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, | ||||||||
| 2016 | 2015 | 2014 | ||||||
| Oil (Bbls) | 73 | % | 75 | % | 76 | % | ||
| Natural gas (Mcf) | 11 | % | 11 | % | 10 | % | ||
| Natural gas liquids (Bbls) | 16 | % | 14 | % | 14 | % | ||
| 100 | % | 100 | % | 100 | % |
On December 31, 2016, our net acreage position in the Permian Basin was approximately 105,894 net acres.
2016 Transactions and Recent Developments
Our Equity Offerings
In January 2016, we completed an underwritten public offering of 4,600,000 shares of common stock, which included 600,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriter. The stock was sold to the underwriter at $55.33 per share and we received proceeds of approximately $254.5 million from the sale of these shares of common stock, net of offering expenses and underwriting discounts and commissions, which we used to repay the borrowings outstanding under our revolving credit facility and to fund a portion of our exploration and development activities and for general corporate purposes.
In July 2016, we completed an underwritten public offering of 6,325,000 shares of common stock, which included 825,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the underwriters at $87.24 per share and we received proceeds of approximately $551.8 million from the sale of these shares of common stock, net of estimated offering expenses and underwriting discounts and commissions, which we used to fund a portion of the purchase price for the acquisition of certain leasehold interests and related assets in the Southern Delaware Basin.
In December 2016, we completed an underwritten public offering of 12,075,000 shares of common stock, which included 1,575,000 shares of common stock issued pursuant to an option to purchase additional shares granted to the underwriters. The stock was sold to the underwriters at $95.3025 per share and we received proceeds of approximately $1,150.8 million from the sale of these shares of common stock, net of estimated offering expenses and underwriting discounts and commissions. We intend to use these net proceeds, together with the net proceeds from our offering of the 2025 senior notes, cash on hand and other financing sources, to fund the cash consideration for the Pending Acquisition.
Viper’s Equity Offerings
In August 2016, Viper completed an underwritten public offering of 8,050,000 common units, which included 1,050,000 common units issued pursuant to an option to purchase additional common units granted to the underwriter. In this offering, we purchased 2,000,000 common units from the underwriter at $15.60 per unit, which is the price per common unit paid by the underwriter to Viper. Following this public offering, we had an approximate 83% limited partner interest in Viper. Viper received proceeds from this offering of approximately $125.0 million, net of estimated offering expenses and underwriting discounts and commissions, which Viper used to repay outstanding borrowings under Viper’s revolving credit facility and fund the acquisition of mineral interests.
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. Following the January 2017 public offering, we had an approximate 74% limited partner interest in Viper. Viper received net proceeds from this offering of approximately $147.6 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 intends to use the remaining net proceeds for general partnership purposes, which may include additional acquisitions.
Senior Note Transactions
On October 28, 2016, we completed an offering of $500.0 million in aggregate principal amount of our 4.75% senior notes due 2024, which we refer to as the 2024 senior notes. We received approximately $496.0 million in net proceeds from the offering of the 2024 senior notes, which were used primarily to repurchase all of our outstanding 7.625% senior notes due 2021, which we refer to as the 2021 senior notes, accepted for purchase in a related tender offer, to pay fees and expenses thereof and to redeem the 2021 senior notes that remained outstanding after completion of the tender offer discussed below. We intend to use the remaining net proceeds from the offering of the 2024 senior notes for general corporate purposes, which may include the funding of a portion of the our capital development plans.
On October 21, 2016, we commenced a cash tender offer to purchase any and all of our 2021 senior notes, which tender offer expired on October 27, 2016 and settled on October 28, 2016. An aggregate of $330.1 million principal amount of the 2021 senior notes was validly tendered in the tender offer. The remaining 2021 senior notes that were not tendered in the tender offer were redeemed by us, and the indenture governing the 2021 senior notes was fully satisfied and discharged. The cash tender offer for the 2021 senior notes and redemption of the remaining 2021 senior notes were funded with a portion of the net proceeds from the offering of the 2024 senior notes.
On December 20, 2016, we completed an offering of $500.0 million in aggregate principal amount of our 5.375% senior notes due 2025, which we refer to as the 2025 senior notes. We received approximately $495.8 million in net proceeds from the offering of the 2025 senior notes, which we intend to use, together with the net proceeds from our December 2016 underwritten public offering of common stock, cash on hand and other financing sources, to fund the cash consideration for the Pending Acquisition.
Our Recent Acquisition
On September 1, 2016, we acquired from an unrelated third party leasehold interests and related assets in the Southern Delaware Basin for an aggregate purchase price of $558.5 million. This transaction included approximately 26,797 gross (19,262 net) acres primarily in Reeves and Ward counties, 19 gross producing vertical wells, 11 gross producing horizontal wells, saltwater disposal and gathering infrastructure and other related assets. We estimate that there are 290 net potential horizontal drilling locations across four zones with an average lateral length of approximately 9,500 feet on this acreage. We financed this acquisition with the net proceeds of the July 2016 equity offering discussed above and cash on hand.
