ROSEHILL RESOURCES INC. The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside of our control. Such statements speak only as of the date of this report. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in "Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements," all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.
Overview
We are an independent oil and natural gas company focused on the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in thePermian Basin . Our assets are concentrated in theDelaware Basin , a sub-basin of thePermian Basin . We have drilling locations in ten distinct formations in theDelaware Basin in:Brushy Canyon , Upper Avalon,Lower Avalon , 2ndBone Spring Shale , 2nd Bone Spring Sand, 3rd Bone Spring Sand, 3rdBone Spring Shale , Wolfcamp A (X/Y), Lower Wolfcamp A and Wolfcamp B, and our goal is to build a premier development and acquisition company focused on horizontal drilling in theDelaware Basin . We have no direct operations and no significant assets other than our ownership interest in Rosehill Operating, an entity of which we act as the sole managing member and of whose common units we currently own approximately 64.5% (or 70.6% assuming the conversion of Rosehill Operating Series A Preferred Units into Rosehill Operating Common Units).
Market Conditions
The oil and natural gas industry is cyclical and commodity prices are highly volatile. Oil prices have recently reached multi-year lows. For example, for the three years endedDecember 31, 2017 , 2018, and 2019, WTI spot prices for crude oil had a low of$42.48 per barrel duringJune 2017 and a high of$77.41 per barrel duringJune 2018 , while the average in 2019 was approximately$56.98 per barrel. As ofMarch 27, 2020 , WTI spot prices for crude oil were$21.84 per barrel. For the three years endedDecember 31, 2017 , 2018, and 2019,Henry Hub spot prices for natural gas had a low of$1.75 per MMBtu duringDecember 2019 and a high of$6.24 per MMBtu duringJanuary 2018 , while the average in 2019 was approximately$2.56 per MMBtu. As ofMarch 27, 2020 ,Henry Hub spot prices for natural gas were$1.67 per MMBtu. It is likely that commodity prices will continue to fluctuate and possibly further, decline due to global supply and demand, inventory supply levels, weather conditions, geopolitical events, the COVID-19 pandemic and other factors. Due to these and other unprecedented factors, commodity prices cannot be accurately predicted.
On
Realized Prices
Our revenue, profitability and future growth are highly dependent on the prices
we receive for our oil and natural gas production, as well as NGLs that are
extracted from our natural gas during processing. The following table presents
our average realized commodity prices before the effects of commodity derivative
settlements:
Year Ended December 31,
2019 2018 2017
Crude oil (per Bbl) $ 52.99 $ 55.27 $ 48.46
Natural gas (per Mcf) $ 0.39 $ 1.80 $ 2.65
NGLs (per Bbl) $ 11.71 $ 23.07 $ 18.31
Current 2020 forward pricing will likely result in impairments of our properties
during the first quarter of 2020 and may materially and adversely affect our
future business, financial condition, results of operations, operating cash
flows, liquidity, or ability to finance planned capital expenditures. Lower oil,
natural gas and NGL prices may also reduce the borrowing base under our Amended
and Restated Credit Agreement, which may be redetermined at the discretion of
the lenders and is based on the
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collateral value of our proved reserves that have been mortgaged to the lenders.
The next redetermination is scheduled for April 2020 . Alternatively, higher oil,
natural gas and NGL prices may result in significant losses being incurred on
our commodity derivatives, which could cause us to experience net losses when
oil and natural gas prices rise. For 2019, we received low prices for our
natural gas due to lower NYMEX gas prices, wider gas price differentials and due
to the adoption of ASC 606. Because we receive revenue from NGLs, we have and
may continue to produce and sell our natural gas at a low, or negative, realized
sales price. The widening gas price differentials were due to pipeline takeaway
capacity constraints in the Permian Basin , but the industry expects new
pipelines to come online to help with this constraint and help provide relief to
the widening gas price differentials.
A 10% change in our realized oil, natural gas and NGL prices would have changed revenue by the following amounts for the periods indicated:
Year Ended December 31,
2019 2018 2017
(In thousands)
Oil sales $ 28,671 $ 27,154 $ 6,160
Natural gas sales 249 939 717
NGL sales 1,308 2,094 747
Total revenues $ 30,228 $ 30,187 $ 7,624
The prices we receive for our products are based on benchmark prices and are
adjusted for quality, energy content, transportation fees and regional price
differentials. See "Results of Operations" below for an analysis of the impact
changes in realized prices had on our revenues.
Sources of Our Revenues
Our revenues are derived from the sale of our oil and natural gas production, as
well as the sale of NGLs that are extracted from our natural gas during
processing. The following table shows the percentage each component contributed
to total revenue:
Year Ended December 31,
Commodity Revenues (1): 2019 2018 2017
Oil sales 95 % 90 % 81 %
Natural gas sales 1 3 9
NGL sales 4 7 10
100 % 100 % 100 %
(1) The percentages exclude the effects of commodity derivatives.
Gateway , a related party to us, accounted for none of our revenues for the year endedDecember 31, 2019 and approximately 60% and 80% of total revenues for the years endedDecember 31, 2018 and 2017, respectively.
Derivative Activity
To achieve a more predictable cash flow and reduce exposure to adverse
fluctuations in commodity prices, we have historically used commodity derivative
instruments, such as swaps, two-way costless collars and three-way costless
collars, to hedge price risk associated with a portion of our anticipated oil,
natural gas and NGL production. By removing a significant portion of the price
volatility associated with our production, we will mitigate, but not eliminate,
the potential negative effects of declines in benchmark oil, natural gas and NGL
prices on our cash flow from operations for those periods. However, for a
portion of our current positions, hedging activity may also reduce our ability
to benefit from increases in oil, natural gas and NGL prices. We will sustain
losses to the extent our commodity derivative contract prices are lower than
market prices and, conversely, we will sustain gains to the extent our commodity
derivative contract prices are higher than market prices. In certain
circumstances, where we have unrealized gains in our commodity derivatives
portfolio, we may choose to restructure existing commodity derivative contracts
or enter into new transactions to modify the terms of current contracts in order
to realize the current value of our existing positions.
57
--------------------------------------------------------------------------------A description of our derivative financial instruments is provided below:
• A swap has an established fixed price. When the settlement price is below the
fixed price, the counterparty pays us an amount equal to the difference
between the settlement price and the fixed price multiplied by the hedged
contract volume. When the settlement price is above the fixed price, we pay
our counterparty an amount equal to the difference between the settlement
price and the fixed price multiplied by the hedged contract value.
• A two-way costless collar is an arrangement that contains a fixed floor price
(purchased put option) and a fixed ceiling price (sold call option) based on
an index price which, in aggregate, have no net cost. At the contract
settlement date, (1) if the index price is higher than the ceiling price, we
pay the counterparty the difference between the index price and ceiling
price, (2) if the index price is between the floor and ceiling prices, no
payments are due from either party and (3) if the index price is below the
floor price, we will receive the difference between the floor price and the
index price.
• A three-way costless collar is an arrangement that contains a purchased put
option, a sold call option and a sold put option based on an index price
which, in aggregate, have no net cost. At the contract settlement date, (1)
if the index price is higher than the sold call strike price, we pay the
counterparty the difference between the index price and sold call strike
price, (2) if the index price is between the purchased put strike price and
the sold call strike price, no payments are due from either party, (3) if the
index price is between the sold put strike price and the purchased put strike
price, we will receive the difference between the purchased put strike price
and the index price and (4) if the index price is below the sold put strike
price, the Company will receive the difference between the purchased put
strike price and the sold put strike price.
• A purchased put option has an established floor price. The buyer of the put
option pays the seller a premium to enter into the put option. When the
settlement price is below the floor price, the seller pays the buyer an
amount equal to the difference between the settlement price and the strike
price multiplied by the hedged contract volume. When the settlement price is
above the floor price, the put option expires worthless.
• A sold call option has an established ceiling price. The buyer of the call
option pays the seller a premium to enter into the call option. When the
settlement price is above the ceiling price, the seller pays the buyer an
amount equal to the difference between the settlement price and the strike
price multiplied by the hedged contract volume. When the settlement price is
below the ceiling price, the call option expires worthless.
