Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of f
inancial 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, 2018 (the “2018 Form 10-K”).
On February 8, 2017, Kimbell Royalty Partners, LP (the “Partnership,” “we” or “us”) completed its initial public offering (“IPO”) of 5,750,000 common units representing limited partner interests. The mineral and royalty interests comprising our initial assets were contributed to us by certain entities and individuals (the “Contributing Parties”), including certain affiliates of our founders (our “Sponsors”), at the closing of our IPO.
References to the “Operating Company” refer to Kimbell Royalty Operating, LLC. References to “the General Partner” refer to Kimbell Royalty GP, LLC. References to “Kimbell Operating” refer to Kimbell Operating Company, LLC, a wholly owned subsidiary of the General Partner.
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,” “forecast,” “predict,” “strategy,” “expect,” “intend,” “estimate,” “anticipate,” “believe,” “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:
|
·
|
|
our ability to replace our reserves;
|
|
·
|
|
our ability to identify, complete and integrate acquisitions of assets or businesses;
|
|
·
|
|
the effect of our Tax Election (as defined below) or our Restructuring (as defined below) on our customer relationships, operating results and business generally;
|
|
·
|
|
the failure to realize the anticipated benefits of our Tax Election or Restructuring;
|
|
·
|
|
our ability to execute our business strategies;
|
|
·
|
|
the volatility of realized prices for oil, natural gas and natural gas liquids (“NGL”);
|
|
·
|
|
the level of production on our properties;
|
|
·
|
|
the level of drilling and completion activity by the operators of our properties;
|
|
·
|
|
regional supply and demand factors, delays or interruptions of production;
|
|
·
|
|
general economic, business or industry conditions;
|
|
·
|
|
competition in the oil and natural gas industry;
|
|
·
|
|
the ability of the operators of our properties to obtain capital or financing needed for development and exploration operations;
|
|
·
|
|
title defects in the properties in which we acquire;
|
|
·
|
|
uncertainties with respect to identified drilling locations and estimates of reserves;
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|
·
|
|
the availability or cost of rigs, completion crews, equipment, raw materials, supplies, oilfield services or personnel;
|
|
·
|
|
restrictions on or the availability of the use of water in the business of the operators of our properties;
|
|
·
|
|
the availability of transportation facilities;
|
|
·
|
|
the ability of the operators of our properties to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
|
|
·
|
|
federal and state legislative and regulatory initiatives relating to the environment, hydraulic fracturing, tax laws and other matters affecting the oil and gas industry;
|
|
·
|
|
future operating results;
|
|
·
|
|
exploration and development drilling prospects, inventories, projects and programs;
|
|
·
|
|
operating hazards faced by the operators of our properties;
|
|
·
|
|
the ability of the operators of our properties to keep pace with technological advancements; and
|
|
·
|
|
certain factors discussed elsewhere in this Quarterly Report.
|
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 June 30, 2019, we owned mineral and royalty interests in approximately 8.7 million gross acres and overriding royalty interests in approximately 4.3 million gross acres, with approximately 48% of our aggregate acres located in the Permian Basin and Mid-Continent. We refer to these non‑cost‑bearing interests collectively as our “mineral and royalty interests.” As of June 30, 2019, 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 92,000 gross producing wells, including over 40,000 wells in the Permian Basin.
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 our acreage as of June 30, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily
|
|
Average Daily
|
|
|
|
|
|
|
|
|
|
|
Production
|
|
Production
|
|
|
|
|
Basin or Producing Region
|
|
Gross Acreage
|
|
Net Acreage
|
|
(Boe/d)(6:1)(1)
|
|
(Boe/d)(20:1)(2)
|
|
Well Count
|
|
Active Rigs
|
Permian Basin
|
|
2,615,262
|
|
23,536
|
|
1,572
|
|
1,311
|
|
40,191
|
|
27
|
Mid‑Continent
|
|
3,589,116
|
|
40,550
|
|
1,471
|
|
807
|
|
10,115
|
|
15
|
Haynesville
|
|
745,745
|
|
7,058
|
|
1,897
|
|
605
|
|
8,460
|
|
15
|
Appalachia
|
|
721,656
|
|
23,074
|
|
1,741
|
|
677
|
|
2,985
|
|
5
|
Bakken
|
|
1,555,557
|
|
5,959
|
|
494
|
|
424
|
|
3,801
|
|
14
|
Eagle Ford
|
|
532,142
|
|
6,282
|
|
1,342
|
|
1,062
|
|
2,394
|
|
6
|
Rockies
|
|
46,328
|
|
829
|
|
539
|
|
300
|
|
12,044
|
|
3
|
Other
|
|
3,222,614
|
|
36,829
|
|
2,751
|
|
1,454
|
|
12,921
|
|
4
|
Total
|
|
13,028,420
|
|
144,117
|
|
11,807
|
|
6,640
|
|
92,911
|
|
89
|
|
(1)
|
|
"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, 2018.
|
|
(2)
|
|
"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.
|
Recent Developments
Transactions in Common Units
On April 10, 2019, Haymaker Minerals & Royalties, LLC exchanged 3,600,000
common units of the Operating Company ("OpCo Common Units")
and
common units representing limited partner interests of the Partnership ("Class B Units")
, together, for an
equal number of our common units.
On July 29, 2019, Haymaker Minerals & Royalties, LLC exchanged 400,000 OpCo Common Units and Class B Units, together, for an
equal number of our common units.