Our Pending Acquisition
On December 13, 2016, we entered into a definitive purchase and sale agreement with Brigham to acquire certain assets of Brigham, for aggregate consideration consisting of a purchase price of $1.62 billion in cash and the issuance of 7.69 million shares of our common stock to Brigham, subject to certain adjustments. See Item 1. “Business and Properties-Our Pending Acquisition” for additional information regarding this transaction.
Recent Acquisitions by Viper
During 2016, Viper acquired mineral interests underlying 61,679 gross (2,142 net royalty) acres in 63 transactions for an aggregate of approximately $205.7 million. Viper funded these acquisitions primarily with borrowings under its revolving credit facility and a portion of the net proceeds from its August 2016 offering of common units.
Operational Update
We are operating six rigs now and currently intend to operate between six and ten drilling rigs in 2017 across our asset base in the Midland and Delaware Basins. We plan to operate four to six of these rigs in the Midland Basin targeting horizontal development of the Wolfcamp and Spraberry formations, while the remainder of the rigs are expected to operate in the Delaware Basin targeting the Wolfcamp and Bone Spring formations following the closing of our Pending Acquisition, which is expected to occur in February 2017.
In the Midland Basin, we have drilled and completed multiple pads in Glasscock County with significant positive results and we anticipate continuing active development on this acreage with one rig in 2017, assuming commodity prices remain steady or increase further. We have also drilled and completed three three-well pads in Howard County targeting the Lower Spraberry, Wolfcamp A and Wolfcamp B formations with positive results, and plan to continue to operate one rig in this area. The remainder of our rigs in the Midland Basin will focus on our core development area in Midland County as well as our acreage in Southwest Martin County and Northeast Andrews County targeting the Spraberry and Wolfcamp formations.
In the Delaware Basin, we are currently drilling our first operated well in Ward County, and plan to operate one rig consistently on this acreage through 2017 targeting the Wolfcamp and Bone Spring formations. After the closing of our Pending Acquisition, which is expected to occur in February 2017, we plan to operate between one and three rigs on that asset targeting the Wolfcamp and Bone Spring formations as well.
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 after two years of declining service costs during the downturn 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 2017 drilling and completion budget includes amount that we believe will cover potential increases in our service costs during the year.
2017 Capital Budget
We have currently budgeted a 2017 total capital spend of $800.0 million to $1.0 billion, consisting of $650.0 million to $825.0 million for horizontal drilling and completions including non-operated activity and $150.0 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 130 to 165 gross horizontal wells in 2017.
Operating Results Overview
The following table summarizes our average daily production for the periods presented:
| Year Ended December 31, | |||||
| 2016 | 2015 | 2014 | |||
| Oil (Bbls)/d | 31,590 | 24,880 | 14,744 | ||
| Natural Gas (Mcf)/d | 29,313 | 21,729 | 11,907 | ||
| Natural Gas Liquids (Bbls)/d | 6,556 | 4,596 | 2,745 | ||
| Total average production per day | 43,031 | 33,098 | 19,474 |
Our average daily production for the year ended December 31, 2016 as compared to the year ended December 31, 2015 increased 9,933 BOE/d, or 30%.
During the year ended December 31, 2016, 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 in the Permian Basin.
Reserves and pricing
Ryder Scott prepared estimates of our proved reserves at December 31, 2016, 2015 and 2014 (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.
| 2016 | 2015 | 2014 | ||||||
| Estimated Net Proved Reserves: | ||||||||
| Oil (Bbls) | 139,174,000 | 105,978,711 | 75,689,589 | |||||
| Natural gas (Mcf) | 174,896,000 | 149,502,744 | 111,605,260 | |||||
| Natural gas liquids (Bbls) | 37,134,000 | 26,004,144 | 18,541,932 | |||||
| Total (BOE) | 205,457,333 | 156,899,979 | 112,832,398 |
| Unweighted Arithmetic Average | |||||||||||
| First-Day-of-the-Month Prices | |||||||||||
| 2016 | 2015 | 2014 | |||||||||
| Oil (per Bbl) | $ | 39.94 | $ | 45.07 | $ | 87.15 | |||||
| Natural gas (per Mcf) | $ | 1.36 | $ | 1.83 | $ | 4.85 | |||||
| Natural gas liquids (per Bbl) | $ | 12.91 | $ | 12.56 | $ | 30.09 |
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, | ||||||||
| 2016 | 2015 | 2014 | ||||||
| Revenues | ||||||||
| Oil sales | 89 | % | 91 | % | 91 | % | ||
| Natural gas sales | 4 | % | 4 | % | 3 | % | ||
| Natural gas liquid sales | 7 | % | 5 | % | 6 | % | ||
| 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 2016, WTI posted prices ranged from $26.19 to $54.01 per Bbl and the Henry Hub spot market price of natural gas ranged from $1.49 to $3.80 per MMBtu. On December 30, 2016, the WTI posted price for crude oil was $53.75 per Bbl and the Henry Hub spot market price of natural gas was $3.71 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.