58-------------------------------------------------------------------------------- We had a net current asset of$6.5 million and a net non-current asset of$32.7 million related to the following open commodity derivative instrument positions as ofDecember 31, 2019 : 2020 2021 2022 Commodity derivative swaps Oil: Notional volume (Bbls) (1)(2) 1,000,000 - - Weighted average fixed price ($/Bbl)$ 67.69 $ - $ - Natural gas: Notional volume (MMBtu) 1,970,368
1,615,792 1,276,142
Weighted average fixed price ($/MMbtu)
Commodity derivative three-way collars Oil: Notional volume (Bbls) 3,294,000
4,200,000 2,000,000
Weighted average ceiling price ($/Bbl)
Weighted average floor price ($/Bbl)$ 57.50 $
54.49
Weighted average sold put option price ($/Bbl)$ 47.50 $ 45.51 $ 45.00 Crude oil basis swaps Midland / Cushing: Notional volume (Bbls) 5,254,000 4,200,000 2,100,000 Weighted average fixed price ($/Bbl)$ (0.83 ) $ 0.49 $ 0.54 Argus WTI roll: Notional volume (Bbls) 665,650 - - Weighted average fixed price ($/Bbl)$ 0.40 $ - $ - NYMEX WTI roll: Notional volume (Bbls) 2,791,102 - - Weighted average fixed price ($/Bbl)$ 0.42 $ - $ - Natural gas basis swaps EP Permian: Notional volume (MMBtu) 2,096,160 - -
Weighted average fixed price ($/MMBtu)
(1) During the second quarter of 2019, the Company entered into commodity
derivative swaps where it bought 2,160,000 barrels of crude oil at a weighted
average fixed price of
for the year ended
crude oil at a weighted average fixed price of
locking in a gain of approximately
recognize in 2021 when the swaps settle.
(2) During the second quarter of 2019, the Company entered into commodity
derivative swaps where it bought 1,100,000 barrels of crude oil at a weighted
average fixed price of
for the year ended
crude oil at a weighted average fixed price of
locking in a gain of approximately
recognize in 2022 when the swaps settle.
59-------------------------------------------------------------------------------- If there are no changes in the forward curve market prices as ofDecember 31, 2019 , we would incur a realized gain of$6.5 million in 2020, a realized gain of$22.1 million in 2021 and a realized gain of$10.6 million in 2022 related to our commodity derivatives. See Note 6 - Derivative Instruments in the consolidated financial statements under Part II, Item 8 of this Annual Report on Form 10-K for additional information about our derivatives. The forward curve market prices have declined sinceDecember 31, 2019 . Our commodity derivative portfolio had a mark-to-market net asset value of approximately$141.6 million as ofMarch 31, 2020 . We utilize interest rate swaps to reduce our exposure to adverse fluctuations in LIBO rates on a portion of our revolving credit facility outstanding borrowings. The gains and losses on our interest rate swaps are recognized in interest expense. Entering into interest rate swaps allows us to mitigate, but not eliminate, the negative effects of increases in the LIBO rate, but reduces our ability to benefit from any decreases in the LIBO rate. InJuly 2019 , we entered into interest rate swaps that extend throughAugust 2022 on a notional amount of$150.0 million of our outstanding borrowings under our revolving credit facility at an average fixed rate of 1.721%. We had a net current liability of$0.2 million and a net non-current liability of$0.5 million related to our interest rate swaps as ofDecember 31, 2019 .
Income Taxes
Rosehill Operating is a limited liability company that is treated as a partnership forU.S. federal income tax purposes and is generally not subject toU.S. federal income tax at the entity level.Rosehill Resources is a C corporation and is subject toU.S. federal, state and local income taxes. Any taxable income or loss generated by Rosehill Operating is passed through to and included inRosehill Resources and the noncontrolling interest taxable income or loss. On a consolidated basis, our effective tax rate will differ from the enacted statutory rate of 21% and will fluctuate from period to period primarily due to the allocation of profits and losses toRosehill Resources and the noncontrolling interest holder in accordance with the LLC Agreement and the impact of state income taxes. We periodically assesses whether it is more likely than not that we will generate sufficient taxable income to realize our deferred tax assets, including NOL carry forwards or carry backs. A valuation allowance for deferred tax assets is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. As ofDecember 31, 2019 , we had no valuation allowance because we believed it was more likely than not that our deferred tax assets would be realized prior to their expiration. Due to the uncertainty of the market and the significant decrease in oil prices that occurred subsequent toDecember 31, 2019 , as detailed in Note 3 - Subsequent Events and Liquidity, we expect to record a full valuation allowance to offset our net deferred tax assets for the first quarter of 2020.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
• production volumes;
• Adjusted EBITDAX as defined under "Non-GAAP Financial Measure"; and
• operating expenses on a per barrel of oil equivalent ("Boe"), as discussed in
"Results of Operations."
Production Results
The following table presents production volumes for our properties for the
periods indicated:
Year Ended December 31,
2019 2018 2017
Oil (MBbls) 5,411 4,913 1,271
Natural gas (MMcf) 6,352 5,231 2,709
NGLs (MBbls) 1,117 908 408
Total (MBoe) 7,587 6,693 2,131Average daily net production (Boe/d) 20,786 18,337 5,838
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As reservoir pressures decline, production from a given well or formation
decreases. Growth in our future production and reserves will depend on our
ability to continue to add proved reserves in excess of our production.
Accordingly, we plan to maintain our focus on adding reserves through drilling
as well as acquisitions; however, in March 2020 , we announced that we have
suspended all drilling and completion activity for 2020 due to the decline in
commodity prices in March 2020 . Our ability to add reserves through development
projects and acquisitions is dependent on many factors, including our ability to
borrow or raise capital, obtain regulatory approvals, procure contract drilling
rigs and personnel and successfully identify and consummate acquisitions.
Non-GAAP Financial Measure
Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by our management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before interest expense, net, income tax expense (benefit), DD&A, accretion, impairment of oil and natural gas properties, exploration costs, stock-settled stock-based compensation, (gains) losses on commodity derivatives excluding net cash receipts (payments) on settled commodity derivatives, one-time costs incurred in connection with the Transaction, (gains) losses from the sale of property and equipment, (gains) losses on asset retirement obligation settlements and other non-cash operating items. Adjusted EBITDAX is not a measure of net income (loss) as determined byUnited States generally accepted accounting principles ("U.S. GAAP"). Management believes Adjusted EBITDAX is useful because it allows us to more effectively evaluate operating performance and compare our results of operations from period to period against our peers without regard to financing methods or capital structure. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDAX 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. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income (loss) as determined in accordance withU.S. GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX 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 the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our presentation of Adjusted EBITDAX should not be construed as an inference that its results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies.
We have provided below a reconciliation of Adjusted EBITDAX to net income
(loss), the most directly comparable
Year Ended December 31,
2019 2018 2017
(In thousands)
Net income (loss) $ (30,088 ) $ 117,962 $ (11,948 )
Interest expense, net 25,228 19,489 2,532
Income tax expense (benefit) 2,143 18,162 1,690
Depreciation, depletion, amortization and accretion 137,937 141,815 36,091
Impairment of oil and natural gas properties - - 1,061
Unrealized (gain) loss on commodity derivatives, net 50,664 (108,086 ) 16,553
Transaction costs - - 2,618
Stock settled stock-based compensation 6,124 6,477 1,245
Exploration costs 15,917 4,374 1,747
(Gain) loss on disposition of property and equipment (11,117 ) 499 (4,995 )
Other non-cash (income) expense, net (109 ) 3,667 172
Adjusted EBITDAX $ 196,699 $ 204,359 $ 46,766
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Results of Operations
Year Ended
Oil, Natural Gas and NGL Sales Revenues. The following table provides the components of our revenues for the periods indicated, as well as each period's respective average sales prices and volumes:
Year Ended December 31,
2019 2018 Change Change %
(Dollars in thousands, except price data)
Revenues:
Oil sales $ 286,710 $ 271,539 $ 15,171 6 %
Natural gas sales 2,489 9,392 (6,903 ) (73 )
NGL sales 13,084 20,944 (7,860 ) (38 )
Total revenues $ 302,283 $ 301,875 $ 408 - %
Average sales price (1):
Oil (per Bbl) $ 52.99 $ 55.27 $ (2.28 ) (4 )%
Natural gas (per Mcf) 0.39 1.80 (1.41 ) (78 )
NGLs (per Bbl) 11.71 23.07 (11.36 ) (49 )
Total (per Boe) $ 39.84 $ 45.10 $ (5.26 ) (12 )%
Total, including effects of gain (loss)
on settled
commodity derivatives, net (per Boe) $ 37.91
$ (4.88 ) (11 )% Net production: Oil (MBbls) 5,411 4,913 498 10 % Natural gas (MMcf) 6,352 5,231 1,121 21 NGLs (MBbls) 1,117 908 209 23 Total (MBoe) 7,587 6,693 894 13 % Average daily net production volume: Oil (Bbls/d) 14,825 13,460 1,365 10 % Natural gas (Mcf/d) 17,403 14,332 3,071 21 NGLs (Bbls/d) 3,060 2,488 572 23 Total (Boe/d) 20,786 18,337 2,449 13 %
(1) Excluding the effects of settled and unsettled commodity derivative
transactions unless noted otherwise.