Joint Venture
On June 19, 2019, we entered into a joint venture (the “Joint Venture”) with Springbok SKR Capital Company, LLC and Rivercrest Capital Partners, LP. Our ownership in the Joint Venture is 49.3% and our total capital commitment will not exceed $15.0 million. The Joint Venture will be managed by Springbok Operating Company, LLC. The purpose of the Joint Venture will be to make direct or indirect investments in royalty, mineral and overriding royalty interests and similar non-cost bearing interests in oil and gas properties, excluding leasehold or working interests. We have paid $2.2 million in capital contributions through the date of this report.
Commodity Derivative Instruments
On June 28, 2019, we entered into additional oil and natural gas fixed price swaps with Frost Bank for the second quarter of 2021. The fixed price swaps consist of 59,423 Bbl of oil at a fixed rate of $54.52 per Bbl and 836,381 MMBtu of natural gas at a fixed rate of $2.43 per MMBtu.
Second Quarter Distributions
On August 7, 2019, the Operating Company paid a quarterly cash distribution of $0.411452 to holders of OpCo Common Units. As to the Partnership, $0.021452 of the distribution corresponds to a tax payment made by us from cash reserves in the second quarter of 2019. The second quarter 2019 tax payment made by us was generated by a gross income allocation related to the Series A Preferred Units, which were issued in connection with the Haymaker Acquisition. Under
the limited liability company agreement of the Operating Company, we are not reimbursed by the Operating Company for federal income taxes paid by us.
On August 9, 2019, we will pay a
quarterly cash distribution on the Series A Preferred Units of $1.9 million for the quarter ended June 30, 2019.
On August 9, 2019, we will pay
a quarterly cash distribution to each Class B unitholder equal to 2.0% of such unitholder’s respective Class B Contribution (as defined below), resulting in a total quarterly distribution of approximately $23,414 for the quarter ended June 30, 2019
.
On July 26, 2019 the General Partner’s Board of Directors (the “Board of Directors”) declared a quarterly cash distribution of $0.39 per common unit for the quarter ended June 30, 2019. The distribution will be paid on August 12, 2019 to common unitholders of record as of the close of business on August 5, 2019.
Business Environment
Commodity Prices and Demand
Oil and natural gas prices have been historically volatile and may continue to be volatile in the future. The table below demonstrates such volatility for the periods presented as reported by the United States Energy Information Administration (“EIA”).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30, 2019
|
|
Six Months Ended
June 30, 2018
|
|
|
High
|
|
Low
|
|
High
|
|
Low
|
Oil ($/Bbl)
|
|
$
|
66.24
|
|
$
|
46.31
|
|
$
|
77.41
|
|
$
|
59.20
|
Natural gas ($/MMBtu)
|
|
$
|
4.25
|
|
$
|
2.27
|
|
$
|
6.24
|
|
$
|
2.49
|
On July 29, 2019, the West Texas Intermediate posted price for crude oil was $56.85 per Bbl and the Henry Hub spot market price of natural gas was $2.23 per MMBtu.
The following table, as reported by the EIA, sets forth the average prices for oil and natural gas.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Oil ($/Bbl)
|
|
$
|
59.88
|
|
$
|
68.07
|
|
$
|
57.39
|
|
$
|
65.55
|
Natural gas ($/MMBtu)
|
|
$
|
2.57
|
|
$
|
2.85
|
|
$
|
2.74
|
|
$
|
2.96
|
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 7.6% from 1,047 active rigs as of June 30, 2018 to 967 active rigs as of June 30, 2019.
We own mineral and royalty interests in 28 states. 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 960 active rigs as of June 30, 2019 compared to 1,038 active rigs as of June 30, 2018.
The active rig count across our acreage as of June 30, 2019 remained steady at 89 active rigs compared to the active rigs at March 31, 2019. The 89 active rig count across our acreage as of June 30, 2019 increased significantly compared to the 25 active rigs as of June 30, 2018, primarily due to the additional mineral and royalty interests we acquired in connection with the acquisition of the equity interests in subsidiaries of PEP I Holdings, LLC, PEP II Holdings, LLC and PEP III Holdings, LLC (the “Phillips Acquisition”) in the first quarter of 2019, as well as the additional mineral and royalty interests we acquired in connection with the acquisition of the equity interests in certain subsidiaries owned by Haymaker Minerals & Royalties, LLC and Haymaker Properties, LP (the “Haymaker Acquisition”) and the acquisition of
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 equity interests of a subsidiary of Rivercrest Royalties Holdings II, LLC (the “Dropdown”), in the third and fourth quarters of 2018, respectively.