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, | |||||||||||
| 2016 | 2015 | 2014 | |||||||||
| (in thousands, except Bbl, Mcf and BOE amounts) | |||||||||||
| Revenues | |||||||||||
| Oil, natural gas liquids and natural gas | $ | 527,107 | $ | 446,733 | $ | 495,718 | |||||
| Operating Expenses | |||||||||||
| Lease operating expenses | 82,428 | 82,625 | 55,384 | ||||||||
| Production and ad valorem taxes | 34,456 | 32,990 | 32,638 | ||||||||
| Gathering and transportation | 11,606 | 6,091 | 3,288 | ||||||||
| Depreciation, depletion and amortization | 178,015 | 217,697 | 170,005 | ||||||||
| Impairment of oil and natural gas properties | 245,536 | 814,798 | — | ||||||||
| General and administrative expenses | 42,619 | 31,968 | 21,266 | ||||||||
| Asset retirement obligation accretion expense | 1,064 | 833 | 467 | ||||||||
| Total expenses | 595,724 | 1,187,002 | 283,048 | ||||||||
| Income (loss) from operations | (68,617 | ) | (740,269 | ) | 212,670 | ||||||
| Interest income (expense) | (40,684 | ) | (41,510 | ) | (34,514 | ) | |||||
| Other income | 3,064 | 728 | 677 | ||||||||
| Other expense | — | — | (1,416 | ) | |||||||
| Gain (loss) on derivative instruments, net | (25,345 | ) | 31,951 | 127,539 | |||||||
| Loss on extinguishment of debt | (33,134 | ) | — | — | |||||||
| Total other income (expense), net | (96,099 | ) | (8,831 | ) | 92,286 | ||||||
| Income (loss) before income taxes | (164,716 | ) | (749,100 | ) | 304,956 | ||||||
| Provision for (benefit from) income taxes | 192 | (201,310 | ) | 108,985 | |||||||
| Net income (loss) | (164,908 | ) | (547,790 | ) | 195,971 | ||||||
| Net income attributable to non-controlling interest | 126 | 2,838 | 2,216 | ||||||||
| Net income (loss) attributable to Diamondback Energy, Inc. | $ | (165,034 | ) | $ | (550,628 | ) | $ | 193,755 |
| Year Ended December 31, | |||||||||||
| 2016 | 2015 | 2014 | |||||||||
| (in thousands, except Bbl, Mcf and BOE amounts) | |||||||||||
| Production Data: | |||||||||||
| Oil (Bbls) | 11,561,921 | 9,081,135 | 5,381,576 | ||||||||
| Natural gas (Mcf) | 10,728,442 | 7,931,237 | 4,345,916 | ||||||||
| Natural gas liquids (Bbls) | 2,399,441 | 1,677,623 | 1,001,991 | ||||||||
| Combined volumes (BOE) | 15,749,436 | 12,080,631 | 7,107,886 | ||||||||
| Daily combined volumes (BOE/d) | 43,031 | 33,098 | 19,474 | ||||||||
| Average Prices: | |||||||||||
| Oil (per Bbl) | $ | 40.70 | $ | 44.68 | $ | 83.48 | |||||
| Natural gas (per Mcf) | 2.10 | 2.47 | 4.15 | ||||||||
| Natural gas liquids (per Bbl) | 14.20 | 12.77 | 28.39 | ||||||||
| Combined (per BOE) | 33.47 | 36.98 | 69.74 | ||||||||
| Oil, hedged($ per Bbl)(1) | 40.80 | 60.63 | 85.42 | ||||||||
| Average price, hedged($ per BOE)(1) | 33.54 | 48.97 | 71.21 | ||||||||
| Average Costs per BOE: | |||||||||||
| Lease operating expense | $ | 5.23 | $ | 6.84 | $ | 7.79 | |||||
| Production and ad valorem taxes | 2.19 | 2.73 | 4.59 | ||||||||
| Gathering and transportation expense | 0.74 | 0.50 | 0.46 | ||||||||
| General and administrative - cash component | 1.03 | 1.11 | 1.61 | ||||||||
| Total operating expense - cash | $ | 9.19 | $ | 11.18 | $ | 14.45 | |||||
| General and administrative - non-cash component | $ | 1.68 | $ | 1.54 | $ | 1.38 | |||||
| Depreciation, depletion, and amortization | 11.30 | 18.02 | 23.92 | ||||||||
| Interest expense | 2.58 | 3.44 | 4.86 | ||||||||
| Total expenses | $ | 15.56 | $ | 23.00 | $ | 30.16 | |||||
| Average realized oil price ($/Bbl) | $ | 40.70 | $ | 44.68 | $ | 83.48 | |||||
| Average NYMEX ($/Bbl) | $ | 43.29 | $ | 48.66 | $ | 93.17 | |||||
| Differential to NYMEX | $ | (2.59 | ) | $ | (3.98 | ) | $ | (9.69 | ) | ||
| Average realized oil price to NYMEX | 94 | % | 92 | % | 90 | % | |||||
| Average realized natural gas price ($/Mcf) | $ | 2.10 | $ | 2.47 | $ | 4.15 | |||||
| Average NYMEX ($/Mcf) | $ | 2.52 | $ | 2.62 | $ | 4.37 | |||||
| Differential to NYMEX | $ | (0.42 | ) | $ | (0.15 | ) | $ | (0.22 | ) | ||
| Average realized natural gas price to NYMEX | 83 | % | 94 | % | 95 | % | |||||
| Average realized natural gas liquids price ($/Bbl) | $ | 14.20 | $ | 12.77 | $ | 28.39 | |||||
| Average NYMEX oil price ($/Bbl) | $ | 43.29 | $ | 48.66 | $ | 93.17 | |||||
| Average realized natural gas liquids price to NYMEX oil price | 33 | % | 26 | % | 30 | % |
