filings.toolsItem 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our 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. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See Item 1A. “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”
Overview
We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitation of unconventional, onshore oil and natural gas reserves in the Permian Basin in West Texas. Our activities are primarily directed at the horizontal development of the Wolfcamp and Spraberry formations in the Midland Basin and the Wolfcamp and Bone Spring formations in the Delaware Basin. We intend to continue to develop our reserves and increase production through development drilling and exploitation and exploration activities on our multi-year inventory of identified potential drilling locations and through acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves. Substantially all of our revenues are generated through the sale of oil, natural gas liquids and natural gas production.
The following table sets forth our production data for the periods indicated:
| Year Ended December 31, | ||||||||
| 2017 | 2016 | 2015 | ||||||
| Oil (MBbls) | 74 | % | 73 | % | 75 | % | ||
| Natural gas (MMcf) | 12 | % | 11 | % | 11 | % | ||
| Natural gas liquids (MBbls) | 14 | % | 16 | % | 14 | % | ||
| 100 | % | 100 | % | 100 | % |
On December 31, 2017, our acreage position in the Permian Basin was approximately 246,012 gross (206,660 net) acres, which consisted of approximately 117,586 gross (101,941 net) acres in the Northern Midland Basin and approximately 128,426 gross (104,719 net) acres in the Southern Delaware Basin.
2017 Transactions and Recent Developments
Our Delaware Basin Acquisition
On February 28, 2017, we completed an acquisition of oil and natural gas properties, midstream assets and other related assets in the Delaware Basin for an aggregate purchase price consisting of $1.74 billion in cash and 7.69 million shares of our common stock, of which approximately 1.15 million shares were placed in an indemnity escrow. This transaction included the acquisition of (i) approximately 100,306 gross (80,339 net) acres primarily in Pecos and Reeves counties for approximately $2.5 billion and (ii) midstream assets for approximately $47.6 million. We used the net proceeds from our December 2016 equity offering, net proceeds from our December 2016 debt offering, cash on hand and other financing sources to fund the cash portion of the purchase price for this acquisition.
New Senior Notes
On January 29, 2018, we issued $300.0 million aggregate principal amount of new 2025 notes as additional notes under our existing indenture, dated as of December 20, 2016, as supplemented, among us, subsidiary guarantors party thereto and Wells Fargo, as trustee, under which we previously issued $500.0 million aggregate principal amount of our existing 5.375% Senior Notes due 2025. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.
Viper Equity Offerings
In January 2017, Viper completed an underwritten public offering of 9,775,000 common units, which included 1,275,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. Viper received net proceeds from this offering of approximately $147.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which Viper used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance was used for general partnership purposes, which included additional acquisitions.
In July 2017, Viper completed an underwritten public offering of 16,100,000 common units, which included 2,100,000 common units issued pursuant to an option to purchase additional common units granted to the underwriters. In this offering, we purchased 700,000 common units, an affiliate of the General Partner purchased 3,000,000 common units and certain officers and directors of our Company and the General Partner purchased an aggregate of 114,000 common units, in each case directly from the underwriters. Following this offering, we had an approximate 64% limited partner interest in Viper. Viper received net proceeds from this offering of approximately $232.5 million, after deducting underwriting discounts and commissions and estimated offering expenses, of which Viper used $152.8 million to repay all of the then-outstanding borrowings under Viper’s revolving credit facility and the balance was used to fund a portion of the purchase price for acquisitions and for general partnership purposes.
Operational Update
We are operating ten rigs now and currently intend to operate between ten and twelve drilling rigs in 2018 across our asset base in the Midland and Delaware Basins. We plan to operate six to seven of these rigs in the Midland Basin targeting horizontal development of the Wolfcamp and Spraberry formations, with four to five rigs are expected to operate in the Delaware Basin targeting the Wolfcamp and Bone Spring formations.
In the Midland Basin, we continue have positive results across our core development areas located within Midland, Martin, Howard, Glasscock and Andrews counties, where development has primarily focused on drilling long-lateral, multi-well pads targeting the Spraberry and Wolfcamp formations. We are currently operating six rigs on the acreage and expect to average approximately six to eight operated rigs in 2018.
In the Delaware Basin, we have now drilled and completed multiple wells in Pecos, Reeves and Ward counties targeting the Wolfcamp A, which we believe has been de-risked across a significant portion of our total acreage position and remains our primary development target. Additionally, we have successfully completed additional wells targeting such zones as the Wolfcamp B and 2nd Bone Spring, and expect to test these zones further in 2018. We are currently operating four rigs in the Delaware Basin and plan to average approximately four to five rigs in 2018.
We continue to focus on low cost operations and best in class execution. In doing so, we are focused on controlling oilfield service costs as our service providers seek to increase pricing following continued strength in the oil market. To combat rising service costs, we have looked to lock in pricing for dedicated activity levels and will continue to seek opportunities to control additional well cost where possible. Our 2018 drilling and completion budget accounts for rising capital costs that we believe will cover potential increases in our service costs during the year.
2018 Capital Budget
We have currently budgeted a 2018 total capital spend of $1.3 billion to $1.5 billion, consisting of $1.175 billion to $1.325 billion for horizontal drilling and completions including non-operated activity and $125.0 million to $175.0 million for infrastructure and other expenditures, but excluding the cost of any leasehold and mineral interest acquisitions. We expect to drill and complete 170 to 190 gross horizontal wells in 2018.
Operating Results Overview
The following table summarizes our average daily production for the periods presented:
| Year Ended December 31, | |||||
| 2017 | 2016 | 2015 | |||
| Oil (Bbls)/d | 58,678 | 31,590 | 24,880 | ||
| Natural Gas (Mcf)/d | 56,602 | 29,313 | 21,729 | ||
| Natural Gas Liquids (Bbls)/d | 11,112 | 6,556 | 4,596 | ||
| Total average production per day | 79,224 | 43,031 | 33,098 |
Our average daily production for the year ended December 31, 2017 as compared to the year ended December 31, 2016 increased by 36,193 BOE/d, or 84%.
During the year ended December 31, 2017, we drilled 150 gross (130 net) horizontal wells and participated in the drilling of 16 gross (two net) non-operated horizontal wells in the Permian Basin.
Reserves and pricing
Ryder Scott prepared estimates of our proved reserves at December 31, 2017, 2016 and 2015 (which include estimated proved reserves attributable to Viper). The prices used to estimate proved reserves for all periods did not give effect to derivative transactions, were held constant throughout the life of the properties and have been adjusted for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.
| 2017 | 2016 | 2015 | ||||||
| Estimated Net Proved Reserves: | ||||||||
| Oil (MBbls) | 233,181 | 139,174 | 105,979 | |||||
| Natural gas (MMcf) | 285,369 | 174,896 | 149,503 | |||||
| Natural gas liquids (MBbls) | 54,610 | 37,134 | 26,004 | |||||
| Total (MBOE) | 335,352 | 205,458 | 156,899 |
| Unweighted Arithmetic Average | |||||||||||
| First-Day-of-the-Month Prices | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Oil (per Bbl) | $ | 48.03 | $ | 39.94 | $ | 45.07 | |||||
| Natural gas (per Mcf) | $ | 2.06 | $ | 1.36 | $ | 1.83 | |||||
| Natural gas liquids (per Bbl) | $ | 20.79 | $ | 12.91 | $ | 12.56 |
Sources of our revenue
Our revenues are derived from the sale of oil and natural gas production, as well as the sale of natural gas liquids that are extracted from our natural gas during processing. Our oil and natural gas revenues do not include the effects of derivatives. Our revenues may vary significantly from period to period as a result of changes in volumes of production sold, production mix or commodity prices.
