I
tem 2.
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Management’s Discussion and Analysis of Financial Condition and Results of Operations
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You should read the following discussion and analysis of our financial condition and results of operations in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, 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, 2015. This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”
Unless the context clearly indicates otherwise, references in this Quarterly Report on Form 10-Q to “BSM,” the “Partnership,” “we,” “our,” “us,” or similar terms for time periods prior to the IPO refer to Black Stone Minerals Company, L.P. and its subsidiaries, the predecessor for accounting purposes. For time periods subsequent to the IPO, these terms refer to Black Stone Minerals, L.P. and its subsidiaries.
Cautionary Note Regarding Forward-Looking Statements
Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. 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 any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
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·
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our ability to execute our business strategies;
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·
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the volatility of realized oil and natural gas prices;
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·
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the level of production on our properties;
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·
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regional supply and demand factors, delays, or interruptions of production;
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·
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our ability to replace our oil and natural gas reserves;
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·
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our ability to identify, complete, and integrate acquisitions;
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·
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general economic, business, or industry conditions;
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·
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competition in the oil and natural gas industry;
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·
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the ability of our operators to obtain capital or financing needed for development and exploration operations;
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·
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title defects in the properties in which we invest;
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·
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the availability or cost of rigs, equipment, raw materials, supplies, oilfield services, or personnel;
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·
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restrictions on the use of water;
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·
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the availability of transportation facilities;
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·
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the ability of our operators to comply with applicable governmental laws and regulations and to obtain permits and governmental approvals;
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·
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federal and state legislative and regulatory initiatives relating to hydraulic fracturing;
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·
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future operating results;
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·
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future cash flows and liquidity, including our ability to generate sufficient cash to pay quarterly distributions;
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·
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exploration and development drilling prospects, inventories, projects, and programs;
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·
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operating hazards faced by our operators;
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14
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·
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the ability of our operators to keep pace with technological advancements; and
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·
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certain factors discussed elsewhere in this filing.
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For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see “Risk Factors” in our Annual Report on Form 10-K.
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 one of the largest owners of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests. We maximize value through marketing our mineral assets for lease, creatively structuring terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working-interest basis in low-risk development-drilling opportunities on our interests. Our primary business objective is to grow our reserves, production, and cash generated from operations over the long term, while paying, to the extent practicable, a growing quarterly distribution to our unitholders.
On May 1, 2015 our common units began trading on the New York Stock Exchange under the symbol “BSM.” On May 6, 2015, we completed our initial public offering of 22,500,000 common units representing limited partner interests at a price to the public of $19.00 per common unit.
As of March 31, 2016, our mineral and royalty interests were located in 41 states and 61 onshore basins in the continental United States. These non-cost-bearing interests include ownership in approximately 45,000 producing wells. We also own non-operated working interests, largely on our mineral and royalty interests. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when the oil and natural gas production from the associated acreage is sold. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.
Recent Developments
Common Unit Repurchase Program
On March 4, 2016, the board of directors of our general partner authorized the repurchase of up to $50.0 million in common units over the next six months. The repurchase program authorizes us to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. All or a portion of any repurchases may be made under a Rule 10b5-1 plan, which would permit common units to be repurchased when we might otherwise be precluded from doing so under insider trading laws. The repurchase program does not obligate us to acquire any particular amount of common units and may be modified or suspended at any time and could be terminated prior to completion. We will periodically report the number of common units repurchased. The repurchase program will be funded from our cash on hand or available revolving credit facility. Any repurchased common units will be cancelled.
Acquisitions
On January 8, 2016, we acquired mineral and royalty interests in the Permian Basin for $10.0 million.
On April 21, 2016, we entered into a purchase and sale agreement with Freeport-McMoRan Oil and Gas and certain of its affiliates to acquire a diverse oil and natural gas mineral asset package for $102.0 million subject to certain closing adjustments. Closing is expected to be completed during the second quarter of 2016.
On May 9, 2016, we entered into a purchase and sale agreement to acquire an oil and natural gas mineral package for $35.0 million. Closing is expected to be completed during the second quarter of 2016.
15
Business Environment
The information presented below is designed to give a broad overview of the oil and natural gas business environment as it affects us.