| (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, 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 2,480,786 Bbls of oil, 721,818 Bbls of natural gas liquids and 2,797,205 Mcf 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 | ) | 11,561,921 | $ | (46,031 | ) | ||||
| Natural gas liquids | $ | 1.43 | 2,399,441 | $ | 3,431 | ||||||
| Natural gas | $ | (0.37 | ) | 10,728,442 | $ | (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 | 2,480,786 | $ | 44.68 | $ | 110,815 | ||||||
| Natural gas liquids | 721,818 | $ | 12.77 | $ | 9,219 | ||||||
| Natural gas | 2,797,205 | $ | 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 Bbls for oil and natural gas liquids and Mcf 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 other property and equipment | 1,646 | 1,641 | |||||
| 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.
Interest Income (Expense). Interest income (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.
Comparison of the Years Ended December 31, 2015 and 2014
Oil, Natural Gas Liquids and Natural Gas Revenues. Our oil, natural gas liquids and natural gas revenues decreased by approximately $49.0 million, or 10%, to $446.7 million for the year ended December 31, 2015 from $495.7 million for the year ended December 31, 2014. 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 13,624 BOE/d to 33,098 BOE/d during the year ended December 31, 2015 from 19,474 BOE/d during the year ended December 31, 2014. The total decrease in revenue of approximately $49.0 million is largely attributable to lower average sales prices partially offset by higher oil, natural gas liquids and natural gas production volumes for the year ended December 31, 2015 as compared to the year ended December 31, 2014. The increases in production volumes were due to a combination of increased drilling activity and growth through acquisitions. Our production increased by 3,699,559 Bbls of oil, 675,632 Bbls of natural gas liquids and 3,585,321 Mcf of natural gas for the year ended December 31, 2015 as compared to the year ended December 31, 2014.
The net dollar effect of the decreases in prices of approximately $391.9 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 $342.9 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 | $ | (38.80 | ) | 9,081,135 | $ | (352,356 | ) | ||||
| Natural gas liquids | $ | (15.62 | ) | 1,677,623 | $ | (26,204 | ) | ||||
| Natural gas | $ | (1.68 | ) | 7,931,237 | $ | (13,324 | ) | ||||
| Total revenues due to change in price | $ | (391,884 | ) | ||||||||
| Change in production volumes(1) | Prior period average prices | Total net dollar effect of change | |||||||||
| (in thousands) | |||||||||||
| Effect of changes in production volumes: | |||||||||||
| Oil | 3,699,559 | $ | 83.48 | $ | 308,839 | ||||||
| Natural gas liquids | 675,632 | $ | 28.39 | $ | 19,181 | ||||||
| Natural gas | 3,585,321 | $ | 4.15 | $ | 14,879 | ||||||
| Total revenues due to change in production volumes | $ | 342,899 | |||||||||
| Total change in revenues | $ | (48,985 | ) |
| (1) | Production volumes are presented in Bbls for oil and natural gas liquids and Mcf for natural gas. |
Lease Operating Expenses. Lease operating expenses was $82.6 million ($6.84 per BOE) for the year ended December 31, 2015, an increase of $27.2 million, or 49%, from $55.4 million ($7.79 per BOE) for the year ended December 31, 2014. The increase is due to increased drilling activity and acquisitions, which resulted in 169 additional producing wells for the year ended December 31, 2015 as compared to the year ended December 31, 2014. 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 $33.0 million for the year ended December 31, 2015 from $32.6 million for the year ended December 31, 2014. 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. During the year ended December 31, 2015, our production taxes per BOE decreased by $1.86 as compared to the year ended December 31, 2014, primarily reflecting the impact of lower oil and natural gas prices on production taxes in 2015, offset by an increased production as a result of our acquisitions and drilling.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $47.7 million, or 28%, from $170.0 million for the year ended December 31, 2014 to $217.7 million for the year ended December 31, 2015.