The increase in total revenues was due to an increase in sales volume, partially offset by a decrease in average sales price. The increase in sales volume increased total revenues by approximately$34.3 million , partially offset by a decrease of approximately$33.9 million related to a decrease in average sales price. The increase in sales volumes is primarily due to new wells coming online without any significant offsetting decrease in production from natural well production declines. The decrease in average sales price is due to (i) lower price indices for crude oil and NGLs, (ii) less favorable pricing differentials for natural gas and (ii) more gathering and transportation costs being netted against revenue as a result of adopting ASU 2014-09, Revenue from Contracts with Customers (Topic 606) ("ASC 606") onJanuary 1, 2019 . The adoption of ASC 606 resulted in the Company recording less total revenue of approximately$2.5 million . There was no impact on our net income; the impact was a change in presentation between revenues and gathering and transportation expense based on where control of our oil, natural gas and NGL production transfers to the customer. The change did not significantly impact our reported average sales for each product. See Note 18 - Revenue from Contracts with Customers of this Annual Report on Form 10-K in Part II, Item 8 for more detail on our revenue recognition under ASC 606. 62 -------------------------------------------------------------------------------- Operating expenses. The following table summarizes our operating expenses for the periods indicated: Year Ended December 31, 2019 2018 Change Change % (In thousands, except per Boe data) Operating expenses: Lease operating expenses$ 37,348 $ 37,881 $ (533 ) (1 )% Production and ad valorem taxes 17,432 15,635 1,797 11 Gathering and transportation 5,756 4,939 817 17 Depreciation, depletion, amortization and accretion 137,937 141,815 (3,878 ) (3 ) Exploration costs 15,917 4,374 11,543 264 General and administrative, excluding stock-based compensation 29,428 23,947 5,481 23 Stock-based compensation 6,301 6,522 (221 ) (3 ) (Gain) Loss on disposition of property and equipment (11,117 ) 499 (11,616 ) (2,328 ) Total operating expenses$ 239,002 $ 235,612 $ 3,390 1 % Operating expenses per Boe: Lease operating expenses $ 4.92$ 5.66 $ (0.74 ) (13 )% Production and ad valorem taxes 2.30 2.34 (0.04 ) (2 ) Gathering and transportation 0.76 0.74 0.02 3 Depreciation, depletion, amortization and accretion 18.18 21.19 (3.01 ) (14 ) Exploration costs 2.10 0.65 1.45 223 General and administrative, excluding stock-based compensation 3.88 3.58 0.30 8 Stock-based compensation 0.83 0.97 (0.14 ) (14 ) (Gain) Loss on disposition of property and equipment (1.47 ) 0.07 (1.54 ) (2,200 ) Total operating expenses per Boe $ 31.50$ 35.20
Lease operating expenses ("LOE"). LOE for the year ended December 31, 2019
decreased compared to the year ended December 31, 2018 by approximately $5.6
million due to a decrease in LOE rate partially offset by an increase of
approximately $5.1 million due to an increase in sales volume. The decrease in
our LOE rate is due to a lower level of water disposal costs now that we have
facilities in place to handle produced waste water. The increase in sales
volumes is primarily due to new wells coming online without any significant
offsetting decrease in production from natural well production declines.
Production and ad valorem taxes. Production taxes for the year ended December
31, 2019 decreased by $0.5 million compared to the year ended December 31, 2018
and ad valorem taxes increased by $2.3 million for the year ended December 31,
2019 compared to the year ended December 31, 2018 . Production taxes are
primarily based on the market value of our wellhead production and the increase
was primarily due to a decrease in total revenues. Our total revenues increased
by less than 1% and production taxes decreased by 3%. Production taxes as a
percentage of total revenues were 4.6% and 4.8% for the years ended December 31,
2019 and 2018, respectively. The increase in ad valorem taxes was due to an
increase in producing wells.
Gathering and transportation ("G&T"). G&T costs primarily relates to gathering,
transportation, and processing of our liquids-rich natural gas production. G&T
for the year ended December 31, 2019 increased compared to the year ended
December 31, 2018 by approximately $1.1 million due to an increase in sales
volume partially offset by a decrease of approximately $0.3 million due to a
decrease in the gathering and transportation rate. The increase in sales volumes
is primarily due to new wells coming online without any significant offsetting
decrease in production from natural well production declines. The gathering and
transportation rate was lower due to the adoption of ASC 606, which resulted in
the Company presenting G&T costs of approximately $2.5 million as an offset to
total revenues that would have previously been presented as G&T. Without the
adoption of ASC 606, the gathering and transportation rate increased for the
year ended December 31, 2019 compared to the year ended December 31, 2018
primarily due to higher gathering and transportation rates in certain sections
of the Northern and Southern Delaware Basin and those sections had an increase
in production for the year ended December 31, 2019 compared to the year ended
December 31, 2018 .
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Depreciation, depletion, amortization and accretion ("DD&A"). See the following table for a breakdown of DD&A and accretion:
Year Ended December 31,
2019 2018 Change Change %
(In thousands, except per Boe data)
Components of DD&A and accretion
Depreciation, depletion and amortization
of oil and gas properties $ 136,201 $ 140,447 $ (4,246 ) (3 )%
Depreciation of other property and
equipment 936 730 206 28
Accretion expense 800 638 162 25
$ 137,937 $ 141,815 $ (3,878 ) (3 )%
DD&A and accretion per Boe
Depreciation, depletion and amortization
of oil and gas properties $ 17.95 $ 20.98 $ (3.03 ) (14 )%
Depreciation of other property and
equipment 0.12 0.11 0.01 9
Accretion expense 0.11 0.10 0.01 10
Total DD&A and accretion per Boe $ 18.18 $ 21.19 DD&A for our oil and gas properties decreased by approximately$23.0 million due to a decrease in the DD&A per Boe ("DD&A Rate") partially offset by an increase of approximately$18.8 million due to an increase in sales volume. The DD&A Rate was higher during the year endedDecember 31, 2018 compared to the year endedDecember 31, 2019 due to a higher level of infrastructure costs being added to the depletion group without associated proved reserves being added. The increase in sales volumes is primarily due to new wells coming online without any significant offsetting decrease in production from natural well production declines. Oil represents a significant portion of our production and as noted above oil prices decreased significantly inMarch 2020 . Based onMarch 2020 daily price curves, we will more than likely need to record an impairment of our proved properties during the first quarter of 2020. If oil prices continue to decrease subsequent toMarch 2020 , additional impairments of our proved properties will be recorded. Exploration costs. Exploration costs include exploratory seismic expenditures, other geological and geophysical costs, lease rentals and drilling costs of exploratory wells that are determined to be unsuccessful. Exploration costs for the year endedDecember 31, 2019 increased compared to the year endedDecember 31, 2018 primarily due to the impairment of approximately$12.4 million on undeveloped leasehold acreage partially offset by lower expenses incurred related to our ongoing seismic studies of the acreage we acquired in theSouthern Delaware Basin inDecember 2017 . General and administrative, excluding stock-based compensation ("G&A"). G&A for the year endedDecember 31, 2019 increased compared to the year endedDecember 31, 2018 primarily due to an increase in payroll and payroll related costs of$5.0 million as a result of an increase in full-time employees. Stock-based compensation. Stock-based compensation for the year endedDecember 31, 2019 decreased slightly compared to the year endedDecember 31, 2018 . Because we account for forfeitures as they occur by reversing compensation cost previously recognized and associated with unvested awards when the award is forfeited, we expect volatility in our stock-based compensation; however, we do not expect such volatility to be significant. (Gain) loss on disposition of property and equipment. (Gain) loss on disposition of property and equipment increased for the year endedDecember 31, 2019 compared toDecember 31, 2018 primarily due to us recognizing a gain of approximately$11.1 million on the disposition of our oil and gas properties located inLea County, New Mexico ("Tatanka Assets"). 64 --------------------------------------------------------------------------------
Other income and expense. The following table summarizes our other income and expense for the periods indicated:
Year Ended December 31,
2019 2018 Change Change %
(In thousands)
Other income (expense):
Interest expense, net $ (25,228 ) $ (19,489 ) $ (5,739 ) 29 %
Gain (loss) on commodity derivative
instruments, net (65,338 ) 92,604 (157,942 ) (171 )