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Royalty income
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil sales
|
|
53
|
%
|
|
61
|
%
|
|
52
|
%
|
|
61
|
%
|
Natural gas sales
|
|
34
|
%
|
|
23
|
%
|
|
36
|
%
|
|
23
|
%
|
NGL sales
|
|
9
|
%
|
|
12
|
%
|
|
10
|
%
|
|
13
|
%
|
Lease bonus and other income
|
|
4
|
%
|
|
4
|
%
|
|
2
|
%
|
|
3
|
%
|
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
We entered into oil and natural gas commodity derivative agreements with Frost Bank beginning January 1, 2018 which extends through June 2021 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) income and net cash provided by operating activities, our most directly comparable GAAP financial measures, for the periods indicated (unaudited).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Reconciliation of net loss to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income
|
|
$
|
(20,365,487)
|
|
$
|
1,378,295
|
|
$
|
(25,710,850)
|
|
$
|
(51,446,176)
|
Depreciation and depletion expense
|
|
|
12,311,443
|
|
|
3,431,594
|
|
|
22,592,451
|
|
|
7,887,302
|
Interest expense
|
|
|
1,441,651
|
|
|
483,558
|
|
|
2,864,214
|
|
|
833,600
|
Provision for income taxes
|
|
|
507,801
|
|
|
—
|
|
|
507,801
|
|
|
—
|
EBITDA
|
|
|
(6,104,592)
|
|
|
5,293,447
|
|
|
253,616
|
|
|
(42,725,274)
|
Impairment of oil and natural gas properties
|
|
|
28,146,711
|
|
|
—
|
|
|
30,948,909
|
|
|
54,753,444
|
Transaction costs
|
|
|
—
|
|
|
1,188,967
|
|
|
—
|
|
|
1,188,967
|
Unit‑based compensation
|
|
|
2,112,764
|
|
|
723,039
|
|
|
3,883,174
|
|
|
1,391,973
|
Gain (loss) on commodity derivative instruments, net of settlements
|
|
|
(2,603,825)
|
|
|
469,072
|
|
|
2,562,059
|
|
|
681,530
|
Consolidated Adjusted EBITDA
|
|
|
21,551,058
|
|
|
7,674,525
|
|
|
37,647,758
|
|
|
15,290,640
|
Adjusted EBITDA attributable to noncontrolling interest
|
|
|
(10,940,971)
|
|
|
—
|
|
|
(20,347,981)
|
|
|
—
|
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP
|
|
|
10,610,087
|
|
|
7,674,525
|
|
|
17,299,777
|
|
|
15,290,640
|
Adjustments to reconcile Adjusted EBITDA to cash available for distribution
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash interest expense
|
|
|
582,829
|
|
|
502,811
|
|
|
1,207,118
|
|
|
977,487
|
Cash distributions on Series A preferred units
|
|
|
947,722
|
|
|
—
|
|
|
1,747,740
|
|
|
—
|
Cash income tax expense
|
|
|
504,000
|
|
|
—
|
|
|
504,000
|
|
|
—
|
Distributions on Class B units
|
|
|
23,814
|
|
|
—
|
|
|
47,628
|
|
|
—
|
Cash reserves
|
|
|
(504,000)
|
|
|
—
|
|
|
(504,000)
|
|
|
—
|
Cash available for distribution
|
|
$
|
9,055,722
|
|
$
|
7,171,714
|
|
$
|
14,297,291
|
|
$
|
14,313,153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Reconciliation of net cash provided by operating activities to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by operating activities
|
|
$
|
23,332,182
|
|
$
|
6,894,754
|
|
$
|
39,144,514
|
|
$
|
14,188,843
|
Interest expense
|
|
|
1,441,651
|
|
|
483,558
|
|
|
2,864,214
|
|
|
833,600
|
Provision for income taxes
|
|
|
507,801
|
|
|
—
|
|
|
507,801
|
|
|
—
|
Impairment of oil and natural gas properties
|
|
|
(28,146,711)
|
|
|
—
|
|
|
(30,948,909)
|
|
|
(54,753,444)
|
Amortization of right-of-use assets
|
|
|
(11,374)
|
|
|
—
|
|
|
(22,578)
|
|
|
—
|
Amortization of loan origination costs
|
|
|
(260,422)
|
|
|
(15,625)
|
|
|
(518,149)
|
|
|
(31,250)
|
Unit-based compensation
|
|
|
(2,112,764)
|
|
|
(723,039)
|
|
|
(3,883,174)
|
|
|
(1,391,973)
|
Gain (loss) on commodity derivative instruments, net of settlements
|
|
|
2,603,825
|
|
|
(469,072)
|
|
|
(2,562,059)
|
|
|
(681,530)
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and NGL receivables
|
|
|
(2,599,599)
|
|
|
37,453
|
|
|
(3,893,763)
|
|
|
(195,074)
|
Accounts receivable and other current assets
|
|
|
(167,330)
|
|
|
(144,931)
|
|
|
325,570
|
|
|
(10,032)
|
Accounts payable
|
|
|
257,657
|
|
|
(825,555)
|
|
|
949,806
|
|
|
(1,204,349)
|
Other current liabilities
|
|
|
(959,735)
|
|
|
55,904
|
|
|
(1,736,663)
|
|
|
519,935
|
Operating lease liabilities
|
|
|
10,227
|
|
|
—
|
|
|
27,006
|
|
|
—
|
EBITDA
|
|
|
(6,104,592)
|
|
|
5,293,447
|
|
|
253,616
|
|
|
(42,725,274)
|
Add:
|
|
|
|
|
|
|
|
|
|
|
|
|
Impairment of oil and natural gas properties
|
|
|
28,146,711
|
|
|
—
|
|
|
30,948,909
|
|
|
54,753,444
|
Transaction costs
|
|
|
—
|
|
|
1,188,967
|
|
|
—
|
|
|
1,188,967
|
Unit‑based compensation
|
|
|
2,112,764
|
|
|
723,039
|
|
|
3,883,174
|
|
|
1,391,973
|
Gain (loss) on commodity derivative instruments, net of settlements
|
|
|
(2,603,825)
|
|
|
469,072
|
|
|
2,562,059
|
|
|
681,530
|
Consolidated Adjusted EBITDA
|
|
|
21,551,058
|
|
|
7,674,525
|
|
|
37,647,758
|
|
|
15,290,640
|
Adjusted EBITDA attributable to noncontrolling interest
|
|
|
(10,940,971)
|
|
|
—
|
|
|
(20,347,981)
|
|
|
—
|
Adjusted EBITDA attributable to Kimbell Royalty Partners, LP
|
|
$
|
10,610,087
|
|
$
|
7,674,525
|
|
$
|
17,299,777
|
|
$
|
15,290,640
|
Factors Affecting the Comparability of Our Results to the 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.