Commodity Prices
Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. Recently, oil and natural gas prices have remained significantly below prices seen over the past five years as global concerns of long-term supply imbalances and slowing demand growth have weighed on prices. The West Texas Intermediate (“WTI”) spot price reached a low of $26.19 per Bbl on February 11, 2016, but rebounded to a recent high of $43.18 per Bbl on April 21, 2016. During the three months ended March 31, 2016, Henry Hub spot natural gas prices ranged from a low of $1.49 per MMBtu on March 4, 2016 to a high of $2.54 per MMBtu on January 11, 2016. The Henry Hub spot price settled at $1.88 per MMBtu on April 27, 2016. To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts.
The following table reflects commodity prices at the end of each quarter for the periods presented:
|
|
2016
|
|
|
2015
|
|
Benchmark Prices
|
|
First
Quarter
|
|
|
First
Quarter
|
|
WTI spot oil price ($/Bbl)
|
|
$
|
36.94
|
|
|
$
|
47.72
|
|
Henry Hub spot natural gas ($/MMBtu)
|
|
$
|
1.98
|
|
|
$
|
2.65
|
|
Source: EIA
Rig Count
As we are not an operator, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage. In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage.
The following table shows the rig count at the close of each quarter for the periods presented:
|
|
2016
|
|
|
2015
|
|
U.S. Rotary Rig Count
|
|
First
Quarter
|
|
|
First
Quarter
|
|
Oil
|
|
|
372
|
|
|
|
813
|
|
Natural gas
|
|
|
92
|
|
|
|
233
|
|
Other
|
|
|
—
|
|
|
|
2
|
|
Total
|
|
|
464
|
|
|
|
1,048
|
|
Source: Baker Hughes Incorporated
Natural Gas Storage
A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.
Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months.
16
The following table shows natural gas storage volumes by region at the close of each
quarter for the periods
presented:
|
|
2016
|
|
|
2015
|
|
Region
|
|
First
Quarter
|
|
|
First
Quarter
|
|
|
|
(Bcf)
|
|
East
|
|
|
439
|
|
|
|
255
|
|
Midwest
|
|
|
555
|
|
|
|
261
|
|
Mountain
|
|
|
147
|
|
|
|
114
|
|
Pacific
|
|
|
262
|
|
|
|
269
|
|
South Central
|
|
|
1,065
|
|
|
|
562
|
|
Total
|
|
|
2,468
|
|
|
|
1,461
|
|
Source: EIA
How We Evaluate Our Operations
We use a variety of operational and financial measures to assess our performance. Among the measures considered by management are the following:
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·
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volumes of oil and natural gas produced;
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|
·
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commodity prices including the effect of hedges; and
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|
·
|
EBITDA, Adjusted EBITDA, and cash available for distribution.
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Volumes of Oil and Natural Gas Produced
In order to assess and track the performance of our assets, we monitor and analyze our production volumes from the various basins and plays that comprise our extensive asset base. We also regularly compare projected volumes to actual reported volumes and investigate unexpected variations.
Commodity Prices
Factors Affecting the Sales Price of Oil and Natural Gas
The prices we receive for oil, natural gas, and natural gas liquids (“NGLs”) vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and NYMEX prices are referred to as differentials. All of our production is derived from properties located in the United States. As a result of our geographic diversification, we are not exposed to concentrated differential risks associated with any single play, trend, or basin.
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·
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Oil
. The substantial majority of our oil production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of our control. NYMEX light sweet crude oil, commonly referred to as WTI, is the prevailing domestic oil pricing index. The majority of our oil production is priced at the prevailing market price with the final realized price affected by both quality and location differentials.
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The chemical composition of crude oil plays an important role in its refining and subsequent sale as petroleum products. As a result, variations in chemical composition relative to the benchmark crude oil, usually WTI, will result in price adjustments, which are often referred to as quality differentials. The characteristics that most significantly affect quality differentials include the density of the oil, as characterized by its American Petroleum Institute (“API”) gravity, and the presence and concentration of impurities, such as sulfur.
Location differentials generally result from transportation costs based on the produced oil’s proximity to consuming and refining markets and major trading points.
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·
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Natural Gas.
The NYMEX price quoted at Henry Hub is a widely used benchmark for the pricing of natural gas in the United States. The actual volumetric prices realized from the sale of natural gas differ from the quoted NYMEX price as a result of quality and location differentials.