The following table provides components of our depreciation, depletion and amortization expense for the periods presented:
| Year Ended December 31, | |||||||
| 2015 | 2014 | ||||||
| (in thousands, except BOE amounts) | |||||||
| Depletion of proved oil and natural gas properties | $ | 216,056 | $ | 168,674 | |||
| Depreciation of other property and equipment | 1,641 | 1,331 | |||||
| Depreciation, depletion and amortization expense | $ | 217,697 | $ | 170,005 | |||
| Oil and natural gas properties depreciation, depletion and amortization expense per BOE | $ | 17.84 | $ | 23.79 | |||
| Total depreciation, depletion and amortization expense per BOE | $ | 18.02 | $ | 23.92 |
The increases in depletion of proved oil and natural gas properties of $47.4 million for the year ended December 31, 2015 as compared to the year ended December 31, 2014 resulted primarily from higher total production levels and an increase in net book value on new reserves. On a per BOE basis, depreciation, depletion and amortization decreased primarily due to the impairment of oil and gas properties recorded in 2015.
Impairment of Oil and Natural Gas Properties. During the year ended December 31, 2015, we recorded an impairment of oil and natural gas properties of $814.8 million as a result of the significant decline in prices in 2015. No impairment was recorded during the year ended December 31, 2014.
General and Administrative Expenses. General and administrative expenses increased $10.7 million from $21.3 million for the year ended December 31, 2014 to $32.0 million for the year ended December 31, 2015. The increase was due to increases in salaries and benefits expense as a result of an increase in workforce and equity-based compensation.
Interest Income (Expense). Interest income (expense) for the year ended December 31, 2015 was $41.5 million as compared to $34.5 million for the year ended December 31, 2014, an increase of $7.0 million. This increase was due primarily to the higher average level of outstanding borrowings under our credit facility during 2015.
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, 2015 and 2014, we had a cash gain on settlement of derivative instruments of $144.9 million and $10.4 million, respectively. For the year ended December 31, 2015, we had a negative change in the fair value of open derivative instruments of $112.9 million as compared to a positive change in the fair value of open derivative instruments of $117.1 million during the year ended December 31, 2014.
Provision for (Benefit from) Income Taxes. We recorded an income tax benefit of $201.3 million for the year ended December 31, 2015 as compared to an income tax expense of $109.0 million for the year ended December 31, 2014. Our effective tax rate was 26.9% for the year ended December 31, 2015 as compared to 35.7% for the year ended December 31, 2014.
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, 2016, 2015 and 2014 are presented below:
| Year Ended December 31, | |||||||||||
| 2016 | 2015 | 2014 | |||||||||
| (in thousands) | |||||||||||
| Net cash provided by operating activities | $ | 332,080 | $ | 416,501 | $ | 356,389 | |||||
| Net cash used in investing activities | (1,310,242 | ) | (895,050 | ) | (1,481,997 | ) | |||||
| Net cash provided by financing activities | $ | 2,624,621 | $ | 468,481 | $ | 1,140,236 | |||||
| Net change in cash | $ | 1,646,459 | $ | (10,068 | ) | $ | 14,628 |
Operating Activities
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.
Net cash provided by operating activities was $416.5 million for the year ended December 31, 2015 as compared to $356.4 million for the year ended December 31, 2014. The increase in operating cash flows is primarily the result of the increase in our oil and natural gas revenues due to a 70.0% increase in our net BOE production partially offset by a 47.0% decrease in our net realized sales prices.
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 $1,310.2 million, $895.1 million and $1,482.0 million during the years ended December 31, 2016, 2015 and 2014 respectively.
During the year ended December 31, 2016, we spent $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, $611.3 million on leasehold acquisitions, $205.7 million on royalty interest acquisitions, $9.9 million for the purchase of other property and equipment and $121.4 million was placed in escrow as a deposit under the purchase agreement for the Pending Acquisition.
During the year ended December 31, 2015, we spent $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, $437.5 million on leasehold acquisitions, $43.9 million on royalty interest acquisitions and $1.2 million for the purchase of other property and equipment.