Restructuring, Tax Election and Related Transactions
On July 24, 2018, we entered into a Recapitalization Agreement (the “Recapitalization Agreement”) with 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) our equity interest in the Operating Company was recapitalized into 13,886,204 newly issued OpCo Common Units of the Operating Company and 110,000 newly issued Series A Preferred Cumulative Convertible Units of 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 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 our common units.
In May 2018, the Board of Directors unanimously approved a change of our 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.
For each Class B Unit issued, five cents has been paid to us as additional consideration (the “Class B Contribution”). 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.
Following the effectiveness of the Tax Election and the completion of the related transactions, our 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.
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 $28.1 million for the three months ended June 30, 2019 primarily as a result of a decline in the 12-month average price of oil and natural gas. No impairment expense was recorded for the three months ended June 30, 2018. We recorded an impairment on our oil and natural gas properties of $30.9 million and $54.8 million as a result of our quarterly full-cost ceiling analysis for the six months ended June 30, 2019 and 2018, respectively. As discussed in our Annual Report on Form 10-K for the year ended December 31, 2018, 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, if the price of oil, natural gas and NGLs decreases in future periods, we may be required to record additional impairments as a result of the full-cost ceiling limitation.
Credit Agreement
In connection with our IPO, on January 11, 2017, we entered into a credit agreement (the “2017 Credit Agreement”) with Frost Bank, as administrative agent, and the lenders party thereto.
On July 12, 2018, in connection with the closing of the Haymaker Acquisition, we entered into an amendment (the “Credit Agreement Amendment”) to the 2017 Credit Agreement (the 2017 Credit Agreement as amended by the Credit Agreement Amendment, the “Amended Credit Agreement”), with certain of our subsidiaries, as guarantors, Frost Bank, as administrative agent, and the other lenders party thereto.
The Credit Agreement Amendment amended the 2017 Credit Agreement to provide for, among other things, (i) the addition of the subsidiaries we acquired in the Haymaker Acquisition, as well as the Operating Company, as guarantors under the Amended Credit Agreement, (ii) limitations on our ability to incur certain debt or issue preferred equity, (iii) limitations on redemptions of the Series A Preferred Units and our ability and our restricted subsidiaries’ ability to make distributions and other restricted payments, in each case, unless certain conditions are satisfied, (iv) increased limitations on our 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 our and the Operating Company’s ability to take certain actions or amend their organizational documents.
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. 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 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 order to include all assets acquired through the Phillips Acquisition in the borrowing base available under the Amended Credit Agreement, a borrowing base redetermination was completed in late May 2019. In connection with the redetermination, total commitments under the Amended Credit Agreement were increased from $200.0 million to $225.0 million and the borrowing base was increased from $200.0 million to $300.0 million. The secured revolving credit facility matures on February 8, 2022.
As of June 30, 2019, we had approximately $87.3 million in borrowings outstanding under our senior secured credit facility. For the three months ended June 30, 2019 and 2018, we incurred $1.4 million and $0.5 million, respectively, in interest expense. For the six months ended June 30, 2019 and 2018, we incurred $2.9 million and $0.8 million, respectively, in interest expense.
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 and six months ended June 30, 2019 and 2018 include the Phillips Acquisition, the Haymaker Acquisition and the Dropdown.
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.
Management Services Agreements
In connection with our IPO, we entered into a management services agreement with Kimbell Operating, which entered into separate services agreements with certain entities controlled by affiliates of our Sponsors and certain Contributing Parties, pursuant to which they and Kimbell Operating provide management, administrative and operational services to us. In addition, under each of their respective services agreements, affiliates of our Sponsors identify, evaluate and recommend to us 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 our unitholders.
Transition Services Agreement
On March 25, 2019, pursuant to the Phillips Acquisition, we entered into a Transition Services Agreement (the “Transition Services Agreement”) with Fortis Administrative Services, LLC (“Fortis”). Pursuant to the Transition Services Agreement, Fortis provided certain administrative services and accounting assistance on a transitional basis for total compensation of $300,000 from April 1, 2019 through June 1, 2019, at which point, the Transition Services Agreement was terminated.