The following table presents the sources of our revenues for the years presented:
| Year Ended December 31, | ||||||||
| 2017 | 2016 | 2015 | ||||||
| Revenues | ||||||||
| Oil sales | 88 | % | 89 | % | 91 | % | ||
| Natural gas sales | 4 | % | 4 | % | 4 | % | ||
| Natural gas liquid sales | 8 | % | 7 | % | 5 | % | ||
| 100 | % | 100 | % | 100 | % |
Since our production consists primarily of oil, our revenues are more sensitive to fluctuations in oil prices than they are to fluctuations in natural gas liquids or natural gas prices. Oil, natural gas liquids and natural gas prices have historically been volatile. During 2017, WTI posted prices ranged from $42.48 to $60.46 per Bbl and the Henry Hub spot market price of natural gas ranged from $2.44 to $3.71 per MMBtu. On December 29, 2017, the WTI posted price for crude oil was $60.46 per Bbl and the Henry Hub spot market price of natural gas was $3.69 per MMBtu. Lower prices may not only decrease our revenues, but also potentially the amount of oil and natural gas that we can produce economically. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our credit agreement, which may be determined at the discretion of our lenders.
Principal components of our cost structure
Lease operating expenses. These are daily costs incurred to bring oil and natural gas out of the ground and to the market, together with the daily costs incurred to maintain our producing properties. Such costs also include maintenance, repairs and workover expenses related to our oil and natural gas properties.
Production and ad valorem taxes. Production taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. We are also subject to ad valorem taxes in the counties where our production is located. Ad valorem taxes are generally based on the valuation of our oil and gas properties.
General and administrative expenses. These are costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production and development operations, franchise taxes, audit and other fees for professional services and legal compliance.
Midstream services expense. These are costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.
Depreciation, depletion and amortization. Under the full cost accounting method, we capitalize costs within a cost center and then systematically expense those costs on a units of production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unproved properties and major development projects for which proved reserves cannot yet be assigned, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
Impairment of oil and natural gas properties. This is the cost to reduce proved oil and gas properties to the calculated full cost ceiling value.
Other income (expense)
Interest income (expense). We have financed a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our revolving credit facility and our net proceeds from the issuance of the senior notes. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. This amount reflects interest paid to our lender plus the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees net of interest received on our cash and cash equivalents.
Gain (loss) on derivative instruments, net. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in the price of crude oil. This amount represents (i) the recognition of the change in the fair value of open non-hedge derivative contracts as commodity prices change and commodity derivative contracts expire or new ones are entered into, and (ii) our gains and losses on the settlement of these commodity derivative instruments.
Deferred tax assets (liabilities). We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when 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 income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.
Results of Operations
The following table sets forth selected historical operating data for the periods indicated.
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| (in thousands) | |||||||||||
| Revenues | |||||||||||
| Oil, natural gas liquids and natural gas | $ | 1,186,275 | $ | 527,107 | $ | 446,733 | |||||
| Lease bonus | 11,764 | — | — | ||||||||
| Midstream services | 7,072 | — | — | ||||||||
| Total revenues | 1,205,111 | 527,107 | 446,733 | ||||||||
| Operating expenses | |||||||||||
| Lease operating expenses | 126,524 | 82,428 | 82,625 | ||||||||
| Production and ad valorem taxes | 73,505 | 34,456 | 32,990 | ||||||||
| Gathering and transportation | 12,834 | 11,606 | 6,091 | ||||||||
| Midstream services | 10,409 | — | — | ||||||||
| Depreciation, depletion and amortization | 326,759 | 178,015 | 217,697 | ||||||||
| Impairment of oil and natural gas properties | — | 245,536 | 814,798 | ||||||||
| General and administrative expenses | 48,669 | 42,619 | 31,968 | ||||||||
| Asset retirement obligation accretion | 1,391 | 1,064 | 833 | ||||||||
| Total expenses | 600,091 | 595,724 | 1,187,002 | ||||||||
| Income (loss) from operations | 605,020 | (68,617 | ) | (740,269 | ) | ||||||
| Interest expense, net | (40,554 | ) | (40,684 | ) | (41,510 | ) | |||||
| Other income, net | 10,235 | 3,064 | 728 | ||||||||
| Gain (loss) on derivative instruments, net | (77,512 | ) | (25,345 | ) | 31,951 | ||||||
| Loss on extinguishment of debt | — | (33,134 | ) | — | |||||||
| Total other expense, net | (107,831 | ) | (96,099 | ) | (8,831 | ) | |||||
| Income (loss) before income taxes | 497,189 | (164,716 | ) | (749,100 | ) | ||||||
| Provision for (benefit from) income taxes | (19,568 | ) | 192 | (201,310 | ) | ||||||
| Net income (loss) | 516,757 | (164,908 | ) | (547,790 | ) | ||||||
| Net income attributable to non-controlling interest | 34,496 | 126 | 2,838 | ||||||||
| Net income (loss) attributable to Diamondback Energy, Inc. | $ | 482,261 | $ | (165,034 | ) | $ | (550,628 | ) |
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Production Data: | |||||||||||
| Oil (MBbls) | 21,418 | 11,562 | 9,081 | ||||||||
| Natural gas (MMcf) | 20,660 | 10,728 | 7,931 | ||||||||
| Natural gas liquids (MBbls) | 4,056 | 2,399 | 1,678 | ||||||||
| Combined volumes (MBOE) | 28,917 | 15,749 | 12,081 | ||||||||
| Daily combined volumes (BOE/d) | 79,224 | 43,031 | 33,098 | ||||||||
| Average Prices: | |||||||||||
| Oil (per Bbl) | $ | 48.75 | $ | 40.70 | $ | 44.68 | |||||
| Natural gas (per Mcf) | 2.53 | 2.10 | 2.47 | ||||||||
| Natural gas liquids (per Bbl) | 22.20 | 14.20 | 12.77 | ||||||||
| Combined (per BOE) | 41.02 | 33.47 | 36.98 | ||||||||
| Oil, hedged ($ per Bbl)(1) | 48.94 | 40.80 | 60.63 | ||||||||
| Natural gas, hedged ($ per MMbtu)(1) | 2.65 | 2.06 | 2.47 | ||||||||
| Average price, hedged ($ per BOE)(1) | 41.26 | 33.54 | 48.97 | ||||||||
| Average Costs per BOE: | |||||||||||
| Lease operating expense | $ | 4.38 | $ | 5.23 | $ | 6.84 | |||||
| Production and ad valorem taxes | 2.54 | 2.19 | 2.73 | ||||||||
| Gathering and transportation expense | 0.44 | 0.74 | 0.50 | ||||||||
| General and administrative - cash component | 0.80 | 1.03 | 1.11 | ||||||||
| Total operating expense - cash | $ | 8.16 | $ | 9.19 | $ | 11.18 | |||||
| General and administrative - non-cash component | $ | 0.88 | $ | 1.68 | $ | 1.54 | |||||
| Depreciation, depletion and amortization | 11.30 | 11.30 | 18.02 | ||||||||
| Interest expense | 1.40 | 2.58 | 3.44 | ||||||||
| Total expenses | $ | 13.58 | $ | 15.56 | $ | 23.00 | |||||