Other expense, net (660 ) (3,254 ) 2,594 (80 )
Total other income (expense), net $ (91,226 ) $ 69,861 Interest expense, net. Interest expense, net for the year endedDecember 31, 2019 increased compared to the year endedDecember 31, 2018 . The interest expense related to our revolving credit facility increased by$5.3 million for the year endedDecember 31, 2019 compared to the year endedDecember 31, 2018 as a result of an increase in borrowings outstanding. In addition, in 2019, we entered into interest rate swaps on a portion our outstanding borrowings under our revolving credit facility and incurred a loss of approximately$0.5 million for the year endedDecember 31, 2019 on such swaps. Gain (loss) on commodity derivative instruments, net. Net gains and losses on our commodity derivatives are a function of fluctuations in the underlying commodity prices versus fixed hedge prices, time decay and volatility associated with options and the monthly settlement of the instruments. The total net loss for the year endedDecember 31, 2019 is comprised of net losses of$14.7 million on cash settlements and net losses of$50.7 million on mark-to-market adjustments on unsettled positions. The total net gain for the year endedDecember 31, 2018 is comprised of net losses of$15.5 million on cash settlements and net gains of$108.1 million on mark-to-market adjustments on unsettled positions. Other expense, net. Other expense, net for the year endedDecember 31, 2019 decreased compared to the year endedDecember 31, 2018 primarily due to adjustments to our Tax Receivable Agreement liability. We account for amounts payable under the Tax Receivable Agreement in accordance with ASC Topic 450, Contingencies. Subsequent changes to the measurement of the Tax Receivable Agreement liability are recognized in the statements of operations. The adjustment to our Tax Receivable Agreement liability for the year endedDecember 31, 2019 was approximately$0.2 million compared to approximately$3.5 million for the year endedDecember 31, 2018 . Due to the uncertainty of the market and the significant decrease in oil prices that occurred subsequent toDecember 31, 2019 , as detailed in Note 3 - Subsequent Events and Liquidity, we expect to adjust our Tax Receivable Agreement liability to zero during the first quarter of 2020.
Year Ended
A discussion about our results of operations for the year endedDecember 31, 2018 compared to the year endedDecember 31, 2017 was included in Item 7, Management's Discussion and Analysis, of our Annual Report on Form 10-K for the year endedDecember 31, 2018 filed with theSEC .
Capital Requirements and Sources of Liquidity
Going Concern Assessment and Management's Plan
As ofMarch 31, 2020 , we were fully drawn against the amount available against our Amended and Restated Credit Agreement (as defined in Note 11 - Long-term debt, net), with$340 million outstanding under our Amended and Restated Credit Agreement. Our next borrowing base redetermination is expected to occur inApril 2020 . We expect the borrowing capacity to be reduced by the lenders, potentially significantly, in connection with this redetermination and we will be required to repay borrowings in excess of the borrowing capacity. Under the Amended and Restated Credit Agreement, we have the option to repay either in full within 30 days after the redetermination or in monthly installments over a six-month period commencing 30 days following the redetermination. Any reductions to our borrowing capacity at future redetermination dates could result in additional deficiencies that would require us to repay based on the terms discussed above. Our Amended and Restated Credit Agreement restricts certain distributions including cash dividends on our Series A Preferred Stock and Series B Preferred Stock. Such distributions can only be made so long as both before and immediately following such distributions, (i) we are not in default under our Amended and Restated Credit Agreement, (ii) our unused borrowing capacity is equal to or greater than 20% of the committed borrowing capacity and (iii) our ratio of Total Debt to EBITDAX is not greater than 3.5 to 1.0. Because we fully drew the amount available against our Amended and Restated Credit Agreement, we are restricted 65 -------------------------------------------------------------------------------- from paying dividends on our Series B Preferred Stock. The next scheduled dividend payment date is on or aboutApril 15, 2020 , but we must reduce our borrowings outstanding to an amount that is 20% less than the committed borrowing capacity in place at the time of the dividend payment. Any payments made to reduce our borrowings outstanding to an amount that is 20% less than the committed borrowing capacity is made in addition to the payments made to cure any borrowing capacity deficiencies under the Amended and Restated Credit Agreement. If we fail to pay dividends on our Series B Preferred Stock, the dividend rate increases to 12% per annum until dividends are fully paid and current, at which time the dividend rate will revert back to 10% per annum and if we fail to pay dividends for nine consecutive months, the holders of the Series B Preferred Stock may elect to cause us to redeem all or a portion of the Series B Preferred Stock, which the amount was approximately$195.2 million had the full redemption occurred as ofMarch 31, 2020 . We do not expect to be able to pay dividends on the Series B Preferred Stock on theApril 15, 2020 dividend date and it is uncertain if it will be able to pay dividends at future dates. OnMarch 23, 2020 , we received a letter fromThe Nasdaq Stock Market LLC ("Nasdaq") indicating that for the 30 consecutive business days endingMarch 20, 2020 , the bid price for our common stock had closed below the$1.00 per share minimum bid price requirement for continued listing on The Nasdaq Capital Market under Nasdaq Listing Rule 5550(a)(2). Under Nasdaq Listing Rule 5810(c)(3)(A), we have 180 calendar days, or untilSeptember 21, 2020 , to regain compliance by meeting the continued listing standard. To regain compliance, the closing bid price of our common stock must meet or exceed$1.00 per share for a minimum of ten consecutive business days during the 180 calendar day period. If we are not able to regain compliance with the Nasdaq Listing Rule, it will be an event of default under our Second Lien Notes and Amended and Restated Credit Agreement that would require us to redeem all the amounts outstanding under the Second Lien Notes and Amended and Restated Credit Agreement. It will also constitute a change of control under our Series B Preferred Stock and could give holders of the Series B Preferred Stock the right to require us to redeem all amounts outstanding out of funds legally available therefor. We have halted all drilling and completion activity for 2020, which will result in a reduction in anticipated production and cash flows. In addition to cash on hand of$82 million atMarch 31, 2020 and cash flows from operations, we may generate additional funds through monetization of our commodity derivatives, subject to approval of lenders under our Second Lien Notes, which were in an asset position as ofMarch 31, 2020 , the sale of non-core assets and other sources of capital. There can be no assurance that such capital will be available. However, our future cash flows from operations are subject to a number of variables, including uncertainty in forecasted commodity pricing, production and redetermined borrowing base capacity, which may be significantly reduced, and our ability to reduce costs. Also, we may not be able to monetize our commodity derivatives for an acceptable amount or at all or obtain required approvals under our financing agreements, complete the sale of core or non-core assets or access other sources of capital on acceptable terms or at all. Furthermore, we cannot guarantee that we will be able to maintain the listing of our Class A Common Stock, Class A Common Stock Public Units, or Public Warrants on The Nasdaq Capital Market. If we are unable to reduce the amount outstanding under the Amended and Restated Credit Agreement for payment of preferred dividends or unable to regain compliance with the Nasdaq Listing Rule, the holders of the Series B Preferred Stock may elect to cause us to redeem all or a portion of the Series B Preferred Stock (out of funds legally available therefor). This election could cause us to not be in compliance with our current ratio requirements under the Amended and Restated Credit Agreement. These matters raise substantial doubt about our ability to continue as a going concern within the next year and one day post issuance of these consolidated financial statements. The consolidated financial statements included in this report have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets and satisfaction of liabilities and commitments in the normal course of business. The financial statements do not include adjustments that might result from the outcome of the uncertainty, including any adjustments to reflect the possible future effects of the recoverability and classification of recorded assets amounts or amounts and classification of liabilities that might be necessary should we be unable to continue as a going concern.