Results of Operations
The table below summarizes our revenue and expenses and production data for the periods indicated (unaudited).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Operating Results:
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, natural gas and NGL revenues
|
|
$
|
27,913,975
|
|
$
|
10,847,677
|
|
$
|
50,747,368
|
|
$
|
21,655,856
|
Lease bonus and other income
|
|
|
1,289,044
|
|
|
398,610
|
|
|
1,372,650
|
|
|
766,734
|
Gain (loss) on commodity derivative instruments, net
|
|
|
2,733,582
|
|
|
(538,389)
|
|
|
(2,236,208)
|
|
|
(823,354)
|
Total revenues
|
|
|
31,936,601
|
|
|
10,707,898
|
|
|
49,883,810
|
|
|
21,599,236
|
Costs and expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and ad valorem taxes
|
|
|
1,924,943
|
|
|
805,396
|
|
|
3,521,337
|
|
|
1,621,397
|
Depreciation and depletion expense
|
|
|
12,311,443
|
|
|
3,431,594
|
|
|
22,592,451
|
|
|
7,887,302
|
Impairment of oil and natural gas properties
|
|
|
28,146,711
|
|
|
—
|
|
|
30,948,909
|
|
|
54,753,444
|
Marketing and other deductions
|
|
|
1,749,040
|
|
|
609,033
|
|
|
3,606,083
|
|
|
1,178,875
|
General and administrative expenses
|
|
|
6,220,499
|
|
|
4,000,022
|
|
|
11,553,865
|
|
|
6,770,794
|
Total costs and expenses
|
|
|
50,352,636
|
|
|
8,846,045
|
|
|
72,222,645
|
|
|
72,211,812
|
Operating (loss) income
|
|
|
(18,416,035)
|
|
|
1,861,853
|
|
|
(22,338,835)
|
|
|
(50,612,576)
|
Other expense
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
|
1,441,651
|
|
|
483,558
|
|
|
2,864,214
|
|
|
833,600
|
Net (loss) income before income taxes
|
|
|
(19,857,686)
|
|
|
1,378,295
|
|
|
(25,203,049)
|
|
|
(51,446,176)
|
Provision for income taxes
|
|
|
507,801
|
|
|
—
|
|
|
507,801
|
|
|
—
|
Net (loss) income
|
|
|
(20,365,487)
|
|
|
1,378,295
|
|
|
(25,710,850)
|
|
|
(51,446,176)
|
Distribution and accretion on Series A preferred units
|
|
|
(3,469,584)
|
|
|
—
|
|
|
(6,939,168)
|
|
|
—
|
Net loss attributable to noncontrolling interests
|
|
|
12,100,511
|
|
|
—
|
|
|
17,252,020
|
|
|
—
|
Distribution on Class B units
|
|
|
(23,814)
|
|
|
—
|
|
|
(47,628)
|
|
|
—
|
Net (loss) income attributable to common units
|
|
$
|
(11,758,374)
|
|
$
|
1,378,295
|
|
$
|
(15,445,626)
|
|
$
|
(51,446,176)
|
Production Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls)
|
|
|
268,963
|
|
|
108,201
|
|
|
495,564
|
|
|
218,087
|
Natural gas (Mcf)
|
|
|
4,030,160
|
|
|
999,019
|
|
|
7,366,883
|
|
|
1,983,385
|
Natural gas liquids (Bbls)
|
|
|
133,749
|
|
|
55,917
|
|
|
253,904
|
|
|
110,500
|
Combined volumes (Boe) (6:1)
|
|
|
1,074,405
|
|
|
330,621
|
|
|
1,977,282
|
|
|
659,151
|
Comparison of the Three Months Ended June 30, 2019 to the Three Months Ended June 30, 2018
Oil, Natural Gas and NGL Revenues
For the three months ended June 30, 2019, our oil, natural gas and NGL revenues were $27.9 million, an increase of $17.1 million from $10.8 million for the three months ended June 30, 2018. The increase in revenues was primarily attributable to the revenues associated with the Haymaker Acquisition, which represented approximately $10.1 million of the overall increase in oil, natural gas and NGL revenues, and to a lesser extent, the revenues associated with the Phillips Acquisition and Dropdown which contributed $5.4 million and $2.9 million, respectively, to the overall 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 1,074,405 Boe or 11,807 Boe/d, for the three months ended June 30, 2019, an increase of 743,784 Boe or 8,174 Boe/d, from 330,621 Boe or 3,633 Boe/d, for the three months ended June 30, 2018. The increase in production was primarily attributable to the Haymaker Acquisition, which represented 485,138 Boe or 5,331 Boe/d, and to a lesser extent, production associated with the Phillips Acquisition and Dropdown, which together accounted for 281,783 Boe or 3,097 Boe/d.
Our operators received an average of $57.55 per Bbl of oil, $2.44 per Mcf of natural gas and $19.55 per Bbl of NGL for the volumes sold during the three months ended June 30, 2019 and $63.45 per Bbl of oil, $2.59 per Mcf of natural gas and $25.03 per Bbl of NGL for the volumes sold during the three months ended June 30, 2018. The three months ended June 30, 2019 decreased 9.3% or $5.90 per Bbl of oil and 5.8% or $0.15 per Mcf of natural gas as compared to the three months ended June 30, 2018. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decreases of 12.0% or $8.19 per Bbl of oil and 9.8% or $0.28 per Mcf of natural gas for the comparable periods.
Gain on Commodity Derivative Instruments
Gain on commodity derivative instruments for the three months ended June 30, 2019 included $2.6 million of mark-to-market gains and $0.1 million of gains on the settlement of commodity derivative instruments compared to $0.5 million of mark-to-market losses and $0.1 million loss on the settlement of commodity derivative instruments for the three months ended June 30, 2018. We recorded a mark-to-market gain for the three months ended June 30, 2019 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
Production and ad valorem taxes increased significantly for the three months ended June 30, 2019 for a total of $1.9 million compared to $0.8 million for the three months ended June 30, 2018. The increase was primarily attributable to the Haymaker Acquisition, which accounted for $0.5 million of the increase in production and ad valorem taxes and, to the lesser extent, the Dropdown and Phillips Acquisition.