| Average realized oil price ($/Bbl) | $ | 48.75 | $ | 40.70 | $ | 44.68 | |||||
| Average NYMEX ($/Bbl) | $ | 50.80 | $ | 43.29 | $ | 48.66 | |||||
| Differential to NYMEX | $ | (2.05 | ) | $ | (2.59 | ) | $ | (3.98 | ) | ||
| Average realized oil price to NYMEX | 96 | % | 94 | % | 92 | % | |||||
| Average realized natural gas price ($/Mcf) | $ | 2.53 | $ | 2.10 | $ | 2.47 | |||||
| Average NYMEX ($/Mcf) | $ | 2.99 | $ | 2.52 | $ | 2.62 | |||||
| Differential to NYMEX | $ | (0.46 | ) | $ | (0.42 | ) | $ | (0.15 | ) | ||
| Average realized natural gas price to NYMEX | 85 | % | 83 | % | 94 | % | |||||
| Average realized natural gas liquids price ($/Bbl) | $ | 22.20 | $ | 14.20 | $ | 12.77 | |||||
| Average NYMEX oil price ($/Bbl) | $ | 50.80 | $ | 43.29 | $ | 48.66 | |||||
| Average realized natural gas liquids price to NYMEX oil price | 44 | % | 33 | % | 26 | % |
| (1) | Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects include realized gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. |
Comparison of the Years Ended December 31, 2017 and 2016
Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $659.2 million, or 125%, to $1.2 billion for the year ended December 31, 2017 from $527.1 million for the year ended December 31, 2016. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 36,193 BOE/d to 79,224 BOE/d during the year ended December 31, 2017 from 43,031 BOE/d during the year ended December 31, 2016. The total increase in revenue of approximately $659.2 million is attributable to higher oil, natural gas liquids and natural gas production volumes and higher average sales prices for the year ended December 31, 2017 as compared to the year ended December 31, 2016. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 9,856 MBbls of oil, 1,656 MBbls of natural gas liquids and 9,931 MMcf of natural gas for the year ended December 31, 2017 as compared to the year ended December 31, 2016.
The net dollar effect of the increases in prices of approximately $213.7 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $445.4 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.
| Change in prices | Production volumes(1) | Total net dollar effect of change | |||||||||
| (in thousands) | |||||||||||
| Effect of changes in price: | |||||||||||
| Oil | $ | 8.05 | 21,418 | $ | 172,403 | ||||||
| Natural gas liquids | $ | 8.00 | 4,056 | $ | 32,446 | ||||||
| Natural gas | $ | 0.43 | 20,660 | $ | 8,884 | ||||||
| Total revenues due to change in price | $ | 213,733 | |||||||||
| Change in production volumes(1) | Prior period average prices | Total net dollar effect of change | |||||||||
| (in thousands) | |||||||||||
| Effect of changes in production volumes: | |||||||||||
| Oil | 9,856 | $ | 40.70 | $ | 401,080 | ||||||
| Natural gas liquids | 1,656 | $ | 14.20 | $ | 23,521 | ||||||
| Natural gas | 9,931 | $ | 2.10 | $ | 20,834 | ||||||
| Total revenues due to change in production volumes | $ | 445,435 | |||||||||
| Total change in revenues | $ | 659,168 |
| (1) | Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas. |
Lease Bonus Revenue. Lease bonus revenue was $11.8 million for the year ended December 31, 2017, $2.8 million of which was attributable to lease bonus payments to extend the term of seven leases, reflecting an average bonus of $3,442 per acre and the remaining $9.1 million was attributable to lease bonus payments on three new leases, reflecting an average bonus of $14,320 per acre. We had no lease bonus revenue for the year ended December 31, 2016.
Midstream Services Revenue. Midstream services revenue was $7.1 million for the year ended December 31, 2017. We had no midstream services revenue for the year ended December 31, 2016. Our midstream services revenue represents fees charged to our joint interest owners and third parties for the transportation of oil and natural gas along with water gathering and related disposal facilities. These assets complement our operations in areas where we have significant production.
Lease Operating Expenses. Lease operating expenses were $126.5 million ($4.38 per BOE) for the year ended December 31, 2017, an increase of $44.1 million from $82.4 million ($5.23 per BOE) for the year ended December 31, 2016. The increase in lease operating expense was due to an increase of 234 producing wells compared to 2016. This increase was offset by higher production volumes which resulted in a decrease in lease operating expense per BOE.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased to $73.5 million for the year ended December 31, 2017 from $34.5 million for the year ended December 31, 2016. In general, production taxes and ad valorem
taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. The increase in production and ad valorem taxes during the year ended December 31, 2017 as compared to 2016 was primarily due to an increase in our production taxes as a result of increased commodity prices and volumes.
Midstream Services Expense. Midstream services expense was $10.4 million for the year ended December 31, 2017. We had no midstream services expense for the year ended December 31, 2016. Midstream services expense represents costs incurred to operate and maintain our oil and natural gas gathering and transportation systems, natural gas lift, compression infrastructure and water transportation facilities.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $148.7 million, or 84%, from $178.0 million for the year ended December 31, 2016 to $326.8 million for the year ended December 31, 2017.
The following table provides components of our depreciation, depletion and amortization expense for the periods presented:
| Year Ended December 31, | |||||||
| 2017 | 2016 | ||||||
| (in thousands, except BOE amounts) | |||||||
| Depletion of proved oil and natural gas properties | $ | 321,870 | $ | 176,369 | |||
| Depreciation of midstream assets | 3,451 | 252 | |||||
| Depreciation of other property and equipment | 1,438 | 1,394 | |||||
| Depreciation, depletion and amortization expense | $ | 326,759 | $ | 178,015 | |||
| Oil and natural gas properties depreciation, depletion and amortization expense per BOE | $ | 11.11 | $ | 11.23 | |||
| Total depreciation, depletion and amortization expense per BOE | $ | 11.30 | $ | 11.30 |
The increase in depletion of proved oil and natural gas properties of $145.5 million for the year ended December 31, 2017 as compared to the year ended December 31, 2016 resulted primarily from higher production levels and an increase in net book value on new reserves added.
Impairment of Oil and Natural Gas Properties. During the year ended December 31, 2016, we recorded an impairment of oil and gas properties of $245.5 million as a result of the significant decline in commodity prices, which resulted in a reduction of the discounted present value of our proved oil and natural gas reserves. We did not record an impairment of oil and natural gas properties during the year ended December 31, 2017.
General and Administrative Expenses. General and administrative expenses increased $6.1 million from $42.6 million for the year ended December 31, 2016 to $48.7 million for the year ended December 31, 2017. The increase was due to an increase in salaries and benefits expense as a result of an increase in workforce.