Sources of Capital
Our activities require us to make significant operating, investing and financing
expenditures. Historically, our primary sources of liquidity have been cash
flows from operations, borrowings under our revolving credit agreement,
financing entered into in connection with acquisitions (such as the issuance of
the Series B Preferred Stock and Second Lien Notes), proceeds from the sale of
assets, and proceeds from issuance of equity securities. Our primary uses of
cash have been for the development of oil and natural gas properties,
acquisition of additional properties, interest payments on outstanding debt,
dividend payments on our preferred stock, and operating and general and
administrative expenses. In 2020, we intend to focus our uses of cash on the
operation of our producing properties, interest payments on outstanding debt,
dividend payments on our preferred stock (if permitted under our Amended and
Restated Credit Agreement), and operating and general and administrative
expenses.
66
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In March 2020 , we announced that we have halted all drilling and completion
activity. The amount and allocation of future capital expenditures will depend
upon a number of factors, including our cash flows from operations, investing
and financing activities, growth of our borrowing base and our ability to
assimilate acquisitions and execute our drilling program. We review our capital
expenditure forecast periodically to assess changes in current and projected
cash flows, liquidity, debt requirements and other factors. If we are unable to
obtain funds when needed or on acceptable terms, we may not be able to finance
the capital expenditures necessary to operate our producing properties,
recommence or execute on our drilling and completion program or complete
acquisitions that may be favorable to us. The suspension of our drilling and
completion activity for 2020 will result in a reduction in anticipated
production and cash flows. Because we have curtailed our drilling and completion
program, we expect to lose a portion of our acreage through lease expirations.
In addition, we expect to be required to reclassify some portion of our reserves
currently booked as proved undeveloped reserves because of such a deferral of
planned capital expenditures.
Because we are the operator of a high percentage of our acreage, the timing and
level of our capital spending is largely discretionary and within our control.
As evidenced by suspension of our drilling and completion program commencing in
late March 2020 , we could choose to defer a portion of these planned capital
expenditures depending on a variety of factors, including, but not limited to,
the success of our drilling activities, prevailing and anticipated prices for
oil, natural gas and NGLs, the availability of necessary equipment,
infrastructure and capital, the receipt and timing of required regulatory
permits and approvals, seasonal conditions, drilling and acquisition costs and
the level of participation by other working interest owners. A deferral of
planned capital expenditures, particularly with respect to drilling and
completing new wells, will result in a reduction in anticipated production and
cash flows.
In the event we make any acquisitions and the amount of capital required is
greater than the amount we have available for acquisitions at that time, we
could be required to reduce the expected level of capital expenditures or seek
additional capital. If we require additional capital for that or other reasons,
we may seek such capital through traditional reserve base borrowings, joint
venture partnerships, production payment financings, asset sales, offerings of
debt or equity securities, or other means, although such sources of capital may
not be available on terms acceptable to us or at all.
Attempts to Seek Refinancing
If the maturity date of our Amended and Restated Credit Agreement is not extended prior toAugust 2021 , the total debt outstanding will be considered current debt, which could result in a requirement that we repay the Amended and Restated Credit Agreement and the Second Lien Notes and redeem the Series B Preferred Stock out of funds legally available therefor. As ofDecember 31, 2019 , the Base Return Amount, as defined in Note 12 - 10% Series B Redeemable Preferred Stock, on our Series B Preferred Stock was approximately$199.2 million , which amount will be reduced by any subsequent dividend payments. We intend to refinance the Amended and Restated Credit Agreement beforeAugust 2021 . We are currently pursuing options to refinance our existing indebtedness, including restructuring our existing capital and obtaining new sources of capital. If the Second Lien Notes and Series B Preferred Stock are refinanced, we expect we would be able to extend the maturity of our existing Amended and Restated Credit Agreement. There is no assurance, however, that such discussions will result in a refinancing on acceptable terms, if at all or provide any specific amount of additional liquidity for future capital expenditures. Alternative sources of capital could involve the issuance of additional debt or preferred equity. However, the recent decline in world market conditions and commodity prices has made it more difficult to complete these efforts. We are taking steps to manage compliance with the financial covenants under our Amended and Restated Credit Agreement. Although we were in compliance with all of our financial covenants as ofDecember 31, 2019 , we could face challenges meeting certain financial performance covenants under our Amended and Restated Credit Agreement in the future. As noted above, if we are unable to reduce the amount outstanding under the Amended and Restated Credit Agreement for payment of preferred dividends or unable to regain compliance with the Nasdaq Listing Rule, we could be required to redeem amounts outstanding under our Series B Preferred Stock (out of funds legally available therefor) and Amended and Restated Credit Agreement. The early redemption requirement could cause us to not be in compliance with our current ratio requirements under the Amended and Restated Credit Agreement. While we manage compliance with ratios and review such liquidity-enhancing alternative sources of capital, we intend to continue to manage our expenditures appropriately, including through suspension of our drilling program, a reduction in cash general and administrative expenses, and possibly through the sale of core or non-core properties. We may also pursue strategic transactions. Some of our liquidity management plans would require approvals of the holders of the Series B Preferred Stock, which could limit our options or increase the cost of certain options. There is no assurance that such efforts will be successful. If we are unable to successfully refinance debt or maintain compliance with the covenants in our debt documents and preferred stock, we may seek an out of court restructuring or, alternatively, protection under Chapter 11 of theU.S. Bankruptcy Code. 67 --------------------------------------------------------------------------------
Working Capital
We define working capital as current assets less current liabilities. AtDecember 31, 2019 andDecember 31, 2018 , we had a working capital deficit of$19.1 million and a surplus of$5.5 million , respectively. As ofDecember 31, 2019 , we had$80 million available under our credit facility that we could borrow from to address any timing differences in cash flows. OnMarch 19, 2020 , we announced that we borrowed the remaining availability under our Amended and Restated Credit Agreement making the current borrowings to be$340 million . Collection of our accounts receivable has historically been timely, and losses associated with uncollectible receivables have historically not been significant, although a prolonged decline in market conditions could increase uncollectible or delayed receivables. We expect that production volumes, commodity prices and differentials to NYMEX prices for oil and natural gas production will be significant variables affecting our working capital. Because we are fully drawn under our Amended and Restated Credit Agreement, our Amended and Restated Credit Agreement restricts certain distributions including cash dividends on our Series B Preferred Stock. If we fail to pay dividends for nine consecutive months, the holders of the Series B Preferred Stock may elect to cause us to redeem all or a portion of the Series B Preferred Stock out of funds legally available. The amount outstanding was approximately$195.2 million had the full redemption occurred as ofMarch 31, 2020 . We cannot be certain that we will have the funds available to reduce our borrowing base to a sufficient level to meet restrictions under our Amended and Restated Credit Agreement and therefore have substantial doubt about our ability to continue as a going concern over the next year and one day post issuance of these consolidated financial statements.
