PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market for Registrant’s Common Equity. Our common stock is listed on the Nasdaq under the symbol “OAS.”
Holders. As of February 19, 2020, the number of record holders of our common stock was 643. Based on inquiry, management believes that the number of beneficial owners of our common stock is approximately 33,090 as of February 19, 2020.
On February 25, 2020, the last sale price of our common stock, as reported on the Nasdaq, was $1.77 per share.
Unregistered Sales of Securities. There were no sales of unregistered securities during the year ended December 31, 2019.
Issuer Purchases of Equity Securities. The following table contains information about our acquisition of equity securities during the three months ended December 31, 2019:
| Period |
Total Number
of Shares
Exchanged(1)
|
Average Price
Paid per Share |
Total Number of Shares
Purchased as Part of Publicly Announced Plans or Programs |
Maximum Number (or
Approximate Dollar Value) of Shares that May Be Purchased Under the Plans or Programs |
|||||||||||||||||||
| October 1 – October 31, 2019 | 15,507 | $ | 2.83 | — | — | ||||||||||||||||||
| November 1 – November 30, 2019 | 42,601 | 3.09 | — | — | |||||||||||||||||||
| December 1 – December 31, 2019 | 17,578 | 2.33 | — | — | |||||||||||||||||||
| Total | 75,686 | $ | 2.86 | — | — | ||||||||||||||||||
__________________
(1)Represent shares that employees surrendered back to us that equaled in value the amount needed to pay payroll tax withholding obligations upon the vesting of restricted stock awards. These repurchases were not part of a publicly announced program to repurchase shares of our common stock, nor do we have a publicly announced program to repurchase shares of our common stock.
56
Stock Performance Graph. The following performance graph and related information is “furnished” with the SEC and shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically request that such information be treated as “soliciting material” or specifically incorporate such information by reference into such a filing.
The performance graph shown below compares the cumulative total return to our common stockholders as compared to the cumulative total returns on the Standard and Poor’s 500 Index (“S&P 500”) and the Standard and Poor’s 500 Oil & Gas Exploration & Production Index (“S&P 500 O&G E&P”) for the period of December 2014 through December 2019. The comparison was prepared based upon the following assumptions:
1.$100 was invested in our common stock, the S&P 500 and the S&P 500 O&G E&P on December 31, 2014 at the closing price on such date; and
2.Dividends were reinvested.
57
Item 6. Selected Financial Data
Set forth below is our summary historical consolidated financial data for the years ended December 31, 2015 through 2019. This information may not be indicative of our future results of operations, financial position and cash flows and should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere in this Annual Report on Form 10-K. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable.
| Year ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Statement of operations data: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenues: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenues | $ | 1,408,771 | $ | 1,590,024 | $ | 1,034,634 | $ | 625,233 | $ | 721,672 | |||||||||||||||||||||||||||||||||||||||||||
|
Purchased oil and gas sales(1)
|
408,791 | 550,344 | 133,542 | 10,272 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Midstream revenues(1)
|
212,208 | 120,504 | 72,752 | 35,406 | 23,769 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Well services revenues | 41,974 | 61,075 | 52,791 | 33,754 | 44,294 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total revenues | 2,071,744 | 2,321,947 | 1,293,719 | 704,665 | 789,735 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Expenses: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Lease operating expenses | 223,384 | 193,912 | 177,134 | 135,444 | 144,481 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Midstream expenses(1)
|
62,146 | 32,758 | 17,589 | 9,003 | 6,198 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Well services expenses | 28,761 | 41,200 | 37,228 | 20,675 | 24,782 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Marketing, transportation and gathering expenses | 128,806 | 107,193 | 55,740 | 30,108 | 31,610 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Purchased oil and gas expenses(1)
|
409,180 | 553,461 | 134,615 | 10,258 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Production taxes | 112,592 | 133,696 | 88,133 | 56,565 | 69,584 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 787,192 | 636,296 | 530,802 | 476,331 | 485,322 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Exploration expenses | 6,658 | 27,432 | 11,600 | 1,785 | 2,369 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Rig termination(2)
|