Net Interest Expense. Net interest expense for the year ended December 31, 2017 was $40.6 million as compared to $40.7 million for the year ended December 31, 2016, a decrease of $0.1 million. This decrease was due primarily to the issuance in October 2016 of new senior notes due 2024 with a lower interest rate than the senior notes which we redeemed in the fourth quarter of 2016 partially offset by the interest on the additional senior notes due in 2025 that we issued in December 2016.
Gain (Loss) on Derivative Instruments, Net. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the years ended December 31, 2017 and 2016, we had a cash gain on settlement of derivative instruments of $6.7 million and $1.2 million, respectively. For the year ended December 31, 2017 and 2016, we had a negative change in the fair value of open derivative instruments of $84.2 million and $26.5 million, respectively.
Provision for (Benefit from) Income Taxes. We recorded an income tax benefit of $19.6 million for the year ended December 31, 2017 as compared to an income tax provision of $0.2 million for the year ended December 31, 2016. Our effective tax rate was (3.9)% for the year ended December 31, 2017 as compared to (0.1)% for the year ended December 31, 2016. The change in our income tax provision for the year ended December 31, 2017 as compared to the year ended December 31, 2016 is primarily due to the reduction in our valuation allowance against deferred tax assets, as well as the favorable impact of the
reduction in the federal statutory tax rate enacted in December 2017. While we generated positive pre-tax income from continuing operations in 2017, our 2017 effective tax rate was negative due to the income tax benefit generated by these items.
Comparison of the Years Ended December 31, 2016 and 2015
Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues increased by approximately $80.4 million, or 18%, to $527.1 million for the year ended December 31, 2016 from $446.7 million for the year ended December 31, 2015. Our revenues are a function of oil, natural gas liquids and natural gas production volumes sold and average sales prices received for those volumes. Average daily production sold increased by 9,933 BOE/d to 43,031 BOE/d during the year ended December 31, 2016 from 33,098 BOE/d during the year ended December 31, 2015. The total increase in revenue of approximately $80.4 million is largely attributable to higher oil, natural gas liquids and natural gas production volumes partially offset by lower average sales prices for the year ended December 31, 2016 as compared to the year ended December 31, 2015. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 2,481 MBbls of oil, 722 MBbls of natural gas liquids and 2,797 MMcf of natural gas for the year ended December 31, 2016 as compared to the year ended December 31, 2015.
The net dollar effect of the decreases in prices of approximately $46.6 million (calculated as the change in period-to-period average prices multiplied by current period production volumes of oil, natural gas liquids and natural gas) and the net dollar effect of the increase in production of approximately $126.9 million (calculated as the increase in period-to-period volumes for oil, natural gas liquids and natural gas multiplied by the period average prices) are shown below.
| Change in prices | Production volumes(1) | Total net dollar effect of change | |||||||||
| (in thousands) | |||||||||||
| Effect of changes in price: | |||||||||||
| Oil | $ | (3.98 | ) | 11,562 | $ | (46,031 | ) | ||||
| Natural gas liquids | $ | 1.43 | 2,399 | $ | 3,431 | ||||||
| Natural gas | $ | (0.37 | ) | 10,728 | $ | (3,970 | ) | ||||
| Total revenues due to change in price | $ | (46,570 | ) | ||||||||
| Change in production volumes(1) | Prior period average prices | Total net dollar effect of change | |||||||||
| (in thousands) | |||||||||||
| Effect of changes in production volumes: | |||||||||||
| Oil | 2,481 | $ | 44.68 | $ | 110,815 | ||||||
| Natural gas liquids | 722 | $ | 12.77 | $ | 9,219 | ||||||
| Natural gas | 2,797 | $ | 2.47 | $ | 6,910 | ||||||
| Total revenues due to change in production volumes | $ | 126,944 | |||||||||
| Total change in revenues | $ | 80,374 |
| (1) | Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas. |
Lease Operating Expenses. Lease operating expenses were $82.4 million ($5.23 per BOE) for the year ended December 31, 2016, a decrease of $0.2 million from $82.6 million ($6.84 per BOE) for the year ended December 31, 2015. The decrease is a result of efficiencies we achieved in our field operations. Upon becoming the operator of wells acquired in our acquisitions, we seek to achieve the efficiencies in those wells that we have established with our existing portfolio of wells.
Production and Ad Valorem Taxes. Production and ad valorem taxes increased to $34.5 million for the year ended December 31, 2016 from $33.0 million for the year ended December 31, 2015. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. The increase in production and ad valorem taxes during the year ended December 31, 2016 as compared to 2015 was primarily due to an increase in our production taxes as a result of increased production partially offset by lower ad valorem taxes.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $39.7 million, or 18%, from $217.7 million for the year ended December 31, 2015 to $178.0 million for the year ended December 31, 2016.
The following table provides components of our depreciation, depletion and amortization expense for the periods presented:
| Year Ended December 31, | |||||||
| 2016 | 2015 | ||||||
| (in thousands, except BOE amounts) | |||||||
| Depletion of proved oil and natural gas properties | $ | 176,369 | $ | 216,056 | |||
| Depreciation of midstream assets | 252 | 239 | |||||
| Depreciation of other property and equipment | 1,394 | 1,402 | |||||
| Depreciation, depletion and amortization expense | $ | 178,015 | $ | 217,697 | |||
| Oil and natural gas properties depreciation, depletion and amortization expense per BOE | $ | 11.23 | $ | 17.84 | |||
| Total depreciation, depletion and amortization expense per BOE | $ | 11.30 | $ | 18.02 |
The decreases in depletion of proved oil and natural gas properties of $39.7 million for the year ended December 31, 2016 as compared to the year ended December 31, 2015 resulted primarily from the impairment of oil and gas properties recorded in 2016.
Impairment of Oil and Natural Gas Properties. During the years ended December 31, 2016 and 2015, we recorded impairments of oil and gas properties of $245.5 million and $814.8 million, respectively, as a result of the significant decline in commodity prices, which resulted in a reduction of the discounted present value of our proved oil and natural gas reserves.
General and Administrative Expenses. General and administrative expenses increased $10.7 million from $32.0 million for the year ended December 31, 2015 to $42.6 million for the year ended December 31, 2016. The increase was due to increases in salaries and benefits expense as a result of an increase in workforce and equity-based compensation.
Net Interest Expense. Net interest expense for the year ended December 31, 2016 was $40.7 million as compared to $41.5 million for the year ended December 31, 2015, a decrease of $0.8 million. This decrease was due primarily to the lower average level of outstanding borrowings under our credit facility during 2016.
Gain (Loss) on Derivative Instruments, Net. We are required to recognize all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned “Gain (loss) on derivative instruments, net.” For the years ended December 31, 2016 and 2015, we had a cash gain on settlement of derivative instruments of $1.2 million and $144.9 million, respectively. For the year ended December 31, 2016 and 2015, we had a negative change in the fair value of open derivative instruments of $26.5 million and $112.9 million, respectively.
Provision for (Benefit from) Income Taxes. We recorded an income tax expense of $0.2 million for the year ended December 31, 2016 as compared to an income tax benefit of $201.3 million for the year ended December 31, 2015. Our effective tax rate was (0.1%) for the year ended December 31, 2016 as compared to 26.9% for the year ended December 31, 2015.