During the year ended December 31, 2014, we spent $499.8 million on capital expenditures in conjunction with our drilling program and related infrastructure projects, in which we drilled 82 gross (67 net) horizontal wells and 27 gross (22 net) vertical wells and participated in the drilling of four gross (two net) non-operated wells. We spent an additional $845.8 million on leasehold costs, $44.2 million for the purchase of other property and equipment, $57.7 million on the acquisitions of mineral interests underlying approximately 10,364 gross (3,261 net) acres in the Midland and Delaware basins and approximately $33.9 million for a minor equity interest in an entity that owns mineral, overriding royalty, net profits, leasehold and other similar interests.
Our investing activities for the years ended December 31, 2016, 2015 and 2014 are summarized in the following table:
| Year Ended December 31, | |||||||||||
| 2016 | 2015 | 2014 | |||||||||
| (in thousands) | |||||||||||
| Drilling, completion and infrastructure | $ | (364,275 | ) | $ | (419,512 | ) | $ | (499,848 | ) | ||
| Acquisition of leasehold interests | (611,280 | ) | (437,455 | ) | (845,826 | ) | |||||
| Acquisition of royalty interests | (205,721 | ) | (43,907 | ) | (57,689 | ) | |||||
| Purchase of other property and equipment | (9,891 | ) | (1,213 | ) | (44,213 | ) | |||||
| Proceeds from sale of assets | 4,661 | 9,739 | 56 | ||||||||
| Funds held in escrow | (121,391 | ) | — | — | |||||||
| Equity investments | (2,345 | ) | (2,702 | ) | (34,477 | ) | |||||
| Net cash used in investing activities | $ | (1,310,242 | ) | $ | (895,050 | ) | $ | (1,481,997 | ) |
Financing Activities
Net cash provided by financing activities for the years ended December 31, 2016, 2015 and 2014 was $2,624.6 million, $468.5 million and $1,140.2 million, respectively. 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 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. For the year ended December 31, 2014, the amount provided by financing activities was primarily attributable to the net proceeds of $208.4 million from our February 2014 equity offering, net proceeds of $137.2 million from the Viper Offering, net proceeds of $485.0 million from our July 2014 equity offering, net proceeds of $94.8 million from the Viper September 2014 equity offering and borrowings, net of repayment, of $213.5 million under our credit facility.
In addition, on January 24, 2017, Viper completed an underwritten public offering of 9,775,000 common units, resulting in approximately $147.6 million in net proceeds after deducting underwriting discounts and commissions and estimated offering expenses. Viper used $120.5 million to repay the outstanding borrowings under its revolving credit agreement and the balance will be used for general partnership purposes, which may include additional acquisitions. See “-Viper’s Equity Offerings” above.
2021 Senior Notes; Tender Offer and Redemption
In September 2013, we completed an offering of $450.0 million in aggregate principal amount of 7.625% senior unsecured notes due 2021, which we refer to as the 2021 senior notes. The 2021 senior notes bore interest at the rate of 7.625% per annum, payable semi-annually, in arrears on April 1 and October 1 of each year, were scheduled to mature on October 1, 2021 and were issued under an indenture among us, the subsidiary guarantors party thereto and Wells Fargo Bank, N.A., as the trustee, as amended and supplemented, or the 2021 indenture.
On October 21, 2016, we commenced a cash tender offer to purchase any and all of the 2021 senior notes, of which an aggregate of $450.0 million was outstanding as of that date. The tender offer expired on October 27, 2016 and settled on October 28, 2016. Holders of the 2021 senior notes that were validly tendered and accepted at or prior to the expiration time of the tender offer, or who delivered the 2021 senior notes pursuant to the guaranteed delivery procedures, received total cash consideration of $1,059.69 per $1,000 principal amount of notes, plus any accrued and unpaid interest up to, but not including, the settlement date. An aggregate of $330.1 million principal amount of the 2021 senior notes was validly tendered in the tender offer. The remaining 2021 senior notes that were not tendered in the tender offer were redeemed by us. The redemption payment included approximately $119.9 million of outstanding principal at a redemption price of 105.719% of the principal amount of the redeemed 2021 senior notes, plus accrued and unpaid interest thereon to the redemption date. Upon deposit of the redemption payment with the paying agent on October 28, 2016, the 2021 indenture was fully satisfied and discharged. The cash tender offer for the 2021 senior notes and redemption of the remaining 2021 senior notes were funded with a portion of the net proceeds from our offering of the 2024 senior notes discussed in more detail below.
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 White Fang Energy 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 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.