Cash Flows from Operating, Investing and Financing Activities
The following table summarizes our cash flows for the periods indicated:
Year Ended December 31,
2019 2018 2017
(In thousands)
Net cash provided by operating activities $ 167,409 $ 176,309 $ 37,759
Net cash used in investing activities (230,395 ) (399,343 ) (265,497 )
Net cash provided by financing activities 45,820 218,509 243,986
Net decrease in cash and cash equivalents $ (17,166 ) $ (4,525 ) $ 16,248 Analysis of Cash Flow Changes for the Years Ended
Operating activities. Net cash provided by operating activities is primarily driven by the changes in commodity prices, operating expenses, production volumes and associated changes in working capital. The decrease in net cash provided by operating activities of$8.9 million was primarily due to an increase in cash related expenses which decreased our operating cash flows by approximately$8.8 million and an increase in our loss on hedge settlements which decreased our operating cash flows by approximately$0.6 million , partially offset by an increase in revenues of$0.4 million . Investing activities. Net cash used in investing activities for the year endedDecember 31, 2019 included$249.9 million attributable to the development of oil and natural gas properties,$1.3 million for the acquisition of leasehold and mineral interest and$1.0 million for additions to other property and equipment, all of which was partially offset by the net proceeds from the sale of our Tatanka Assets of$21.8 million . Net cash used in investing activities for the year endedDecember 31, 2018 included$377.9 million attributable to the development of oil and natural gas properties,$15.3 million for the acquisition of land and leasehold, royalty, and mineral interests,$4.0 million for the release of the escrow deposit for the White Wolf Acquisition, and$2.2 million for additions to other property and equipment. Financing activities. Net cash provided by financing activities for the year endedDecember 31, 2019 primarily consisted of net borrowings of$66.0 million under our Amended and Restated Credit Agreement partially offset by$19.1 million of dividend payments,$0.8 million of debt issuance costs and$0.2 million used to repurchase vested stock for tax withholdings. Net cash provided by financing activities for the year endedDecember 31, 2018 primarily consists of net borrowings of$194.0 million under our revolving credit facility and$39.4 million from our Class A Common Stock Offering partially offset by$10.7 million of dividend payments,$3.3 million of debt issuance costs and$0.7 million used to repurchase vested stock for tax withholdings. 68 --------------------------------------------------------------------------------
Analysis of Cash Flow Changes for the Years Ended
An analysis of our cash flow changes for the year ended
Divestiture of
OnMarch 26, 2019 , Rosehill signed a Purchase and Sale Agreement to sell its Tatanka Assets for cash consideration of$22.0 million , along with the assumption by the purchaser of all abandonment obligations associated with the properties. OnApril 4, 2019 , Rosehill closed the transaction with an effective date ofOctober 1, 2018 . Proceeds, net of customary closing adjustments, was$21.8 million . Class A Common Stock Offering OnSeptember 27, 2018 , we entered into an underwriting agreement (the "Underwriting Agreement") withCitigroup Global Markets Inc. , as representative of the several underwriters named therein (the "Underwriters"), for a public offering of 6,150,000 shares of common stock (the "Class A Common Stock Offering") at a public offering price of$6.10 per share ($5.795 per share net of underwriting discount and commissions). Pursuant to the Underwriting Agreement, we granted the Underwriters a 30-day option to purchase up to an additional 922,500 shares of Class A Common Stock. OnOctober 2, 2018 , upon the closing of the Class A Common Stock Offering, we issued 6,150,000 shares of Class A Common Stock. Our net proceeds from the Class A Common Stock Offering, net of underwriting discounts and commissions and offering costs, was$34.5 million . OnOctober 5, 2018 , the Underwriters exercised their option to purchase an additional 840,744 shares of Class A Common Stock at the Underwriters' price of$5.795 per share. We received net proceeds of approximately$4.9 million for the shares of Class A Common Stock sold pursuant to the exercise of the Underwriters' option. We contributed all of the net proceeds from the Class A Common Stock Offering and the exercise of the Underwriters' option to Rosehill Operating in exchange for Rosehill Operating Common Units. Debt Agreements Amended and Restated Credit Agreement. OnMarch 28, 2018 ,Rosehill Operating andJPMorgan Chase Bank, N.A ., asAdministrative Agent and Issuing Bank , entered into the Amended and Restated Credit Agreement to refinance and replace Rosehill Operating's previous credit facility (the "Previous Credit Facility"). Pursuant to the terms and conditions of the Amended and Restated Credit Agreement, Rosehill Operating's line of credit and a letter of credit facility increased from up to$250 million under the Previous Credit Facility to up to$500 million under the Amended and Restated Credit Agreement, subject to a borrowing base that is determined semi-annually by the Lenders based upon Rosehill Operating's financial statements and the estimated value of its oil and gas properties, in accordance with the Lenders' customary practices for oil and gas loans. The redeterminations occur onApril 1 andOctober 1 of each year. The borrowing base is scheduled to be automatically reduced upon the issuance or incurrence of debt under senior unsecured notes or upon Rosehill Operating's or any of its subsidiaries' disposition of properties or liquidation of hedges in excess of certain thresholds. The Amended and Restated Credit Agreement also does not permit Rosehill Operating to borrow funds if, at the time of such borrowing, Rosehill Operating is not in pro forma compliance with the financial covenants. Additionally, Rosehill Operating's borrowing base may be reduced in connection with the subsequent redetermination of the borrowing base. Rosehill Operating and the Lenders each have the right to one interim unscheduled redetermination of the borrowing base between any two successive scheduled redeterminations. Rosehill Operating's borrowing base was$340 million as ofDecember 31, 2019 and we had$260.0 million outstanding under the Amended and Restated Credit Agreement. As previously disclosed onMarch 19, 2020 , we fully drew the amount available under the Amended and Restated Credit Agreement as a precautionary measure in order to increase our cash position and preserve financial flexibility in light of current uncertainty in the global markets and commodity prices. After giving effect to this draw, our total outstanding borrowings under the Amended and Restated Credit Agreement was$340 million and we had no additional capacity. Amounts borrowed under the Amended and Restated Credit Agreement may not exceed the borrowing base. If our borrowing base is reduced below our current borrowing level in connection with any redetermination and we are required to repay indebtedness in excess of the redetermined borrowing base, we may not have the liquidity to do so, which would result in an event of default under the Amended and Restated Credit Agreement. 69 -------------------------------------------------------------------------------- The amounts outstanding under the Amended and Restated Credit Agreement are secured by first priority liens on substantially all of Rosehill Operating's oil and natural gas properties and associated assets and all of the stock of Rosehill Operating's material operating subsidiaries that are guarantors of the Amended and Restated Credit Agreement. There are currently no guarantors under the Amended and Restated Credit Agreement. If an event of default occurs under the Amended and Restated Credit Agreement,JPMorgan Chase Bank, N.A . will have the right to proceed against the pledged capital stock and take control of substantially all of Rosehill Operating and Rosehill Operating's material operating subsidiaries that are guarantors' assets. An event of default can occur under a number of circumstances, including failure to maintain listing of our Class A Common Stock on a national securities exchange. OnMarch 23, 2020 , we received a letter fromThe Nasdaq Stock Market LLC ("Nasdaq") indicating that for the 30 consecutive business days endingMarch 20, 2020 , the bid price for our common stock had closed below the$1.00 per share minimum bid price requirement for continued listing on The Nasdaq Capital Market under Nasdaq Listing Rule 5550(a)(2). We cannot guarantee that we will be able to maintain listing of our Class A Common Stock, Class A Common Stock Public Units, or Public Warrants on The Nasdaq Capital Market. Borrowings under the Amended and Restated Credit Agreement will bear interest at a base rate plus an applicable margin ranging from 1.00% to 2.00% or at LIBO rate plus an applicable margin ranging from 2.00% to 3.00%. The Amended and Restated Credit Agreement will mature onAugust 31, 2022 , with an automatic extension toMarch 28, 2023 upon the payment in full of the Second Lien Notes if there is no event of default under the senior secured credit facility during the time of such extension. The Amended and Restated Credit Agreement contains various affirmative and negative covenants. These negative covenants may limit Rosehill Operating's ability to, among other things: incur additional indebtedness; make loans to others; make investments; enter into mergers; make or declare dividends or distributions; enter into commodity hedges exceeding a specified percentage of Rosehill Operating's expected production; enter into interest rate hedges exceeding a specified percentage of Rosehill Operating's outstanding indebtedness; incur liens; sell assets; and engage in certain other transactions without the prior consent ofJPMorgan Chase Bank, N.A . or lenders. Our Amended and Restated Credit Agreement restrict our cash distributions not to exceed$8.0 million and$25.0 million on our Series A Preferred Stock and Series B Preferred Stock, respectively, in any fiscal year to fund dividends or distributions. Such distributions can only be made so long as both before and immediately following such distributions, (i) we are not in default, (ii) our unused borrowing capacity is equal to or greater than 20% of the committed borrowing capacity and (iii) our ratio of Total Debt to EBITDAX is not greater than 3.5 to 1.0. We do not have sufficient borrowing capacity to make such dividend payments and do not expect to pay cash dividends scheduled to be paid onApril 15, 2020 . With respect to consequences due to our failure to pay the dividends on the Series B Preferred Stock, please read Note 12 - 10% Series B Redeemable Preferred Stock. The Amended and Restated Credit Agreement requires Rosehill Operating to deliver audited financial statements of Rosehill Operating (without a going concern qualification) to the lenders within 90 days after the end of each fiscal year. We can satisfy this requirement by providing audited financial statements ofRosehill Resources within 90 days after the end of each fiscal year. We failed to provide the lenders with audited financial statements and other required certificates and operating reports within 90 days afterDecember 31, 2019 , which constitutes a default under the Amended and Restated Credit Agreement. However, the Amended and Restated Credit Agreement gives us a 30-day cure period before it becomes an event of default that will allow the lenders to redeem a portion or all amounts outstanding. We expect to provide such financial statements, reports and certificates within this 30-day time frame
The Amended and Restated Credit Agreement also requires Rosehill Operating to maintain compliance with the following financial ratios:
• a current ratio, which is the ratio of consolidated current assets (including
unused commitments under the Amended and Restated Credit Agreement, but
excluding certain non-cash assets) to consolidated current liabilities
(excluding certain non-cash obligations, current maturities under the Amended
and Restated Credit Agreement and the Note Purchase Agreement (as defined
below)), of not less than 1.0 to 1.0,
• a leverage ratio, which is the ratio of the sum of Total Debt to Annualized
EBITDAX (as such terms are defined in the Amended and Restated Credit
Agreement) for the four fiscal quarters then ended, of not greater than 4.0
to 1.0 (the calculation of which will be modified once the Second Lien Notes
and the Series B Redeemable Preferred Stock are no longer outstanding) and
• a coverage ratio, which is the ratio of EBITDAX to the sum of Interest
Expense plus the aggregate amount of certain Restricted Payments (as such
terms are defined in the Amended and Restated Credit Agreement) made during
the preceding four fiscal quarters, of not less than 2.5 to 1.0 (such ratio
expiring once the Series B Redeemable Preferred Stock are no longer
outstanding).