384 | — | — | — | 3,895 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment | 10,257 | 384,228 | 6,887 | 4,684 | 46,109 | ||||||||||||||||||||||||||||||||||||||||||||||||
| General and administrative expenses | 143,506 | 121,346 | 91,797 | 89,342 | 89,549 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total operating expenses | 1,912,866 | 2,231,522 | 1,151,525 | 834,195 | 903,899 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Gain (loss) on sale of properties | (4,455) | 28,587 | 1,774 | (1,303) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss) | 154,423 | 119,012 | 143,968 | (130,833) | (114,164) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net gain (loss) on derivative instruments | (106,314) | 28,457 | (71,657) | (105,317) | 210,376 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (176,223) | (159,085) | (146,837) | (140,305) | (149,648) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Gain (loss) on extinguishment of debt | 4,312 | (13,848) | — | 4,741 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense) | 440 | 121 | (1,332) | 160 | (2,935) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total other income (expense), net | (277,785) | (144,355) | (219,826) | (240,721) | 57,793 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Loss before income taxes | (123,362) | (25,343) | (75,858) | (371,554) | (56,371) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Income tax benefit | 32,715 | 5,843 | 203,304 | 128,538 | 16,123 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | (90,647) | (19,500) | 127,446 | (243,016) | (40,248) | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Less: Net income attributable to non-controlling interests(3)
|
37,596 | 15,796 | 3,650 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to Oasis | $ | (128,243) | $ | (35,296) | $ | 123,796 | $ | (243,016) | $ | (40,248) | |||||||||||||||||||||||||||||||||||||||||||
| Earnings (loss) per share: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Basic | $ | (0.41) | $ | (0.11) | $ | 0.53 | $ | (1.32) | $ | (0.31) | |||||||||||||||||||||||||||||||||||||||||||
| Diluted | (0.41) | (0.11) | 0.52 | (1.32) | (0.31) | ||||||||||||||||||||||||||||||||||||||||||||||||
__________________
58
(1)For the year ended December 31, 2018, midstream revenues and midstream expenses have been adjusted to include $1.5 million and $0.8 million, respectively, for certain sales and expenses which were previously recognized in purchased oil and gas sales and purchased oil and gas expenses, respectively, on our Consolidated Statements of Operations.
(2)During the years ended December 31, 2019 and 2015, we elected to early terminate certain drilling rig contracts and recorded rig termination expenses of $0.4 million and $3.9 million, respectively.
(3)As OMP completed its initial public offering on September 25, 2017, net income attributable to non-controlling interests represents the OMP interest owned by the public for the period from September 25, 2017 through December 31, 2018. See Note 3 to our consolidated financial statements for more information with respect to OMP.
| At December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance sheet data: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 20,019 | $ | 22,190 | $ | 16,720 | $ | 11,226 | $ | 9,730 | |||||||||||||||||||||||||||||||||||||||||||
| Property, plant and equipment, net | 6,977,776 | 7,027,109 | 6,173,486 | 5,919,567 | 5,218,242 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Total assets(1)
|
7,499,253 | 7,626,142 | 6,622,929 | 6,178,632 | 5,649,375 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term debt | 2,711,573 | 2,735,276 | 2,097,606 | 2,297,214 | 2,302,584 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total stockholders’ equity | 3,837,081 | 3,918,880 | 3,513,579 | 2,923,157 | 2,319,342 | ||||||||||||||||||||||||||||||||||||||||||||||||
__________________
(1)Upon adoption of Accounting Standards Codification 842, Leases, in 2019, we recognized operating and finance lease ROU assets of $31.1 million and $6.0 million, respectively. See Note 20 to our consolidated financial statements for a description of our operating and finance leases.
| Year ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other financial data: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 892,853 | $ | 996,421 | $ | 507,876 | $ | 228,018 | $ | 359,815 | |||||||||||||||||||||||||||||||||||||||||||
| Net cash used in investing activities | (828,756) | (1,613,536) | (714,760) | (1,070,828) | (479,148) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net cash provided by (used in) financing activities | (66,268) | 622,585 | 212,378 | 844,306 | 83,252 | ||||||||||||||||||||||||||||||||||||||||||||||||
59
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes 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. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in crude oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary note regarding forward-looking statements.”