Depreciation and Depletion Expense
Depreciation and depletion expense for the three months ended June 30, 2019 was $12.3 million, an increase of $8.9 million from $3.4 million for the three months ended June 30, 2018. The increase in the depreciation and depletion expense was primarily attributable to the Haymaker Acquisition, the Dropdown and the Phillips Acquisition, which together added approximately $349.1 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 $11.45 for the three months ended June 30, 2019, an increase of $1.21 per barrel from the $10.24 average depletion rate per barrel for the three months ended June 30, 2018.
Impairment of Oil, Natural Gas and Natural Gas Liquids Expense
We recorded an impairment expense on our oil and natural gas properties of $28.1 million during the three months ended June 30, 2019 primarily as a result of the decline in the 12-month average price of oil and natural gas. No impairment expense was recorded for the three months ended June 30, 2018.
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 June 30, 2019 were $1.7 million, an increase of $1.1 million from $0.6 million for the three months ended June 30, 2018. The increase in marketing and other deductions was primarily attributable to the Haymaker Acquisition, which represents $0.7 million of the overall increase, and to a lesser extent, the Dropdown and the Phillips Acquisition.
General and Administrative Expenses
General and administrative expenses for the three months ended June 30, 2019 were $6.2 million, an increase of $2.2 million from $4.0 million for the three months ended June 30, 2018. 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 primarily attributable a $1.4 million increase in unit-based compensation expense, which included $0.3 million in unit-based compensation expense related to one-time severance costs incurred during the quarter. General and administrative expenses were also impacted by $0.1 million in cash expenses related to one-time severance costs incurred during the quarter. The remainder of the increase was primarily attributable to cash general and administrative expenses resulting from the Haymaker Acquisition, Dropdown and Phillips Acquisition.
Interest Expense
Interest expense for the three months ended June 30, 2019 was $1.4 million as compared to interest expense of $0.5 million for the three months ended June 30, 2018. This increase was due to debt incurred to fund acquisitions in 2018, including the Haymaker Acquisition.
Provision for Income Taxes
We recorded a provision for income taxes of $0.5 million for the three months ended June 30, 2019 as a result of a gross income allocation related to the Series A Preferred Units, which were issued in connection with the Haymaker Acquisition. Such costs are expected to continue throughout the remainder of 2019. Prior to the third quarter of 2018, we had no provision for or benefit from income taxes. Additionally, we assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is more likely than not, do not establish a valuation allowance. As of June 30, 2019, we recorded a full valuation allowance on our deferred tax assets. See Note 12—Income Taxes for further discussion.
Comparison of the Six Months Ended June 30, 2019 to the Six Months Ended June 30, 2018
Oil, Natural Gas and NGL Revenues
For the six months ended June 30, 2019, our oil, natural gas and NGL revenues were $50.7 million, an increase of $29.0 million from $21.7 million for the six months ended June 30, 2018. The increase in revenues was primarily attributable to the revenues associated with the Haymaker Acquisition, which represented approximately $20.1 million of the overall increase in oil, natural gas and NGL revenues, and to a lesser extent, the revenues associated with the Phillips Acquisition and Dropdown, which contributed $10.8 million and $5.9 million, respectively, to the overall 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 1,977,282 Boe or 10,924 Boe/d, for the six months ended June 30, 2019, an increase of 1,318,131 Boe or 7,282 Boe/d, from 659,151 Boe or 3,642 Boe/d, for the six months ended June 30, 2018. The increase in production was primarily attributable to the Haymaker Acquisition, which represented 948,043 Boe or 5,238 Boe/d, and to a lesser extent, production associated with the Phillips Acquisition and Dropdown, which together accounted for 570,064 Boe or 3,150 Boe/d.
Our operators received an average of $54.51 per Bbl of oil, $2.55 per Mcf of natural gas and $19.62 per Bbl of NGL for the volumes sold during the six months ended June 30, 2019 and $62.20 per Bbl of oil, $2.64 per Mcf of natural gas and $25.85 per Bbl of NGL for the volumes sold during the six months ended June 30, 2018. The six months ended June 30, 2019 decreased 12.4% or $7.69 per Bbl of oil and 3.4% or $0.09 per Mcf of natural gas compared to the six months ended June 30, 2018. This change is consistent with prices experienced in the market, specifically when compared to the EIA average price decrease of 12.4% or $8.16 per Bbl of oil and 7.4% or $0.22 per Mcf of natural gas for the comparable periods.
Loss on Commodity Derivative Instruments
Loss on commodity derivative instruments for the six months ended June 30, 2019 included $2.6 million of mark-to-market losses and $0.3 million of gains on the settlement of commodity derivative instruments compared to $0.7 million of mark-to-market losses and $0.1 million loss on the settlement of commodity derivative instruments for the six months ended June 30, 2018. We recorded a mark-to-market loss for the six months ended June 30, 2019 as a result of the increase in volumes hedged due to Haymaker Acquisition, partially offset by 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
Production and ad valorem taxes increased significantly for the six months ended June 30, 2019 for a total of $3.5 million compared to $1.6 million for the three months ended June 30, 2018. The increase was primarily attributable to the Haymaker Acquisition, which accounted for $0.9 million of the increase in production and ad valorem taxes and, to the lesser extent, the Dropdown and Phillips Acquisition.