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17
Quality differentials result from the heating value of natural gas measured in Btus and the presence of impurities, such as hydrogen sulfide, carbon dioxide, and nitrogen. Natur
al gas containing ethane and heavier hydrocarbons has a higher Btu value and will realize a higher volumetric price than natural gas made up of predominantly methane, which has a lower Btu value. Natural gas with a higher concentration of impurities will r
ealize a lower volumetric price due to the presence of the impurities in the natural gas when sold or the cost of treating the natural gas to meet pipeline quality specifications.
Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.
Hedging
We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. We generally employ a “rolling hedge” strategy whereby we hedge a significant portion of our proved developed producing reserves 18 to 24 months into the future. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Since 2015, we have only entered into fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap strike price; conversely, we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap strike price. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue.
Our open oil and natural gas derivative contracts as of March 31, 2016 are detailed in Note 4 – Derivatives and Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q. Our credit agreement limits the extent to which we can hedge our future production. Under the terms of our credit agreement, we are able to hedge estimated production from our proved developed producing reserves based on our most recently completed reserve report provided to our lenders. We do not enter into derivative instruments for speculative purposes. Including derivative contracts entered into subsequent to March 31, 2016, we have hedged 97.3% and 43.7% of our available oil and condensate hedge volumes and 97.3% and 45.0% of our available natural gas hedge volumes for the remainder of 2016 and 2017, respectively.
Non-GAAP Financial Measures
EBITDA, Adjusted EBITDA, and cash available for distribution are supplemental non-GAAP financial measures used by our management and external users of our financial statements such as investors, research analysts, and others, to assess the financial performance of our assets and our ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis.
We define EBITDA as net income (loss) before interest expense, income taxes and depreciation, depletion, and amortization. We define Adjusted EBITDA as EBITDA adjusted for impairment of oil and natural gas properties, accretion of ARO, unrealized gains and losses on derivative instruments, and non-cash equity-based compensation. We define cash available for distribution as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, borrowings for capital expenditures, capital expenditures, cash interest expense, and distributions to noncontrolling interests and preferred unitholders.
EBITDA, Adjusted EBITDA, and cash available for distribution should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with GAAP as measures of our financial performance. EBITDA, Adjusted EBITDA, and cash available for distribution have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure. Our computation of EBITDA, Adjusted EBITDA, and cash available for distribution may differ from computations of similarly titled measures of other companies.
18
The following table presents a reconciliation of EBITDA, Adjusted EBITDA, and cash
available for distribution to net income, the most directly comparable GAAP financial measure, for the periods indicated.
|
|
Three Months Ended March 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
Net income
|
|
$
|
10,749
|
|
|
$
|
17,299
|
|
Adjustments to reconcile to Adjusted EBITDA:
|
|
|
|
|
|
|
|
|
Add:
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization
|
|
|
21,721
|
|
|
|
27,891
|
|
Interest expense
|
|
|
1,048
|
|
|
|
2,945
|
|
EBITDA
|
|
|
33,518
|
|
|
|
48,135
|
|
Add:
|
|
|
|
|
|
|
|
|
Impairment of oil and natural gas properties
|
|
|
6,096
|
|
|
|
13,467
|
|
Accretion of asset retirement obligations
|
|
|
274
|
|
|
|
271
|
|
Equity-based compensation
|
|
|
5,900
|
|
|
|
1,243
|
|
Unrealized loss on commodity derivative instruments
|
|
|
9,955
|
|
|
|
—
|
|
Less:
|
|
|
|
|
|
|
|
|
Unrealized gain on commodity derivative instruments
|
|
|
—
|
|
|
|
(2,197
|
)
|
Adjusted EBITDA
|
|
|
55,743
|
|
|
|
60,919
|
|
Adjustments to reconcile to cash generated from operations:
|
|
|
|
|
|
|
|
|
Add:
|
|
|
|
|
|
|
|
|
Borrowings/cash used to fund additions to and acquisitions of oil and natural gas properties
|
|
|
35,110
|
|
|
|
13,612
|
|
Incremental general and administrative related to initial public offering
|
|
|
—
|
|
|
|
227
|
|
Less:
|
|
|
|
|
|
|
|
|
Deferred revenue
|
|
|
(203
|
)
|
|
|
(104
|
)
|
Cash interest expense
|
|
|
(851
|
)
|
|
|
(2,704
|
)
|
Gain on sales of assets, net
|
|
|
(4,680
|
)
|
|
|
(7
|
)
|
Additions to oil and natural gas properties
|
|
|
(25,110
|
)
|
|
|
(13,612
|
)
|
Acquisitions of oil and natural gas properties
|
|
|
(10,000
|
)
|
|
|
—
|
|
Cash generated from operations
|
|
|
50,009
|
|
|
|
58,331
|
|
Less:
|
|
|
|
|
|
|
|
|
Cash paid to noncontrolling interests
|
|
|
(33
|
)
|
|
|
(52
|
)
|
Redeemable preferred unit distributions
|
|
|
(1,804
|
)
|
|
|
(2,909
|
)
|
Cash generated from operations available for distribution on common and subordinated units and reinvestment in our business
|
|
$
|
48,172
|
|
|
$
|
55,370
|
|
Factors Affecting the Comparability of Our Financial Results
Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, because we will incur higher general and administrative expenses than in prior periods as a result of operating as a publicly traded partnership. These incremental expenses include costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders; tax return and Schedule K-1 preparation and distribution fees; Sarbanes-Oxley Act compliance; New York Stock Exchange listing fees; independent registered public accounting firm fees; legal fees, investor-relations activities, registrar and transfer agent fees; director-and-officer insurance; and additional compensation. These direct, incremental general and administrative expenses are not included in our historical results of operations for periods prior to our IPO.
