portion of cash generated from operations to finance such acquisitions as well. We do not currently intend to (i) maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution, (ii) otherwise reserve cash for distributions or (iii) incur debt to pay quarterly distributions, although the Board of Directors may do so if they believe it is warranted.
On May 6, 2020, we paid a quarterly cash distribution on the Series A preferred units of approximately $1.0 million for the quarter ended March 31, 2020.
On May 6, 2020, we paid a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution, resulting in a total quarterly distribution of $20,644 for the quarter ended March 31, 2020.
On April 24, 2020, our Board of Directors declared a quarterly cash distribution of $0.17 per common unit for the quarter ended Mach 31, 2020. The distribution will be paid on May 11, 2020 to common unitholders and OpCo common unitholders of record as of the close of business on May 4, 2020.
Cash Flows
The table below presents our cash flows for the periods indicated.
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
|
2020
|
|
2019
|
Cash Flow Data:
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
20,787,606
|
|
$
|
15,812,332
|
Net cash used in investing activities
|
|
|
(11,176,643)
|
|
|
(838,432)
|
Net cash used in financing activities
|
|
|
(9,334,346)
|
|
|
(17,204,386)
|
Net increase (decrease) in cash
|
|
$
|
276,617
|
|
$
|
(2,230,486)
|
Operating Activities
Our operating cash flow is impacted by many variables, the most significant of which are changes in oil, natural gas and NGL production volumes due to acquisitions or other external factors and changes in prices for oil, natural gas and NGLs. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. Cash flows provided by operating activities for the three months ended March 31, 2020 were $20.8 million, an increase of $5.0 million compared to $15.8 million for the three months ended March 31, 2019. The increase in cash flows provided by operating activities was primarily attributable to the Phillips Acquisition and the Buckhorn Acquisition in the first and fourth quarters of 2019, respectively.
Investing Activities
Cash flows used in investing activities for the three months ended March 31, 2020 increased by $10.3 million compared to the three months ended March 31, 2019. For the three months ended March 31, 2020, we used $9.7 million to fund the deposit on oil and natural gas properties and $1.3 million to fund the capital commitments of a joint venture with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners. For the three months ended March 31, 2019, we used $0.5 million to fund the Phillips Acquisition and $0.3 million to fund the remodeling of our office space.
Financing Activities
Cash flows used in financing activities were $9.3 million for the three months ended March 31, 2020, a decrease of $7.9 million compared to $17.2 million for the three months ended March 31, 2019. Cash flows used in financing activities for the three months ended March 31, 2020 consists of $70.0 million used to repay borrowings under our secured revolving credit facility, $61.1 million to fund the redemption of Series A preferred units and $22.7 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units, partially offset by $73.6 million in proceeds from the 2020 Equity Offering and $71.1 million of additional borrowings under our secured revolving credit facility. Cash flows used in financing activities for the three months ended March 31, 2019 consists of $17.0 million of distributions paid to holders of common units and OpCo common units, Series A preferred units and Class B units and $0.7 million of issuance costs paid on Series A preferred units, partially offset by $0.5 million in contributions from our Class B unitholders.
Capital Expenditures
During the three months ended March 31, 2020, we paid approximately $0.2 million primarily in connection with the Buckhorn Acquisition. During the three months ended March 31, 2019, we paid approximately $0.5 million in connection with the Phillips Acquisition.
Indebtedness
We maintain a secured revolving credit facility that is secured by substantially all of our assets, the Operating Company’s assets and the assets of ours and the Operating Company’s wholly owned subsidiaries. Availability under our
secured revolving credit facility equals the lesser of the aggregate maximum commitments of the lenders and the borrowing base. Total commitments under our secured revolving credit facility are set at $225.0 million and the borrowing base is set at $300.0 million. The secured revolving credit facility permits aggregate commitments under our secured revolving credit facility to be increased to up to $500.0 million, subject to the limitations of our borrowing base and the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders. The borrowing base will be redetermined semiannually on or about May 1 and November 1 of each year based on the value of our oil and natural gas properties and the oil and natural gas properties of our wholly owned subsidiaries. In connection with the November 1, 2019 redetermination under the secured revolving credit facility, the borrowing base was reaffirmed at $300.0 million and total commitments remained at $225.0 million. The May borrowing base redetermination is currently being conducted and is expected to be finalized by the end of May 2020. A reduction in our borrowing base is not expected in connection with the May borrowing base redetermination as a result of the assets acquired in the Springbok Acquisition providing additional support to the borrowing base. However, in connection with any future redetermination, it is possible that the borrowing base will be reduced as a result of a decrease in the value of the assets underlying the borrowing base in connection with a sustained decrease in oil and natural gas prices. Even in the event that our borrowing base is reduced and assuming that the aggregate maximum commitments of the lenders under the secured revolving credit facility do not change, until such reduction or series of reductions in the aggregate is greater than $75.0 million, our ability to borrow would not be impacted because until that point the borrowing base would exceed the current commitments under the secured revolving credit facility. The secured revolving credit facility matures on February 8, 2022. We intend to request from our lenders an amendment to extend the term of the secured revolving credit facility beyond the current maturity date prior to March 31, 2021.
The secured revolving credit facility contains various affirmative, negative and financial maintenance covenants. These covenants limit our ability to, among other things, incur or guarantee additional debt, make distributions on, or redeem or repurchase, common units, make certain investments and acquisitions, incur certain liens or permit them to exist, enter into certain types of transactions with affiliates, merge or consolidate with another company and transfer, sell or otherwise dispose of assets. The secured revolving credit facility also contains covenants requiring us to maintain the following financial ratios or to reduce our indebtedness if we are unable to comply with such ratios: (i) a Debt to EBITDAX Ratio (as more fully defined in the secured revolving credit facility) of not more than 4.0 to 1.0; and (ii) a ratio of current assets to current liabilities of not less than 1.0 to 1.0. The secured revolving credit facility also contains customary events of default, including non‑payment, breach of covenants, materially incorrect representations, cross‑default, bankruptcy and change of control. As of March 31, 2020, we had outstanding borrowings of $101.2 million under the secured revolving credit facility and $123.8 million of available capacity (or approximately $198.8 million if aggregate commitments were equal to our current borrowing base).
For additional information on our secured revolving credit facility, please read Note 8―Long-Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report.
New and Revised Financial Accounting Standards
The effects of new accounting pronouncements are discussed in Note 2—Summary of Significant Accounting Policies to our unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report.
Critical Accounting Policies and Related Estimates
There have been no substantial changes to our critical accounting policies and related estimates from those previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019.
Contractual Obligations and Off‑Balance Sheet Arrangements
There have been no significant changes to our contractual obligations previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019. As of March 31, 2020, we did not have any off‑balance sheet arrangements other than operating leases.