Liquidity and Capital Resources
Our primary sources of liquidity have been proceeds from our public equity offerings, borrowings under our revolving credit facility, proceeds from the issuance of the senior notes and cash flows from operations. Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. As we pursue reserves and production growth, we regularly consider which capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. Our future ability to grow proved reserves and production will be highly dependent on the capital resources available to us.
Liquidity and Cash Flow
Our cash flows for the years ended December 31, 2017, 2016 and 2015 are presented below:
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| (in thousands) | |||||||||||
| Net cash provided by operating activities | $ | 888,625 | $ | 332,080 | $ | 416,501 | |||||
| Net cash used in investing activities | (3,132,282 | ) | (1,310,242 | ) | (895,050 | ) | |||||
| Net cash provided by financing activities | $ | 689,529 | $ | 2,624,621 | $ | 468,481 | |||||
| Net change in cash | $ | (1,554,128 | ) | $ | 1,646,459 | $ | (10,068 | ) |
Operating Activities
Net cash provided by operating activities was $888.6 million for the year ended December 31, 2017 as compared to $332.1 million for the year ended December 31, 2016. The increase in operating cash flows is primarily the result of an increase in our oil and natural gas revenues due to an increase in average prices and production growth during the year ended December 31, 2017.
Net cash provided by operating activities was $332.1 million for the year ended December 31, 2016 as compared to $416.5 million for the year ended December 31, 2015. The decrease in operating cash flows is primarily the result of a higher gain on settlement of derivative instruments during the year ended December 31, 2015 as compared to the year ended December 31, 2016.
Our operating cash flow is sensitive to many variables, the most significant of which is the volatility of prices for the oil and natural gas we produce. Prices for these commodities are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. See “–Sources of our revenue” and Item 1A. “Risk Factors” above.
Investing Activities
The purchase and development of oil and natural gas properties accounted for the majority of our cash outlays for investing activities. We used cash for investing activities of $3.1 billion, $1.3 billion and $895.1 million during the years ended December 31, 2017, 2016 and 2015, respectively.
During the year ended December 31, 2017, we spent (a) $860.7 million on capital expenditures in conjunction with our drilling program, in which we drilled 150 gross (130 net) horizontal wells and participated in the drilling of 16 gross (two net) non-operated wells, (b) $68.1 million on additions to midstream assets, (c) $407.5 million for the acquisition of mineral interests, (d) $1,960.6 million on leasehold acquisitions, (e) $50.3 million for the acquisition of midstream assets and (f) $22.8 million for the purchase of other property and equipment.
During the year ended December 31, 2016, we spent (a) $364.3 million on capital expenditures in conjunction with our drilling program, in which we drilled 73 gross (61 net) horizontal wells and two gross (one net) vertical wells and participated in the drilling of 19 gross (five net) non-operated wells, (b) $611.3 million on leasehold acquisitions, (c) $205.7 million on royalty interest acquisitions, (d) $9.9 million for the purchase of other property and equipment and (e) $121.4 million was placed in escrow as a deposit under the purchase agreement for oil and natural gas assets located in Pecos and Reeves counties in Texas.
During the year ended December 31, 2015, we spent (a) $419.5 million on capital expenditures in conjunction with our drilling program, in which we drilled 64 gross (54 net) horizontal wells and four gross (three net) vertical wells and participated in the drilling of 15 gross (six net) non-operated wells, (b) $437.5 million on leasehold acquisitions, (c) $43.9 million on royalty interest acquisitions and (d) $1.2 million for the purchase of other property and equipment.
Our investing activities for the years ended December 31, 2017, 2016 and 2015 are summarized in the following table:
| Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| (in thousands) | |||||||||||
| Drilling, completion and infrastructure | $ | (860,738 | ) | $ | (363,087 | ) | $ | (419,512 | ) | ||
| Additions to midstream assets | (68,139 | ) | (1,188 | ) | — | ||||||
| Acquisition of leasehold interests | (1,960,591 | ) | (611,280 | ) | (437,455 | ) | |||||
| Acquisition of mineral interests | (407,450 | ) | (205,721 | ) | (43,907 | ) | |||||
| Acquisition of midstream assets | (50,279 | ) | — | — | |||||||
| Purchase of other property and equipment | (22,779 | ) | (9,891 | ) | (1,213 | ) | |||||
| Proceeds from sale of property and equipment | 65,656 | 4,661 | 9,739 | ||||||||
| Funds held in escrow | 104,087 | (121,391 | ) | — | |||||||
| Equity investments | (188 | ) | (2,345 | ) | (2,702 | ) | |||||
| Net cash used in investing activities | $ | (3,200,421 | ) | $ | (1,310,242 | ) | $ | (895,050 | ) |
Financing Activities
Net cash provided by financing activities for the years ended December 31, 2017, 2016 and 2015 was $689.5 million, $2.6 billion and $468.5 million, respectively.
During the year ended December 31, 2017, the amount provided by financing activities was primarily attributable to proceeds from Viper’s January and July 2017 equity offerings of $370.3 million as well as borrowings net of repayments of $370.0 million partially offset by distributions to non-controlling interests of $41.4 million.
During the year ended December 31, 2016, the amount provided by financing activities was primarily attributable to the aggregate proceeds of $2.1 billion from our January, July and December 2016 equity offerings partially offset by repayments of net borrowings of $75.0 million under our credit facility.
During the year ended December 31, 2015, the amount provided by financing activities was primarily attributable to the aggregate proceeds of $650.7 million from our January, May and August 2015 equity offerings of $650.7 million partially offset by repayments of net borrowings of $184.5 million under our credit facility.
2024 Senior Notes
On October 28, 2016, we issued $500.0 million in aggregate principal amount of 4.750% senior notes due 2024, which we refer to as the 2024 senior notes. The 2024 senior notes bear interest at a rate of 4.750% per annum, payable semi-annually, in arrears on May 1 and November 1 of each year, commencing on May 1, 2017 and will mature on November 1, 2024. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the 2024 senior notes; provided, however, that the 2024 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of the our future unrestricted subsidiaries.
The 2024 senior notes were issued under, and are governed by, an indenture among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee, as supplemented. The 2024 indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.
We may on any one or more occasions redeem some or all of the 2024 senior notes at any time on or after November 1, 2019 at the redemption prices (expressed as percentages of principal amount) of 103.563% for the 12-month period beginning
on November 1, 2019, 102.375% for the 12-month period beginning on November 1, 2020, 101.188% for the 12-month period beginning on November 1, 2021 and 100.000% beginning on November 1, 2022 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to November 1, 2019, we may on any one or more occasions redeem all or a portion of the 2024 senior notes at a price equal to 100% of the principal amount of the 2024 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to November 1, 2019, we may on any one or more occasions redeem the 2024 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2024 senior notes issued prior to such date at a redemption price of 104.750%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.
2025 Senior Notes
On December 20, 2016, we issued $500.0 million in aggregate principal amount of 5.375% senior notes due 2025, which we refer to as the exiting 2025 notes, under an indenture (which, as may be amended or supplemented from time to time, is referred to as the 2025 Indenture) among us, the subsidiary guarantors party thereto and Wells Fargo, as the trustee. On July 27, 2017, we exchanged all of the existing 2025 notes for substantially identical notes in the same aggregate principal amount that were registered under the Securities Act.