19
Results of Operations
The following table shows our production, pricing, revenues, and expenses for the periods presented:
|
|
Three Months Ended March 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
Variance
|
|
|
|
(Unaudited)
|
|
|
|
(Dollars in thousands, except for realized prices and per BOE data)
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbls)
1
|
|
|
886
|
|
|
|
827
|
|
|
|
59
|
|
|
|
7.1
|
%
|
Natural gas (MMcf)
1
|
|
|
11,250
|
|
|
|
10,785
|
|
|
|
465
|
|
|
|
4.3
|
%
|
Equivalents (MBoe)
|
|
|
2,761
|
|
|
|
2,625
|
|
|
|
|
|
|
|
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales
|
|
$
|
27,248
|
|
|
$
|
36,163
|
|
|
$
|
(8,915
|
)
|
|
|
(24.7
|
%)
|
Natural gas and natural gas liquids sales
|
|
|
25,112
|
|
|
|
31,640
|
|
|
|
(6,528
|
)
|
|
|
(20.6
|
%)
|
Gain on commodity derivative instruments
|
|
|
10,626
|
|
|
|
19,647
|
|
|
|
(9,021
|
)
|
|
|
(45.9
|
%)
|
Lease bonus and other income
|
|
|
1,395
|
|
|
|
3,611
|
|
|
|
(2,216
|
)
|
|
|
(61.4
|
%)
|
Total revenue
|
|
$
|
64,381
|
|
|
$
|
91,061
|
|
|
|
|
|
|
|
|
|
Realized prices:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate ($/Bbl)
|
|
$
|
30.75
|
|
|
$
|
43.73
|
|
|
$
|
(12.98
|
)
|
|
|
(29.7
|
%)
|
Natural gas ($/Mcf)
1
|
|
|
2.23
|
|
|
|
2.93
|
|
|
|
(0.70
|
)
|
|
|
(23.9
|
%)
|
Equivalents ($/Boe)
|
|
$
|
18.96
|
|
|
$
|
25.83
|
|
|
|
|
|
|
|
|
|
Operating expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
4,889
|
|
|
$
|
6,133
|
|
|
$
|
(1,244
|
)
|
|
|
(20.3
|
%)
|
Production costs and ad valorem taxes
|
|
|
7,062
|
|
|
|
8,256
|
|
|
|
(1,194
|
)
|
|
|
(14.5
|
%)
|
Exploration expense
|
|
|
8
|
|
|
|
39
|
|
|
|
(31
|
)
|
|
|
(79.5
|
%)
|
Depreciation, depletion, and amortization
|
|
|
21,721
|
|
|
|
27,891
|
|
|
|
(6,170
|
)
|
|
|
(22.1
|
%)
|
Impairment of oil and natural gas properties
|
|
|
6,096
|
|
|
|
13,467
|
|
|
|
(7,371
|
)
|
|
|
(54.7
|
%)
|
General and administrative
|
|
|
17,401
|
|
|
|
14,818
|
|
|
|
2,583
|
|
|
|
17.4
|
%
|
Other expense:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense
|
|
$
|
1,048
|
|
|
$
|
2,945
|
|
|
$
|
(1,897
|
)
|
|
|
(64.4
|
%)
|
Per Boe:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating expense
|
|
$
|
1.77
|
|
|
$
|
2.34
|
|
|
$
|
(0.57
|
)
|
|
|
(24.4
|
%)
|
Lease operating expense (per working interest Boe)
|
|
|
5.37
|
|
|
|
6.98
|
|
|
|
(1.61
|
)
|
|
|
(23.1
|
%)
|
Production costs and ad valorem taxes
|
|
|
2.56
|
|
|
|
3.15
|
|
|
|
(0.59
|
)
|
|
|
(18.7
|
%)
|
Depreciation, depletion, and amortization
|
|
|
7.87
|
|
|
|
10.63
|
|
|
|
(2.76
|
)
|
|
|
(26.0
|
%)
|
General and administrative
|
|
|
6.30
|
|
|
|
5.64
|
|
|
|
0.66
|
|
|
|
11.7
|
%
|
1
|
As a mineral-and-royalty-interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.