In connection with the issuance of the 2024 senior notes, we and the subsidiary guarantors entered into a registration rights agreement with the initial purchasers on October 28, 2016, pursuant to which we agreed to file a registration statement with respect to an offer to exchange the 2024 senior notes for a new issue of substantially identical debt securities registered under the Securities Act. Under the 2024 registration rights agreement, we also agreed to use its commercially reasonable efforts to have the registration statement declared effective by the SEC on or prior to the 360th day after the issue date of the 2024 senior notes and to keep the exchange offer open for not less than 30 days (or longer if required by applicable law). We may be required to file a shelf registration statement to cover resales of the 2024 senior notes under certain circumstances. If we fail to satisfy these obligations under the 2024 registration rights agreement, we agreed to pay additional interest to the holders of the 2024 senior notes as specified in the 2024 registration rights agreement.
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 2025 senior notes. We intend to use the net proceeds from this offering, together with the net proceeds from our December 2016 underwritten public offering of common stock, cash on hand and other financing sources, to fund the cash consideration for the Pending Acquisition discussed above. 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, commencing on May 31, 2017 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 White Fang Energy LLC, and will not be guaranteed by any of our future unrestricted subsidiaries.
The 2025 senior notes were issued under an indenture, dated as of December 20, 2016, among us, the guarantors party thereto and Wells Fargo, as the trustee. 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 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.
In connection with the issuance of the 2025 senior notes, we and the subsidiary guarantors entered into a registration rights agreement with the initial purchasers on December 20, 2016, pursuant to which we agreed to file a registration statement with respect to an offer to exchange the 2025 senior notes for a new issue of substantially identical debt securities registered under the Securities Act. Under the 2025 registration rights agreement, we also agreed to use its commercially reasonable efforts to have the registration statement declared effective by the SEC on or prior to the 360th day after the issue date of the 2025 senior notes and to keep the exchange offer open for not less than 30 days (or longer if required by applicable law). We may be required to file a shelf registration statement to cover resales of the 2025 senior notes under certain circumstances. If we fail to satisfy these obligations under the 2025 registration rights agreement, we agreed to pay additional interest to the holders of the 2025 senior notes as specified in the 2025 registration rights agreement.
Second Amended and Restated Credit Facility
Our second amended and restated credit agreement, dated November 1, 2013, as amended, with a syndicate of banks, including Wells Fargo, as administrative agent, sole book runner and lead arranger, provides for a revolving credit facility in the maximum amount of $2.0 billion. As of December 31, 2016, the borrowing base was set at $1.0 billion, although we had
elected a commitment amount of $500.0 million. As of December 31, 2016, we had no outstanding borrowings and $500.0 million available for future borrowings under this facility.
The outstanding borrowings under the credit agreement bear interest at a 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 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. 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 that the loan amount exceeds 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, 2018.
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, as amended in December 2016, allows for the issuance of unsecured debt of up to $1.0 billion in the form of senior or senior subordinated 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. As of December 31, 2016, we had $1.0 billion in aggregate principal amount of senior notes outstanding. See “–2025 Senior Notes”, “–2024 Senior Notes” and “–2021 Senior Note; Tender Offer and Redemption.”
As of December 31, 2016, 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
Viper is a party to a $500.0 million secured revolving credit agreement, dated as of July 8, 2014, as amended, with Wells Fargo as the administrative agent, sole book runner and lead arranger, and certain other lenders party thereto. The credit agreement matures on July 8, 2019. On August 5, 2016, Viper repaid $78.0 million of its outstanding borrowings with a portion of the proceeds from its August 2016 public offering of common units and, as of December 31, 2016, the borrowing base was set at $275.0 million and Viper had $120.5 million in outstanding borrowings under the credit agreement. Upon completion of Viper’s January 2017 underwritten public offering of common units, Viper repaid all of the outstanding borrowings under its revolving credit agreement, and as of February 13, 2017, had no borrowings outstanding under this facility.
The outstanding borrowings under Viper’s credit agreement bear interest at a rate elected by Viper that is equal to an alternative base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.5% and 3-month LIBOR plus 1.0%) or LIBOR, in each case plus the applicable margin. The applicable margin ranges from 0.50% to 1.50% in the case of the alternative base rate and from 1.50% to 2.50% in the case of LIBOR, in each case depending on the amount of the loan outstanding in relation to 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 borrowing base, which fee is also dependent on the amount of the loan outstanding in relation to the borrowing base. 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 that the loan amount exceeds the borrowing base, whether due to a borrowing base redetermination or otherwise (in some cases subject to a cure period) and (b) at the maturity date of July 8, 2019. The loan is secured by substantially all of the assets of Viper and its subsidiaries.