Depreciation and Depletion Expense
Depreciation and depletion expense for the six months ended June 30, 2019 was $22.6 million, an increase of $14.7 million from $7.9 million for the six months ended June 30, 2018. The increase in the depreciation and depletion expense was primarily attributable to the Haymaker Acquisition, the Dropdown and the Phillips Acquisition, which together added approximately $349.1 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 $11.42 for the six months ended June 30, 2019, a decrease of $0.41 per barrel from the $11.83 average depletion rate per barrel for the six months ended June 30, 2018. The decrease was primarily attributable to the $54.8 million of impairment recorded on our oil and natural gas properties during the six months ended June 30, 2018.
Impairment of Oil, Natural Gas and Natural Gas Liquids Expense
We recorded an impairment expense on our oil and natural gas properties of $30.9 million and $54.8 million during the six months ended June 30, 2019 and 2018, respectively, as a result of our quarterly full cost ceiling analysis.
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 six months ended June 30, 2019 were $3.6 million, an increase of $2.4 million from $1.2 million for the six months ended June 30, 2018. The increase in marketing and other deductions was primarily attributable to the Haymaker Acquisition, which represents $1.6 million of the overall increase, and to a lesser extent, the Dropdown and the Phillips Acquisition.
General and Administrative Expenses
General and administrative expenses for the six months ended June 30, 2019 were $11.6 million, an increase of $4.8 million from $6.8 million for the six months ended June 30, 2018. The increase in general and administrative expenses was primarily attributable the $2.5 million increase in unit-based compensation expense. The remainder of the increase was primarily attributable to cash general and administrative expenses resulting from the Haymaker Acquisition, Dropdown and Phillips Acquisition.
Interest Expense
Interest expense for the six months ended June 30, 2019 was $2.9 million as compared to interest expense of $0.8 million for the six months ended June 30, 2018. This increase was due to debt incurred to fund acquisitions in 2018, including the Haymaker Acquisition.
Provision for Income Taxes
We recorded a provision for income taxes of $0.5 million for the six months ended June 30, 2019 as a result of a gross income allocation related to the Series A Preferred Units, which were issued in connection with the Haymaker Acquisition. Such costs are expected to continue throughout the remainder of 2019. Prior to the third quarter of 2018, we had no provision for or benefit from income taxes. Additionally, we assess the likelihood that our deferred tax assets will be recovered from future taxable income and, to the extent we believe that recovery is more likely than not, do not establish a valuation allowance. As of June 30, 2019, we recorded a full valuation allowance on our deferred tax assets. See Note 12—Income Taxes for further discussion.
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. On July 12, 2018, we entered into an amendment to the 2017 Credit Agreement, increasing commitments under the secured revolving credit facility from $50.0 million to $200.0 million, with an accordion feature permitting aggregate commitments under the secured revolving credit facility to be increased up to $500.0 million (subject to 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. In connection with the redetermination of the borrowing base in May 2019, total commitments under the Amended Credit Agreement were increased from $200.0 million to $225.0 million. As of August 2, 2019, we had an outstanding balance of $87.3 million under our secured revolving credit facility.
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 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, tax obligations, fixed charges and reserves for future operating or capital needs that the Board of Directors may determine is appropriate. We do not currently intend to 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 completed the Haymaker Acquisition by providing equity consideration for the transaction in the form of 10,000,000 common units and funding the cash consideration of the transaction through the net proceeds from the 2018 preferred offering and borrowings of $124.0 million under the Amended Credit Agreement, while the Dropdown was financed by providing equity consideration for the transaction in the form of 6,500,000 OpCo Common Units and an equal number of Class B Units, and the Phillips Acquisition was financed by providing equity consideration for the transaction in the form of 9,400,000 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.
Because the limited liability company agreement of the Operating Company and our partnership agreement each require the Operating Company and us to distribute an amount equal to all available cash generated by each respective entity each quarter, holders of OpCo Common Units and our unitholders have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of quarterly distributions, if any, will fluctuate based on variations in, among other factors, (i) the performance of the operators of our properties, (ii) earnings caused by, among other things, fluctuations in the price of oil, natural gas and NGLs, changes to working capital or capital expenditures, (iii) tax and certain contractual obligations and (iv) cash reserves deemed appropriate by the Board of Directors. Such variations in the amount of quarterly distributions may be significant and could result in no distribution being made for any particular quarter.
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 a material amount of 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 August 7, 2019, the Operating Company paid a quarterly cash distribution of $0.411452 to holders of OpCo Common Units. As to the Partnership, $0.021452 of the distribution corresponds to a tax payment made by us from cash reserves in the second quarter of 2019. The second quarter 2019 tax payment made by us was generated by a gross income allocation related to the Series A Preferred Units, which were issued in connection with the Haymaker acquisition. Under the limited liability company agreement of the Operating Company, we are not reimbursed by the Operating Company for federal income taxes paid by us.
On August 9, 2019, we will pay a
quarterly cash distribution on the Series A Preferred Units of $1.9 million for the quarter ended June 30, 2019.
On August 9, 2019, we will pay
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 approximately $23,414 for the quarter ended June 30, 2019
.
On July 26, 2019 the Board of Directors declared a quarterly cash distribution of $0.39 per common unit for the quarter ended June 30, 2019. The distribution will be paid on August 12, 2019 to common unitholders and OpCo common unitholders of record as of the close of business on August 5, 2019.
Cash Flows
The table below presents our cash flows for the periods indicated.