|
Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015
Revenue
Total revenue for the quarter ended March 31, 2016 decreased compared to the quarter ended March 31, 2015. Production for the quarter ended March 31, 2016 averaged 30.3 MBoe per day, an increase of 1.2 MBoe per day compared to the corresponding period in 2015. The decrease in total revenues is primarily due to lower realized commodity prices, the impact of which totaled $19.4 million, a decrease in gains on commodity derivative instruments, and lower lease bonus as compared to the corresponding period in 2015. Higher production volumes partially offset the decrease in realized prices.
20
Oil and condensate sales.
Oil and condensate sales during the period were
lower
than the
first quarter of 2015
primarily due to
lower
realized prices.
Our total oil and condensate production was higher than the
first quarter of 2015
, but the increased production was more than offs
et by
the
decline in realized prices.
Our mineral-and-royalty-interest oil
and condensate
volumes accounted for
78.5%
and
76.1%
of total oil and condensate volumes for the
quarters ended
March 31, 2016
and
2015
, respectively.
Our
mineral-and-royalty-intere
st oil
and condensate
volumes
increased
10.6%
in
the
first quarter of 2016
relative to
the
corresponding period in 2015
,
primarily
driven
by production increases from new wells
in the Bakken/Three Forks
,
Eagle Ford
, and Wolfcamp
plays. Our working-interest
oil and condensate volumes
decreased
by
3.9%
during the
first quarter of 2016
versus the same period in
2015
to
190
MBbls
primarily due to
normal production declines
.
Natural gas and natural gas liquids sales.
Natural gas and NGL sales decreased for the quarter ended March 31, 2016 as compared to the same period for 2015. A decline in the realized natural gas and NGL prices for the quarter ended March 31, 2016 versus the corresponding period in 2015 was primarily responsible for the decline in our natural gas and NGL revenues. Mineral-and-royalty-interest production accounted for 61.6% and 62.1% of our natural gas volumes for the quarters ended March 31, 2016 and 2015, respectively.
Gain on commodity derivative instruments.
During the first quarter of 2016, we recognized $2.9 million of gains from oil commodity contracts, which included cash received of $12.6 million, compared to recognized gains of $13.0 million in the same period of 2015. During the first quarter of 2016, we recognized $7.7 million of gains from natural gas commodity contracts, which included cash received of $8.0 million, compared to recognized gains of $6.6 million in the same period of 2015.
Lease bonus and other income.
When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. In the first quarter of 2016, we successfully closed several lease transactions in the Bone Springs/Wolfcamp, Utica, and Haynesville/Bossier plays; however, overall lease bonus for the quarter ended March 31, 2016 was lower than the same period of 2015.
Operating Expense
Lease operating expense
. Lease operating expense includes normally recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended March 31, 2016 as compared to the same period in 2015, primarily due to lower costs associated with workover and other service-related costs.
Production costs and ad valorem taxes
. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended March 31, 2016, production costs and ad valorem taxes decreased from the quarter ended March 31, 2015, generally as a result of lower realized prices and estimated mineral reserve valuations.
Depreciation, depletion, and amortization
. Depletion is an estimate of the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon the mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depletion rates were updated prospectively as of December 31, 2015. Depreciation, depletion, and amortization decreased for the quarter ended March 31, 2016 as compared to the same period in 2015, primarily due to the impact of a reduced cost basis resulting from impairment charges recorded during the prior twelve months that were partially offset by higher production rates.