The Viper credit agreement contains various affirmative, negative and financial maintenance covenants. These covenants, among other things, limit additional indebtedness, purchases of margin stock, 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 $250.0 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 2017 capital budget for drilling and infrastructure of $800.0 million to $1.0 billion, representing an increase of 132% over our 2016 capital budget. We estimate that, of these expenditures, approximately:
| • | $650.0 million to $825.0 million will be spent on drilling and completing 130 to 165 gross (110 to 140 net) horizontal wells focused in Midland, Andrews, Upton, Martin and Dawson Counties and participating in non-operated activity; and |
| • | $150.0 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, 2016, our aggregate capital expenditures for drilling and infrastructure were $364.3 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, 2016, we spent approximately $611.3 million on acquisitions of leasehold interests.
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 six horizontal rigs and two 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 2017, 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 2017. 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 2017 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, 2016:
| Payments Due by Period | |||||||||||||||||||
| 2017 | 2018-2019 | 2020-2021 | Thereafter | Total | |||||||||||||||
| (in thousands) | |||||||||||||||||||
| Secured revolving credit facility(1) | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||
| Interest expense related to the secured revolving credit facility | 3,750 | 2,188 | — | — | $ | 5,938 | |||||||||||||
| Senior notes | — | — | — | 1,000,000 | $ | 1,000,000 | |||||||||||||
| Interest expense related to the senior notes(2) | 50,625 | 101,250 | 101,250 | 159,100 | $ | 412,225 | |||||||||||||
| Viper's secured revolving credit facility(1) | — | 120,500 | — | — | $ | 120,500 | |||||||||||||
| Interest and commitment fees under Viper's credit agreement(3) | 1,031 | 1,562 | — | — | $ | 2,593 | |||||||||||||
| Asset retirement obligations (4) | 1,288 | — | — | 16,134 | $ | 17,422 | |||||||||||||
| Drilling commitments(5) | 27,817 | 28,489 | — | — | $ | 56,306 | |||||||||||||
| Operating lease obligations | 2,468 | 4,710 | 4,294 | 10,070 | $ | 21,542 | |||||||||||||
| $ | 86,979 | $ | 258,699 | $ | 105,544 | $ | 1,185,304 | $ | 1,636,526 |
| (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, 2016, 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, 2016. |
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, 2016, 2015 and 2014. 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 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, 2016, 2015 and 2014. 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
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. The standard will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application permitted for annual reporting period beginning after December 31, 2016. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. We are currently evaluating the impact of this standard; however, we do not believe this standard will have a material impact on our consolidated financial statements.
In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update 2015-03, “Interest–Imputation of Interest”. This update requires that debt issuance costs related to a recognized debt liability (except costs associated with revolving debt arrangements) be presented in the balance sheet as a direct deduction from that debt liability, consistent with the presentation of a debt discount, to simplify the presentation of debt issuance costs. This update is effective for financial statements issued for fiscal years beginning after December 15, 2015. We retrospectively adopted this new standard effective January 1, 2016. Adoption of this standard only affects the presentation of our consolidated balance sheets and did not have a material impact on our consolidated financial statements.
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. This update will be effective for public entities for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. Entities should apply the amendments by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. While this update will not have a direct impact on us, Viper will be required to mark its cost method investment to fair value with the adoption of this update.
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 March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-08, “Revenue from Contracts with Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net)”. Under this update, an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This update will be effective for annual and interim reporting periods beginning after December 15, 2017, with early application not permitted. This update allows for either full retrospective adoption, meaning this update is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning this update is applied only to the most current period presented. We are currently evaluating the impact, if any, that the adoption of this update will have on our financial position, results of operations and liquidity.
In March 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-09, "Compensation - Stock Compensation". This update applies to all entities that issue equity-based payment awards to their employees. Under this update, there were several areas that were simplified including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update will be effective for financial
statements issued for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years with early adoption permitted. We are currently evaluating the impact that the adoption of this update will have on our financial position, results of operations and liquidity.
In April 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-10, “Revenue from Contracts with Customers - Identifying Performance Obligations and Licensing”. This update clarifies two principles of Accounting Standards Codification Topic 606: identifying performance obligations and the licensing implementation guidance. This standard has the same effective date as Accounting Standards Update 2016-08, the revenue recognition standard discussed above. The adoption of this standard is not expected to have a material impact on our financial position, results of operations and liquidity.
In May 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-12, “Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients”. This update applies only to the following areas from Accounting Standards Codification Topic 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and technical correction. This standard has the same effective date as Accounting Standards Update 2016-08, the revenue recognition standard discussed above. The adoption of this standard is not expected to have a material impact on our financial position, results of operations and liquidity.
In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update 2016-13, “Financial Instruments - Credit Losses”. This update affect 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.
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. This update will be effective for financial statements issued for fiscal years beginning after December 31, 2017, including interim periods within those fiscal years with early adoption permitted. This update should be applied using the retrospective transition method. Adoption of this standard will only affect the presentation of our cash flows and will not have a material impact on our consolidated financial statements.
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, 2016, 2015 and 2014. 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, 2016. 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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