On January 29, 2018, we issued $300.0 million aggregate principal amount of new 5.375% senior notes due 2025, which we refer to as the new 2025 notes, as additional notes under the 2025 Indenture. The new 2025 notes were issued in a transaction exempt from the registration requirements under the Securities Act. We refer to the new 2025 notes, together with the existing 2025 notes, as the 2025 senior notes. We received approximately $308.4 million in net proceeds, after deducting the initial purchaser’s discount and our estimated offering expenses, but disregarding accrued interest, from the issuance of the new 2025 notes. We used the net proceeds from the issuance of the new 2025 notes to repay a portion of the outstanding borrowings under our revolving credit facility.
The 2025 senior notes bear interest at a rate of 5.375% per annum, payable semi-annually, in arrears on May 31 and November 30 of each year and will mature on May 31, 2025. All of our existing and future restricted subsidiaries that guarantee our revolving credit facility or certain other debt guarantee the 2025 senior notes; provided, however, that the 2025 senior notes are not guaranteed by Viper, Viper Energy Partners GP LLC, Viper Energy Partners LLC or Rattler Midstream LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.
The 2025 Indenture contains certain covenants that, subject to certain exceptions and qualifications, among other things, limit our ability and the ability of the restricted subsidiaries to incur or guarantee additional indebtedness, make certain investments, declare or pay dividends or make other distributions on capital stock, prepay subordinated indebtedness, sell assets including capital stock of restricted subsidiaries, agree to payment restrictions affecting our restricted subsidiaries, consolidate, merge, sell or otherwise dispose of all or substantially all of our assets, enter into transactions with affiliates, incur liens, engage in business other than the oil and natural gas business and designate certain of our subsidiaries as unrestricted subsidiaries.
We may on any one or more occasions redeem some or all of the 2025 senior notes at any time on or after May 31, 2020 at the redemption prices (expressed as percentages of principal amount) of 104.031% for the 12-month period beginning on May 31, 2020, 102.688% for the 12-month period beginning on May 31, 2021, 101.344% for the 12-month period beginning on May 31, 2022 and 100.000% beginning on May 31, 2023 and at any time thereafter with any accrued and unpaid interest to, but not including, the date of redemption. Prior to May 31, 2020, we may on any one or more occasions redeem all or a portion of the 2025 senior notes at a price equal to 100% of the principal amount of the 2025 senior notes plus a “make-whole” premium and accrued and unpaid interest to the redemption date. In addition, any time prior to May 31, 2020, we may on any one or more occasions redeem the 2025 senior notes in an aggregate principal amount not to exceed 35% of the aggregate principal amount of the 2025 senior notes issued prior to such date at a redemption price of 105.375%, plus accrued and unpaid interest to the redemption date, with an amount equal to the net cash proceeds from certain equity offerings.
Under a registration rights agreement executed in connection with the issuance of the new 2025 notes, we and our subsidiary guarantors agreed to file, subject to certain conditions, a registration statement relating to the new 2025 notes with the SEC pursuant to which we will either offer to exchange the new 2025 notes for registered notes with substantially identical terms or, in certain circumstances, register the resale of the new 2025 notes. Additional interest on the new 2025 notes may become payable if we do not comply with our obligations under the registration rights agreement relating to the new 2025 notes.
Second Amended and Restated Credit Facility
Our credit agreement dated November 1, 2013, as amended and restated, with a syndicate of banks, including Wells Fargo, as administrative agent, and its affiliate Wells Fargo Securities, LLC, as sole book runner and lead arranger, provides for
a revolving credit facility in the maximum credit amount of $5.0 billion, subject to a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”). The borrowing base is scheduled to be redetermined, under certain circumstances, annually with an effective date of May 1st, and, under certain circumstances, semi-annually with effective dates of May 1st and November 1st. In addition, we may request up to two additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $1.8 billion, we had elected a commitment amount of $1.0 billion and we had borrowings of $397.0 million outstanding under the revolving credit facility. Of this amount, we repaid $308.5 million with the net proceeds from our issuance of the new 2025 notes on January 29, 2018. Immediately following the completion of the new 2025 notes offering and the application of our net proceeds thereof, our borrowing base remained $1.8 billion (as the lenders waived the borrowing base decrease under our revolving credit facility in connection with the issuance of the new 2025 notes), our elected commitment was $1.0 billion, and we had $911.4 million of available borrowing capacity under our revolving credit facility.
Diamondback O&G LLC is the borrower under our credit agreement. As of December 31, 2017, the credit agreement is guaranteed by us, Diamondback E&P LLC and Rattler Midstream LLC (formerly known as White Fang Energy LLC) and will also be guaranteed by any of our future subsidiaries that are classified as restricted subsidiaries under the credit agreement. The credit agreement is also secured by substantially all of our assets and the assets of Diamondback O&G LLC and the guarantors.
The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.25% to 1.25% in the case of the alternative base rate and from 1.25% to 2.25% in the case of LIBOR, each of which applicable margin rates is increased by 0.25% per annum if the total debt to EBITDAX ratio is greater than 3.0 to 1.0. The applicable margin depends on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the least of the maximum credit amount, the borrowing base and the elected commitment amount. 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, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022.
The 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 and require the maintenance of the financial ratios described below.
| Financial Covenant | Required Ratio |
| Ratio of total debt to EBITDAX | Not greater than 3.0 to 1.0 |
| Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
The covenant prohibiting additional indebtedness, as amended in November 2017, allows for the issuance of unsecured debt in the form of senior or senior subordinated notes if no default would result from the incurrence of such debt after giving effect thereto and if, in connection with any such issuance, the borrowing base is reduced by 25% of the stated principal amount of each such issuance.
As of December 31, 2017, we were in compliance with all financial covenants under our revolving credit facility. The lenders may accelerate all of the indebtedness under our revolving credit facility upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change of control. With certain specified exceptions, the terms and provisions of our revolving credit facility generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.
Viper’s Facility-Wells Fargo Bank
On July 8, 2014, Viper entered into a secured revolving credit agreement with Wells Fargo, as administrative agent, and Wells Fargo Securities, as sole book runner and lead arranger. The credit agreement, as amended, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base based on our oil and natural gas reserves and other factors (the “borrowing base”) of $400.0 million, subject to scheduled semi-annual and other elective borrowing base redeterminations. The borrowing base is scheduled to be re-determined semi-annually with effective dates of May 1st and November 1st. In addition, Viper may request up to three additional redeterminations of the borrowing base during any 12-month period. As of December 31, 2017, the borrowing base was set at $400.0 million, and Viper had $93.5 million of outstanding borrowings and $306.5 million available for future borrowings under its revolving credit facility.
The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by Viper that is equal to an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.75% to 1.75% per annum in the case of the alternate base rate and from 1.75% to 2.75% per annum in the case of LIBOR, in each case depending on the amount of loans and letters of credit outstanding in relation to the commitment, which is defined as the lesser of the maximum credit amount and the borrowing base. Viper is obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment, which fee is also dependent on the amount of loans and letters of credit outstanding in relation to the commitment. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be repaid (a) to the extent the loan amount exceeds the commitment or the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period), (b) in an amount equal to the net cash proceeds from the sale of property when a borrowing base deficiency or event of default exists under the credit agreement and (c) at the maturity date of November 1, 2022. The loan is secured by substantially all of Viper and its subsidiary’s assets.