Impairment of oil and natural gas properties
. Individual categories of oil and natural gas properties are assessed periodically to determine if the net book value for these properties has been impaired. Management periodically conducts an in-depth evaluation of the cost of property acquisitions, successful exploratory wells, development activity, unproved leasehold, and mineral interests to identify impairments. Impairments totaled $6.1 million for the quarter ended March 31, 2016 primarily due to changes in reserve values resulting from declines in future expected realizable net cash flows as a result of lower commodity prices as of March 31, 2016. There were no impairments for the first quarter of 2015.
General and administrative
. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended March 31, 2016, general and administrative expenses increased as compared to the same period in 2015. In 2016, costs attributable to our long-term incentive plan were $2.0 million higher than in the corresponding prior period due to the recognition of
21
expense related to
incentive compensation awards granted subsequent to our IPO. We also incurred an additional $
0
.
7
million
of
legal and professional
expense for the
three months ended March 31, 2016
as compared to the same period in 2015
.
Interest expense
. Interest expense decreased due to lower borrowings under our credit facility. Outstanding borrowings during the first quarter of 2016 were lower than the first quarter of 2015 due to mid-year 2015 repayments towards our credit facility using proceeds received from our IPO.
Liquidity and Capital Resources
Overview
Our primary sources of liquidity are cash generated from operations, borrowings under our credit facility, and proceeds from any future issuances of equity and debt. Our primary uses of cash are for distributions to our unitholders and for investing in our business, specifically the acquisition of mineral and royalty interests and our selective participation on a nonoperated-working-interest basis in the development of our oil and natural gas properties.
The board of directors of our general partner has adopted a policy pursuant to which distributions equal in amount to the applicable minimum quarterly distribution will be paid on each common and subordinated unit for each quarter to the extent we have sufficient cash generated from our operations after establishment of cash reserves, if any, and after we have made the required distributions to the holders of our outstanding preferred units. However, we do not have a legal or contractual obligation to pay distributions quarterly or on any other basis, at the applicable minimum quarterly distribution rate or at any other rate, and there is no guarantee that we will pay distributions to our unitholders in any quarter. Our minimum quarterly distribution provides the common unitholders a specified priority right to distributions over the subordinated unitholders. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time.
We intend to finance our future acquisitions and working-interest capital needs with cash generated from operations, borrowings from our credit facility, and proceeds from any future issuances of equity and debt. Replacement capital expenditures are expenditures necessary to replace our existing oil and natural gas reserves or otherwise maintain our asset base over the long-term. Like a number of other master limited partnerships, we are required by our partnership agreement to retain cash from our operations in an amount equal to our estimated replacement capital requirements. The board of directors of our general partner is responsible for establishing the amount of our estimated replacement capital expenditures.
Cash Flows
The following table shows our cash flows for the periods presented:
|
|
Three Months Ended March 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
|
(Unaudited)
|
|
|
|
(In thousands)
|
|
Cash flows provided by operating activities
|
|
$
|
25,906
|
|
|
$
|
74,359
|
|
Cash flows used in investing activities
|
|
|
(35,082
|
)
|
|
|
(13,206
|
)
|
Cash flows provided by (used in) financing activities
|
|
|
956
|
|
|
|
(67,588
|
)
|
Three Months Ended March 31, 2016 Compared to Three Months Ended March 31, 2015
Operating Activities
. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, lease-bonus revenue, and operating expenses. Our cash flows from operations decreased from $74.4 million for the three months ended March 31, 2015 to $25.9 million for the three months ended March 31, 2016. The decrease was primarily due to lower cash collections of $44.1 million related to lower oil and natural gas sales and lower lease bonus as compared to the corresponding period in 2015. In 2016, an increase of $3.1 million in operating cash flows related to the settlement of commodity derivative instruments partially offset the overall decrease in operating cash flows.
Investing Activities
. Net cash used in investing activities increased by $21.9 million in the first three months of 2016 as compared to the corresponding period in 2015 due to an acquisition of mineral and royalty interests in the Permian Basin during the first three months of 2016 and increased capital expenditures for our working interests.
22
Financing Activities
. For the
three months ended March 31, 2016
,
we generated cash from financing activities as we
increased our borrowings under our senior line of credit and
l
owered distributions as compared to the corresponding period in 2015.