70-------------------------------------------------------------------------------- We were in compliance with all financial ratios in the Amended and Restated Credit Agreement for the measurement period endedDecember 31, 2019 . Although we were in compliance with all of our financial covenants as ofDecember 31, 2019 , we could face challenges meeting certain financial covenants under our Amended and Restated Credit Agreement in the future. For additional information regarding our Amended and Restated Credit Agreement, see Note 11 - Long-term Debt, net in the consolidated financial statements under Part II, Item 8 of this Annual Report on Form 10-K. Second Lien Notes. OnDecember 8, 2017 , Rosehill Operating issued and sold$100,000,000 in aggregate principal amount of 10.00% Senior Secured Second Lien Notes dueJanuary 31, 2023 toEIG Global Energy Partners, LLC ("EIG") under and pursuant to the terms of the Note Purchase Agreement (as amended by the Limited Consent and First Amendment to Note Purchase Agreement, dated as ofMarch 28, 2018 , the "Note Purchase Agreement"), among Rosehill Operating and us, the holders of the Second Lien Notes party thereto (the "Holders") andU.S. Bank National Association , as agent and collateral agent on behalf of the Holders. The Second Lien Notes were issued and sold to the Holders in a private placement exempt from the registration requirements under the Securities Act. Under the Note Purchase Agreement, Rosehill Operating may, at its option, redeem the Second Lien Notes in whole or in part, together with accrued and unpaid interest thereon, (i) at any time afterDecember 8, 2019 but on or prior toDecember 8, 2020 , at a redemption price equal to 103% of the principal amount of the Second Lien Notes being redeemed, (ii) at any time afterDecember 8, 2020 but on or prior toDecember 8, 2021 , at a redemption price equal to 101.5% of the principal amount of the Second Lien Notes being redeemed and (iii) at any time afterDecember 8, 2021 , at a redemption price equal to the principal amount of the Second Lien Notes being redeemed. The Second Lien Notes may become subject to redemption under certain other circumstances, including upon the incurrence of non-permitted debt or, subject to various exceptions, reinvestments rights and prepayment or redemption rights with respect to other debt or equity of Rosehill Operating, upon an asset sale, hedge termination or casualty event. Rosehill Operating will be further required to make an offer to redeem the Second Lien Notes upon a Change in Control (as defined in the Note Purchase Agreement) at a redemption price equal to 101% of the principal amount being redeemed. Other than in connection with a Change in Control or casualty event, the redemption prices described in the foregoing paragraph shall also apply, at such times and to the extent set forth therein, to any mandatory redemption of the Second Lien Notes or any acceleration of the Second Lien Notes prior to the stated maturity thereof upon the occurrence of an event of default. The Note Purchase Agreement requires Rosehill Operating to maintain a leverage ratio, which is the ratio of the sum of all of Rosehill Operating's Total Debt to Annualized EBITDAX (as such terms are defined in the Note Purchase Agreement) for the four fiscal quarters then ended, of not greater than 4.00 to 1.00. We were in compliance with the leverage ratio for the measurement period endedDecember 31, 2019 . The Note Purchase Agreement contains various affirmative and negative covenants, events of default and other terms and provisions that are based largely on the Amended and Restated Credit Agreement, with a number of important modifications reflecting the second lien nature of the Second Lien Notes and certain other terms that were agreed to with the Holders. The negative covenants may limit Rosehill Operating's ability to, among other things, incur additional indebtedness (including pursuant to senior unsecured notes), make investments, make or declare dividends or distributions, redeem its preferred equity, acquire or dispose of oil and gas properties and other assets or engage in certain other transactions without the prior consent of the Holders, subject to various exceptions, qualifications and value thresholds. Rosehill Operating is also required to meet minimum commodity hedging levels based on its expected production on an ongoing basis. Any event or condition that causes any debt under the Amended and Restated Credit Agreement becoming due prior to its scheduled maturity, with certain exceptions, including borrowing base deficiencies, is an event of default under the Note Purchase Agreement. The Note Purchase Agreement requires Rosehill Operating to deliver audited financial statements of Rosehill Operating (without a going concern qualification) to the Holders within 90 days after the end of each fiscal year. We failed to provide the Holders with audited financial statements and other required certificates and operating reports within 90 days afterDecember 31, 2019 , which constitutes a default under the Note Purchase Agreement. However, the Note Purchase Agreement gives us a 30-day cure period before it becomes an event of default that will allow the Holders to force redemption of a portion or all amounts outstanding. We expect to provide such financial statements, reports and certificates within this 30-day time frame. We are subject to certain restrictions under the Note Purchase Agreement, including (without limitation) a negative pledge with respect to our equity interests in Rosehill Operating and a contingent obligation to guarantee the Second Lien Notes upon request by the Holders in the event that we incur debt obligations. The obligations of Rosehill Operating under the Note Purchase Agreement are secured on a second-lien basis by the same collateral that secures its first-lien obligations. In connection with the Note Purchase Agreement, Rosehill Operating granted second-lien security interests over additional collateral to meet the minimum mortgage requirements under the Note Purchase Agreement. 71 --------------------------------------------------------------------------------
Preferred Stock and Warrants
We are authorized to issue up to 1,000,000 shares of our preferred stock, of which 150,000 have been designated as Series A Preferred Stock and 210,000 have been designated as Series B Preferred Stock. OnApril 27, 2017 , we issued 75,000 shares of Series A Preferred Stock and 5,000,000 warrants (exercisable for shares of Class A Common Stock) in a private placement to certain qualified institutional buyers and accredited investors for net proceeds of$70.8 million . We issued an additional 20,000 shares of Series A Preferred Stock toRosemore Holdings, Inc. and KLR Sponsor in connection with the closing of the Transaction for an additional$20.0 million . OnDecember 8, 2017 , in connection with the White Wolf Acquisition, we issued 150,000 shares of Series B Preferred Stock, par value of$0.0001 per share, to EIG (the "Series B Preferred Stock Purchasers") for an aggregate purchase price of$150.0 million , less transaction costs and up-front fees of approximately$10.0 million . We had the option, subject to certain conditions, to sell from time to time up to an additional 50,000 shares of Series B Preferred Stock, in the aggregate, to the Series B Preferred Stock Purchasers and their transferees for a purchase price of$1,000 per share of Series B Preferred Stock. We did not exercise such option, which terminated onDecember 8, 2018 . Please read Capital Requirements and Sources of Liquidity - Going Concern Assesment and Management's Plan and and Note 12 - 10% Series B Redeemable Preferred Stock for more details on dividend requirements, results of failure to pay dividends and the impact on our liquidity.
Off-Balance Sheet Arrangements
As of
Critical Accounting Policies and Estimates
The preparation of financial statements requires the use of judgments and estimates. Our critical accounting policies are described below to provide a better understanding of how we develop our assumptions and judgments about future events and related estimates and how they can impact our financial statements. A critical accounting estimate is one that requires our most difficult, subjective or complex estimates and assessments and is fundamental to our results of operations. We base our estimates on historical experience and on various other assumptions we believe to be reasonable according to the current facts and circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We believe the following are the critical accounting policies used in the preparation of our combined financial statements, as well as the significant estimates and judgments affecting the application of these policies. This discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in this report.