The 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 and require the maintenance of the financial ratios described below.
| Financial Covenant | Required Ratio |
| Ratio of total debt to EBITDAX | Not greater than 4.0 to 1.0 |
| Ratio of current assets to liabilities, as defined in the credit agreement | Not less than 1.0 to 1.0 |
The covenant prohibiting additional indebtedness allows for the issuance of unsecured debt of up to $400.0 million in the form of senior unsecured notes and, in connection with any such issuance, the reduction of the borrowing base by 25% of the stated principal amount of each such issuance. A borrowing base reduction in connection with such issuance may require a portion of the outstanding principal of the loan to be repaid.
The lenders may accelerate all of the indebtedness under Viper’s revolving credit facility upon the occurrence and during the continuance of any event of default. Viper’s 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.
Capital Requirements and Sources of Liquidity
Our board of directors approved a 2018 capital budget for drilling and infrastructure of $1.3 billion to $1.5 billion, representing an increase of 60% over our 2017 capital budget. We estimate that, of these expenditures, approximately:
| • | $1.175 billion to $1.325 billion will be spent on drilling and completing 170 to 190 gross (146 to 163 net) horizontal wells across our operated leasehold acreage in the Northern Midland and Southern Delaware Basins; and |
| • | $125.0 million to $175.0 million will be spent on infrastructure and other expenditures, excluding the cost of any leasehold and mineral interest acquisitions. |
During the year ended December 31, 2017, our aggregate capital expenditures for drilling and infrastructure were $860.7 million. We do not have a specific acquisition budget since the timing and size of acquisitions cannot be accurately
forecasted. During the year ended December 31, 2017, we spent approximately $2.0 billion on acquisitions of leasehold interests, primarily related to the Brigham Resources acquisition which closed on February 28, 2017.
The amount and timing of these capital expenditures are largely discretionary and within our control. 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 and natural gas, 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 interest owners. With recent improvement in oil prices, we are currently operating ten horizontal rigs and four completion crews. We will continue monitoring commodity prices and overall market conditions and can adjust our rig cadence up or down in response to changes in commodity prices and overall market conditions.
Based upon current oil and natural gas price and production expectations for 2018, we believe that our cash flow from operations and borrowings under our revolving credit facility will be sufficient to fund our operations through year-end 2018. However, future cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and significant additional capital expenditures will be required to more fully develop our properties. Further, our 2018 capital expenditure budget does not allocate any funds for leasehold and mineral interest acquisitions.
We monitor and adjust our projected capital expenditures in response to success or lack of success in drilling activities, changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, contractual obligations, internally generated cash flow and other factors both within and outside our control. If we require additional capital, we may seek such capital through traditional reserve base borrowings, joint venture partnerships, production payment financing, asset sales, offerings of debt and or equity securities or other means. We cannot assure you that the needed capital will be available on acceptable terms or at all. If we are unable to obtain funds when needed or on acceptable terms, we may be required to curtail our drilling programs, which could result in a loss of acreage through lease expirations. In addition, we may not be able to complete acquisitions that may be favorable to us or finance the capital expenditures necessary to replace our reserves. Further, if the decline in commodity prices continue, our revenues, cash flows, results of operations, liquidity and reserves may be materially and adversely affected.
Contractual Obligations
The following table summarizes our contractual obligations and commitments as of December 31, 2017:
| Payments Due by Period | |||||||||||||||||||
| 2018 | 2019-2020 | 2021-2022 | Thereafter | Total | |||||||||||||||
| (in thousands) | |||||||||||||||||||
| Secured revolving credit facility(1) | $ | — | $ | — | $ | 397,000 | $ | — | $ | 397,000 | |||||||||
| Interest expense related to the secured revolving credit facility | 2,261 | 10,522 | 7,144 | — | $ | 19,927 | |||||||||||||
| Senior notes | — | — | — | 1,000,000 | $ | 1,000,000 | |||||||||||||
| Interest expense related to the senior notes(2) | 50,625 | 101,250 | 101,250 | 108,475 | $ | 361,600 | |||||||||||||
| Viper's secured revolving credit facility(1) | — | — | 93,500 | — | $ | 93,500 | |||||||||||||
| Interest and commitment fees under Viper's credit agreement(3) | 1,149 | 2,299 | 2,107 | — | $ | 5,555 | |||||||||||||
| Asset retirement obligations (4) | 1,163 | — | — | 20,122 | $ | 21,285 | |||||||||||||
| Drilling commitments(5) | 21,882 | 10,082 | — | — | $ | 31,964 | |||||||||||||
| Sand supply agreements | — | 18,000 | 18,000 | 9,000 | $ | 45,000 | |||||||||||||
| Operating lease obligations(6) | 3,581 | 6,234 | 4,648 | 7,973 | $ | 22,436 | |||||||||||||
| Fasken Center office building7) | 99,000 | — | — | — | $ | 99,000 | |||||||||||||
| $ | 179,661 | $ | 148,387 | $ | 623,649 | $ | 1,145,570 | $ | 2,097,267 |
| (1) | Includes the outstanding principal amount under the revolving credit facilities, the table does not include interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged. |
| (2) | Interest represents the scheduled cash payments on the senior notes. |
| (3) | Includes only the minimum amount of interest and commitment fees due which, as of December 31, 2017, includes a commitment fee equal to 0.375% per year of the unused portion of the borrowing base of Viper’s credit agreement. |
| (4) | Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to |
future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See Note 6 of the notes to our consolidated financial statements set forth in Part IV, Item 15 of this Form 10-K.
| (5) | Drilling commitments represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2017. |
| (6) | Operating lease obligations represent future commitments for building and vehicle leases. |
| (7) | Fasken Center office buildings represents the amount we paid on January 31, 2018 at the closing of this transaction. The Fasken building contains our corporate offices. |
Critical Accounting Policies
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Below, we have provided expanded discussion of our more significant accounting policies, estimates and judgments. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our financial statements. See Note 2 of the Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.
Use of Estimates
Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Actual results could differ from those estimates.
We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas properties, asset retirement obligations, the fair value determination of acquired assets and liabilities, equity-based compensation, fair value estimates of commodity derivatives and estimates of income taxes.
Method of accounting for oil and natural gas properties
We account for our oil and natural gas producing activities using the full cost method of accounting. Accordingly, all costs incurred in the acquisition, exploration and development of proved oil and natural gas properties, including the costs of abandoned properties, dry holes, geophysical costs and annual lease rentals are capitalized. We also capitalize direct operating costs for services performed with internally owned drilling and well servicing equipment. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs unrelated to drilling activities are expensed as incurred. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded unless the ratio of cost to proved reserves would significantly change. Income from services provided to working interest owners of properties in which we also own an interest, to the extent they exceed related costs incurred, are accounted for as reductions of capitalized costs of oil and natural gas properties. Depletion of evaluated oil and natural gas properties is computed on the units of production method, whereby capitalized costs plus estimated future development costs are amortized over total proved reserves.
Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. We assess all items classified as unevaluated property on an annual basis for possible impairment. We assess properties on an individual basis or as a group if properties are individually insignificant. The assessment includes consideration of the following factors, among others: intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; the assignment of proved reserves; and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization.
Oil and natural gas reserve quantities and standardized measure of future net revenue
Our independent engineers and technical staff prepare our estimates of oil and natural gas reserves and associated future net revenues. The SEC has defined proved reserves as the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. The process of estimating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates. If such changes are material, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Revenue recognition
Oil and natural gas revenues are recorded when title passes to the purchaser, net of royalty interests, discounts and allowances, as applicable. We account for oil and natural gas production imbalances using the sales method, whereby a liability is recorded when our volumes exceed our estimated remaining recoverable reserves. No receivables are recorded for those wells where we have taken less than our ownership share of production. We did not have any gas imbalances as of December 31, 2017, 2016 and 2015. Revenues from oil and natural gas services are recognized as services are provided.
Impairment
We use the full cost method of accounting for our oil and natural gas properties. Under this method, all acquisition, exploration and development costs, including certain internal costs, are capitalized and amortized on a composite unit of production method based on proved oil, natural gas liquids and natural gas reserves. Internal costs capitalized to the full cost pool represent management’s estimate of costs incurred directly related to exploration and development activities such as geological and other administrative costs associated with overseeing the exploration and development activities. All internal costs not directly associated with exploration and development activities were charged to expense as they were incurred. Costs associated with unevaluated properties are excluded from the full cost pool until we have made a determination as to the existence of proved reserves. The inclusion of our unevaluated costs into the amortization base is expected to be completed within three to five years. Sales of oil and natural gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil, natural gas liquids and natural gas.
Under this method of accounting, we are required to perform a ceiling test each quarter. The test determines a limit, or ceiling, on the book value of the proved oil and natural gas properties. Net capitalized costs are limited to the lower of unamortized cost net of deferred income taxes, or the cost center ceiling. The cost center ceiling is defined as the sum of (a) estimated future net revenues, discounted at 10% per annum, from proved reserves, based on the trailing 12-month unweighted average of the first-day-of-the-month price, adjusted for any contract provisions and excluding the estimated abandonment costs for properties with asset retirement obligations recorded on the balance sheet, (b) the cost of properties not being amortized, if any, and (c) the lower of cost or market value of unproved properties included in the cost being amortized, including related deferred taxes for differences between the book and tax basis of the oil and natural gas properties. If the net book value, including related deferred taxes, exceeds the ceiling, an impairment or non-cash writedown is required.
Asset retirement obligations
We measure the future cost to retire our tangible long-lived assets and recognize such cost as a liability for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction or normal operation of a long-lived asset. The fair value of a liability for an asset’s retirement obligation is recorded in the period in which it is incurred if a reasonable estimate of fair value can be made and the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, the difference is recorded in oil and natural gas properties.
Our asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to the oil and natural gas property balance.
Derivatives
From time to time, we have used energy derivatives for the purpose of mitigating the risk resulting from fluctuations in the market price of crude oil and natural gas. We recognize all of our derivative instruments as either assets or liabilities at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and further on the type of hedging relationship. None of our derivatives were designated as hedging instruments during the years ended December 31, 2017, 2016 and 2015. For derivative instruments not designated as hedging instruments, changes in the fair value of these instruments are recognized in earnings during the period of change.
Accounting for Equity-Based Compensation
We grant various types of equity-based awards including stock options and restricted stock units. These plans and related accounting policies are defined and described more fully in Note 10–Equity-Based Compensation. Stock compensation awards are measured at fair value on the date of grant and are expensed, net of estimated forfeitures, over the required service period.
Income Taxes
We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when 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 income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.
Recent Accounting Pronouncements
Recently Issued Pronouncements
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. This update supersedes most of the existing revenue recognition requirements in GAAP and requires (i) an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for those goods or services and (ii) requires expanded disclosures regarding the nature, amount, timing and certainty of revenue and cash flows from contracts with customers.
We will adopt this Accounting Standards Update effective January 1, 2018 using the modified retrospective approach. We have reviewed various contracts that represent our material revenue streams and determined that there will be no impact to our financial position, results of operations or liquidity. Upon adoption of this Accounting Standards Update, we will not be required to record a cumulative effect adjustment due to the new Accounting Standards Update not having a quantitative impact compared to existing GAAP. Also, upon adoption of this Accounting Standards Update, we will not be required to alter our existing information technology and internal controls outside of ongoing contract review processes in order to identify impacts of future revenue contracts entered into by us. We do not anticipate the disclosure requirements under the Accounting Standards Update to have a material change on how we present information regarding our revenue streams as compared to existing GAAP.
In January 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-01, “Financial Instruments–Overall”. This update applies to any entity that holds financial assets or owes financial liabilities. This update
requires equity investments (except for those accounted for under the equity method or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. Viper will adopt this standard effective January 1, 2018 by means of a cumulative-effect adjustment which will decrease Viper’s Unitholders’ Equity and will bring the fair value of its investment to $15.2 million or $15.20 per unit for that investment.
In August 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-15, “Statement of Cash Flows - Classification of Certain Cash Receipts and Cash Payments”. This update apples to all entities that are required to present a statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions and separately identifiable cash flows and application of the predominance principle. We will adopt this update effective January 1, 2018 using the retrospective transition method. Adoption of this standard will change the presentation of our cash flows and will not have a material impact on our consolidated financial statements.
In November 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-18, “Statement of Cash Flows - Restricted Cash”. This update affects entities that have restricted cash or restricted cash equivalents. We adopted this update retrospectively effective January 1, 2018. Adoption of this standard will change the presentation of our cash flows and will not have a material impact on our consolidated financial statements.
In January 2017, the Financial Accounting Standards Board issued Accounting Standards Update 2017-01, “Business Combinations - Clarifying the Definition of a Business”. This update apples to all entities that must determine whether they acquired or sold a business. This update provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. We will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on our financial position, results of operations or liquidity.
Accounting Pronouncements Not Yet Adopted
In February 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-02, “Leases”. This update applies to any entity that enters into a lease, with some specified scope exemptions. Under this update, a lessee should recognize in the statement of financial position a liability to make lease payments (the lease liability) and a right-of-use asset representing its right to use the underlying asset for the lease term. While there were no major changes to the lessor accounting, changes were made to align key aspects with the revenue recognition guidance. This update will be effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted. Entities will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. We believe the primary impact of adopting this standard will be the recognition of assets and liabilities on our balance sheet for current operating leases. We are still evaluating the impact of this standard.
In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard will have a material impact on our consolidated financial statements since we do not have a history of credit losses.
Inflation
Inflation in the United States has been relatively low in recent years and did not have a material impact on results of operations for the years ended December 31, 2017, 2016 and 2015. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and we tend to experience inflationary pressure on the cost of oilfield services and equipment as increasing oil and gas prices increase drilling activity in our areas of operations.
Off-balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2017. Please read Note 15 included in Notes to the Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K, for a discussion of our commitments and contingencies, some of which are not recognized in the balance sheets under GAAP.
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