Capital Expenditures
At the beginning of each calendar year, we establish a capital budget and then monitor it throughout the year. Our capital budget is created based upon our estimate of internally-generated cash flows and the ability to borrow and raise additional capital. Actual capital expenditure levels will vary, in part, based on actual cash generated, the economics of wells proposed by our operators for our participation, and the successful closing of acquisitions. The timing, size, and nature of acquisitions are unpredictable.
Our 2016 capital budget for drilling expenditures is approximately $60.0 million. Approximately 95% of our drilling capital budget will be spent in the Haynesville/Bossier and Bakken/Three Forks plays, with the remainder spent in various plays including the Wolfcamp and Wilcox plays. During the three months ended March 31, 2016, we incurred $15.6 million related to drilling and completion costs and $0.4 million related to prospect leasehold acreage, primarily in the aforementioned plays. We also spent $10.0 million on a mineral and royalty interest acquisition in the Permian Basin.
Credit Facility
On January 23, 2015, we amended and restated our $1.0 billion senior secured revolving credit agreement. Under this third amended and restated credit facility, the commitment of the lenders equals the lesser of the aggregate maximum credit amounts of the lenders and the borrowing base, which is determined based on the lenders’ estimated value of our oil and natural gas properties. On October 28, 2015, the third amended and restated credit facility was further amended to extend the term of the agreement from February 3, 2017 to February 4, 2019. Borrowings under the third amended and restated credit facility may be used for the acquisition of properties, cash distributions, and other general corporate purposes. The borrowing base was $550.0 million at March 31, 2016. Our regular, semi-annual borrowing base redetermination process resulted in a decrease of the borrowing base from $550.0 million to $450.0 million, effective April 15, 2016. Our next borrowing base redetermination is scheduled for October 2016. As of March 31, 2016, we had outstanding borrowings of $116.0 million at a weighted-average interest rate of 2.12%.
The borrowing base under the third amended and restated credit agreement is redetermined semi-annually, typically on or around April 1 and October 1 of each year, by the administrative agent, taking into consideration the estimated loan value of our oil and gas properties consistent with the administrative agent’s normal oil and gas lending criteria. The administrative agent’s proposed redetermined borrowing base must be approved by all lenders to increase our existing borrowing base, and by two-thirds of the lenders to maintain or decrease our existing borrowing base. In addition, we and the lenders (at the election of two-thirds of the lenders) each have discretion once in between scheduled redeterminations, to have the borrowing base redetermined.
Outstanding borrowings under the third amended and restated credit facility bear interest at a floating rate elected by us equal to an alternative base rate (which is equal to the greatest of the Prime rate, the Federal Funds effective rate plus 0.5%, or 1-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of borrowings outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, depending on the amount of the borrowings outstanding in relation to the borrowing base. Principal may be optionally repaid from time to time without premium or penalty, other than customary LIBOR breakage, and is required to be paid (a) if the amount outstanding exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise, in some cases subject to a cure period or (b) at the maturity date. The third amended and restated credit facility is secured by liens on substantially all of our properties.
The third amended and restated credit agreement contains various affirmative, negative, and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, dividends and distributions, transactions with affiliates and entering into certain swap agreements, as well as require the maintenance of certain financial ratios. The third amended and restated credit agreement contains two financial covenants: total debt to EBITDAX of 3.5:1.0 or less; and a modified current ratio of 1.0:1.0 or greater. Distributions are not permitted if there is a default under the third amended and restated credit agreement (including due to a failure to satisfy one of the financial covenants) or during any time that our borrowing base is lower than the loans outstanding under the third amended and restated credit facility. The lenders have the right to accelerate all of the indebtedness under the third amended and restated credit facility upon the occurrence and during the continuance of any event of default, and the third amended and restated credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy, and change of control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. As of March 31, 2016, we were in compliance with all debt covenants.
23
Contractual Obligations
As of March 31, 2016, there have been no material changes to our contractual obligations previously disclosed in our 2015 Annual Report on Form 10-K.
Off-Balance Sheet Arrangements
As of March 31, 2016, we did not have any material off-balance sheet arrangements.
Critical Accounting Policies and Related Estimates
As of March 31, 2016, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2015 Annual Report on Form 10-K.
New and Revised Financial Accounting Standards
The effects of new accounting pronouncements are discussed in the notes to the unaudited consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q.
24