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Six Months Ended June 30,
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2019
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2018
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Cash Flow Data:
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Cash flows provided by operating activities
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$
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39,144,514
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$
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14,188,843
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Cash flows used in investing activities
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(1,405,311)
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(10,477,294)
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Cash flows used in financing activities
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(36,625,419)
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(1,002,412)
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Net increase in cash
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$
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1,113,784
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$
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2,709,137
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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 the change 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 six months ended June 30, 2019 were $39.1 million, an increase of $24.9 million compared to $14.2 million for the six months ended June 30, 2018. The increase in cash flows provided by operating activities was primarily attributable to the Haymaker Acquisition and Dropdown in the third and fourth quarters of 2018, respectively, and to the Phillips Acquisition in the first quarter of 2019.
Investing Activities
Cash flows used in investing activities for the six months ended June 30, 2019 decreased by $9.1 million compared to the six months ended June 30, 2018. For the six months ended June 30, 2019, we used $1.0 million to fund the Phillips Acquisition and $0.4 million to fund the remodel of office space. For the six months ended June 30, 2018 we used $21.0 million to fund the deposit on the Haymaker Acquisition, partially offset by $10.6 million in proceeds received from the sale of oil and natural gas properties.
Financing Activities
Cash flows used in financing activities were $36.6 million for the six months ended June 30, 2019, an increase of $35.6 million compared to $1.0 million for the six months ended June 30, 2018. Cash flows used in financing activities for the six months ended June 30, 2019 consists of $36.3 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. Cash flows used in financing activities for the six months ended June 30, 2018 consists of $13.1 million of distributions paid to common unitholders and $6.9 million of repayments on our secured revolving credit facility, offset by $19.0 million of additional borrowings under our secured revolving credit facility.
Capital Expenditures
During the six months ended June 30, 2019, we paid approximately $1.0 million in connection with the Phillips Acquisition. During the six months ended June 30, 2018, we paid a $21.0 million deposit in connection with the Haymaker Acquisition.
Indebtedness
In connection with our IPO, on January 11, 2017, we entered into the 2017 Credit Agreement with Frost Bank. In connection with the closing of the Haymaker Acquisition, we entered into the Credit Agreement Amendment. Under the Amended Credit Agreement, availability under our secured revolving credit facility will continue to equal the lesser of the aggregate maximum commitments of the lenders and the borrowing base. The secured revolving credit facility will mature on February 8, 2022.
Pursuant to the Credit Agreement Amendment, aggregate commitments under the Amended Credit Agreement were increased to $200.0 million providing for maximum availability of $200.0 million. The borrowing base will be redetermined semi-annually November 1 and May 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 order to include all assets acquired through the Phillips Acquisition in the borrowing base available under the Amended Credit Agreement, a borrowing base redetermination was completed in late May 2019. In connection with the redetermination, total commitments under the Amended Credit Agreement were increased from $200.0 million to $225.0 million and the borrowing base was increased from $200.0 million to $300.0 million. The Amended Credit Agreement permits aggregate commitments under the secured revolving credit facility to be increased up to $500.0 million, subject to the satisfaction of certain conditions and the procurement of additional commitments from new or existing lenders.
The Amended Credit Agreement 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 Amended Credit Agreement 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 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. As of June 30, 2019, we had outstanding borrowings of $87.3 million under the secured revolving credit facility and $212.7 million of available capacity.
For additional information on our Amended Credit Agreement, please read Note 7―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, 2018.
Contractual Obligations and Off‑Balance Sheet Arrangements
There have been no changes to our contractual obligations previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018. As of June 30, 2019, we did not have any off‑balance sheet arrangements other than operating leases.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to the oil, natural gas and NGL production of our operators. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our natural gas production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control. To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we entered into commodity derivative contracts to reduce our exposure to price volatility of oil and natural gas. The counterparty to the contracts is an unrelated third party.
Our commodity derivative contracts consist of fixed price swaps, under which we receive a fixed price for the contract and pay a floating market price to the counterparty over a specified period for a contracted volume.
Our oil fixed price swap transactions are settled based upon the average daily prices for the calendar month of the contract period, and our natural gas fixed price swap transactions are settled based upon the last day settlement of the first nearby month futures contract of the contract period. Settlement for oil derivative contracts occurs in the succeeding month and natural gas derivative contracts are settled in the production month.
Because we have not designated any of our derivative contracts as hedges for accounting purposes, changes in fair values of our derivative contracts will be recognized as gains and losses in current period earnings. As a result, our current period earnings may be significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value are principally measured based on future prices as of period-end compared to the contract price. See Note 4—Derivatives to the unaudited condensed consolidated financial statements for additional information regarding our commodity derivatives.
Counterparty and Customer Credit Risk
Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as we deem appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of June 30, 2019, we had one counterparty, which is also one of the lenders under our credit facility.
As an owner of mineral and royalty interests, we have no control over the volumes or method of sale of oil, natural gas and NGLs produced and sold from the underlying properties. It is believed that the loss of any single purchaser would not have a material adverse effect on our results of operations.
Interest Rate Risk
We will have exposure to changes in interest rates on our indebtedness. As of June 30, 2019, we had total borrowings outstanding under our secured revolving credit facility of $87.3 million. The impact of a 1% increase in the interest rate on this amount of debt would result in an increase in interest expense of approximately $0.9 million annually, assuming that our indebtedness remained constant throughout the year. We do not currently have any interest rate hedges in place.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a‑15(b) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of management of our general partner, including our general partner’s principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a‑15(e) and 15d‑15(e) under the Exchange Act) as of the end of the period covered by this Quarterly Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our general partner’s principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the U.S. Securities and Exchange Commission. Based upon that evaluation, our general partner’s principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2019.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting during the quarter ended June 30, 2019 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.