Successful Efforts Method of Accounting for Oil and Natural Gas Activities
Oil and natural gas exploration, development and production activities are accounted for under the successful efforts method of accounting. Under this method, the costs incurred to acquire, drill and complete productive wells and development wells are capitalized. Oil and gas lease acquisition costs are also capitalized.Proved Oil and Natural Gas Properties . If proved reserves are found for these properties, costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil, natural gas, and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized. Capitalized costs attributed to the properties and mineral interests are subject to depreciation, depletion and amortization ("DD&A"). Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated reservoir. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense.Unproved Properties . Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties. 72 -------------------------------------------------------------------------------- Exploration Costs. Exploration costs, other than exploration drilling costs, are charged to expense as incurred. These costs include exploratory seismic expenditures, other geological and geophysical costs and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a 12-month period after drilling is complete. For sales of a complete or partial unit of proved and unproved properties and related facilities, the cost and related accumulated DD&A are removed from the property accounts and gain or loss is recognized for the difference between the proceeds received and the net carrying value of the properties sold.
Impairment of
Our proved oil and natural gas properties are recorded at cost. Our proved properties are evaluated for impairment on a field-by-field basis whenever events or changes in circumstances indicate that an asset's carrying value may not be recoverable. We compare expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on its estimate of future oil and natural gas prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using WTI andHenry Hub natural gas NYMEX strip market pricing, adjusted for quality, transportation fees and a regional price differential. While it is difficult to project future impairment write-downs in light of numerous factors involved, fluctuations in prices or costs could result in an impairment of our oil and natural gas properties. Unproved oil and natural gas properties are assessed periodically, and no less than annually, for impairment on an aggregate basis based on remaining lease term, drilling results, reservoir performance, seismic interpretation and future plans to develop acreage. As unproved oil and natural gas properties are developed and reserves are proved, the capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved oil and natural gas properties are written off or reclassified to proved oil and natural gas properties depends on the timing and success of our future exploration and development program. We expect the decline in oil prices that occurred subsequent toDecember 31, 2020 to significantly reduce the undiscounted expected cash flows from our proved reserves and will more than likely result in impairments of the Company's proved properties during the first quarter of 2020. If oil prices continue to decrease subsequent toMarch 2020 , additional impairments of our properties will be recorded. InMarch 2020 , we announced that we were halting our drilling and completion activity for 2020 and as a result we expect to lose a portion of our acreage through lease expirations that will result in impairments recorded in 2020 related to those expirations. In addition, we expect to be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves because of such a deferral of planned capital expenditures.
Depreciation, Depletion and Amortization for
The quantities of estimated proved oil and gas reserves are a significant component of our calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves were revised upward or downward, earnings would increase or decrease, respectively. Depreciation, depletion and amortization of the cost of proved oil and gas properties is calculated using the unit-of-production method. The reserve base used to calculate depreciation, depletion and amortization for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. With respect to lease and well equipment costs, which include development costs and successful exploration drilling costs, the reserve base includes only proved developed reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are taken into account.
Oil and gas properties are grouped based upon a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
Depreciation, depletion and amortization rates are updated quarterly to reflect the addition of capital costs, reserve revisions (upwards or downwards) and additions, property acquisitions or property dispositions and impairments.
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--------------------------------------------------------------------------------Oil and Natural Gas Reserve Quantities
Our estimated proved reserve quantities and future net cash flows are critical to the understanding of the value of our business. They are used in comparative financial ratios and are the basis for significant accounting estimates in its financial statements, including the calculations of depletion and impairment of proved oil and natural gas properties. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure calculations require a 10% discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, we make a considerable effort in estimating our reserves. We expect proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. We have and expect to evaluate and estimate our proved reserves each year-end. For purposes of depletion and impairment, reserve quantities are adjusted in accordance withU.S. GAAP for the impact of additions and dispositions. Subsequent toDecember 31, 2019 , commodity prices declined significantly, which we expect to significantly reduce the undiscounted expected cash flows from our proved reserves. In addition, we expect to be required to reclassify some portion of our reserves currently booked as proved undeveloped reserves because of such a deferral of planned capital expenditures.
Asset Retirement Obligations
An asset retirement obligation ("ARO") represents the estimated present value of
the amount we will incur to retire a long-lived asset at the end of its
productive life, in accordance with applicable state laws. We recognize an
estimated liability for future costs primarily associated with the abandonment
of our oil and natural gas properties and related assets. The amount of the ARO
is determined by calculating the present value of estimated cash flows related
to the liability. The retirement obligation is recorded as a liability at its
estimated present value at inception (i.e., at the time the well is drilled or
acquired and related assets are placed into service) with an offsetting increase
in the carrying amount of the related long-lived asset that is included in
proved oil and natural gas properties in the accompanying consolidated balance
sheets. Periodic accretion of discount of the estimated liability is recorded as
an expense in the income statement. We depreciate the long-lived asset,
including the asset retirement cost, over its useful life and recognize an
expense in connection with the accretion of the discounted liability over the
remaining estimated economic lives of the respective oil and natural gas
properties.
Asset retirement liability is determined using significant assumptions,
including current estimates of plugging and abandonment costs, annual inflation
of these costs, the productive lives of assets and our risk-adjusted interest
rate. Changes in any of these assumptions can result in significant revisions to
the estimated asset retirement obligation. Because of the subjectivity of
assumptions, the costs to ultimately retire our wells may vary significantly
from prior estimates.
Commodity Derivative Instruments
We utilize commodity derivative instruments including swaps, collars, basis swaps and other similar agreements to manage our exposure to oil and natural gas price volatility (i.e., price risk) associated with the forecasted sale of a portion of our oil and natural gas production. These commodity derivative instruments are not designated as hedges for accounting purposes. Accordingly, we record derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and record the change in the fair value of derivatives in current earnings in the statements of operations as they occur in the period of change. Gains and losses on commodity derivatives and premiums paid for put options are included in cash flows from operating activities.
To the extent a legal right of offset exists with a counterparty, we report derivative assets and liabilities on a net basis. We have exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. We actively monitor the creditworthiness of counterparties and assesses the impact, if any, on our derivative position.
Income Taxes
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Due to the uncertainty of the market and the significant decrease in oil prices that occurred subsequent toDecember 31, 2019 , as detailed in Note 3 - Subsequent Events and Liquidity, we expect to record a full valuation allowance to offset our net deferred tax assets for the first quarter of 2020. 74 -------------------------------------------------------------------------------- We account for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return, which are subject to examination by federal and state taxing authorities. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management's estimates of the ultimate outcome of various tax uncertainties. We recognize penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations. We are a C corporation and are subject toU.S. federal, state and local income taxes. Rosehill Operating is a limited liability company treated as a partnership forU.S. federal income tax purposes that is generally not subject toU.S. federal income tax at the entity level. See Note 13 - Income Taxes for more income tax disclosures.
Tax Receivable Agreement
In connection with the Transaction, we entered into a Tax Receivable Agreement with the noncontrolling interest holder, Tema. The Tax Receivable Agreement provides that we will pay to Tema 90% of the net cash savings, if any, inU.S. federal, state and local income tax that we realize (or is deemed to realize in certain circumstances) in periods beginning with and after the closing of the Transaction. We account for amount payable under the Tax Receivable Agreement in accordance with Accounting Standards Codification Topic 450, Contingencies. As such, subsequent changes to the measurement of the Tax Receivable Agreement liability are recognized in the statements of operations as a component of other income (expense), net. Due to the uncertainty of the market and the significant decrease in oil prices that occurred subsequent toDecember 31, 2019 , as detailed in Note 3 - Subsequent Events and Liquidity, we expect to adjusted our Tax Receivable Agreement liability to zero during the first quarter of 2020.
Recently Issued Accounting Pronouncements
Please refer to Note 2 - Summary of Significant Accounting Policies and Recently Issued Accounting Standards in the consolidated financial statements under Part II, Item 8 of this Annual Report on Form 10-K for a discussion of recent accounting pronouncements and their anticipated effect on us.
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