Overview
We are an independent E&P company focused on the acquisition and development of onshore, unconventional crude oil and natural gas resources in the United States. Since our inception, we have acquired properties that provide current production and significant upside potential through further development. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct our domestic crude oil and natural gas E&P activities and own our proved and unproved oil and gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Delaware Basin, respectively. In addition to our exploration and production segment, we also operate a midstream business through Oasis Midstream Partners LP (“OMP” or “Oasis Midstream”) and Oasis Midstream Services LLC (“OMS”). OMP is a growth-oriented, fee-based master limited partnership that develops and operates a diversified portfolio of midstream assets. We own a substantial majority of the general partner and a majority of the outstanding units of OMP. As of December 31, 2019, we operated a well services business through Oasis Well Services LLC (“OWS”). In March 2020, we intend to transition our well fracturing services from OWS to a third-party provider who will provide services to us under a long-term agreement. We believe this will result in continued quality service, while allowing us to focus on our core operations.
We built our Williston Basin and Delaware Basin assets through acquisitions and development activities. Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve, and we have historically acquired properties that we believe will meet or exceed our rate of return criteria. For acquisitions of properties with additional development, exploitation and exploration potential, we have focused on acquiring properties that we expect to operate so that we can control the timing and implementation of capital spending. In some instances, we have acquired non-operated property interests at what we believe to be attractive rates of return either because they provided an entry into a new area of interest or complemented our existing operations. In addition, the acquisition of non-operated properties in new areas provides us with geophysical and geologic data that may lead to further acquisitions in the same area, whether on an operated or non-operated basis. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
Our revenue, profitability and future growth rate depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for crude oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. Since the inception of our crude oil and natural gas activities, commodity prices have experienced significant fluctuations and may fluctuate widely in the future. As a result of current market conditions, we continue to concentrate our drilling activities in certain areas that are the most economical in the Williston and Delaware Basins, and we are focused on delivering moderate growth while maintaining capital spending within internally generated cash flows. A substantial or extended decline in prices for crude oil or natural gas could materially and adversely affect our financial position, our results of operations, the quantities of crude oil and natural gas reserves that we can economically produce and our access to capital.
In an effort to improve price realizations from the sale of our crude oil, natural gas and NGLs, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, natural gas and NGLs to a broad array of potential purchasers. We enter into crude oil, natural gas and NGL sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. Due to the availability of other markets and pipeline connections, we do not believe that the loss of any single crude oil, natural gas and NGL customer would have a material adverse effect on our results of operations or cash flows. Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead. Currently, 91% of our gross operated crude oil production and substantially all of
60
our gross operated natural gas production are connected to gathering systems. Please see “Item 1. Business—Marketing, transportation and major customers.”
Our quarterly average net realized crude oil prices and average price differentials are shown in the tables below.
| 2019 | Year ended December 31, 2019 | ||||||||||||||||||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | ||||||||||||||||||||||||||||||||||||||||||||
|
Average Realized Crude Oil Prices ($/Bbl)(1)
|
$ | 53.52 | $ | 58.87 | $ | 55.12 | $ | 53.66 | $ | 55.27 | |||||||||||||||||||||||||||||||||||||
|
Average Price Differential ($/Bbl)(2)
|
$ | 1.30 | $ | 0.96 | $ | 1.30 | $ | 3.23 | $ | 1.68 | |||||||||||||||||||||||||||||||||||||
|
Average Price Differential Percentage(2)
|
2 | % | 2 | % | 2 | % | 6 | % | 3 | % | |||||||||||||||||||||||||||||||||||||
| 2018 | Year ended December 31, 2018 | ||||||||||||||||||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | ||||||||||||||||||||||||||||||||||||||||||||
|
Average Realized Crude Oil Prices ($/Bbl)(1)
|
$ | 61.75 | $ | 65.82 | $ | 68.33 | $ | 52.01 | $ | 61.84 | |||||||||||||||||||||||||||||||||||||
|
Average Price Differential ($/Bbl)(2)
|
$ | 1.12 | $ | 2.07 | $ | 1.16 | $ | 6.79 | $ | 2.88 | |||||||||||||||||||||||||||||||||||||
|
Average Price Differential Percentage(2)
|
2 | % | 3 | % | 2 | % | 12 | % | 4 | % | |||||||||||||||||||||||||||||||||||||
| 2017 | Year ended December 31, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | ||||||||||||||||||||||||||||||||||||||||||||
|
Average Realized Crude Oil Prices ($/Bbl)(1)
|
$ | 47.03 | $ | 44.58 | $ | 46.34 | $ | 54.95 | $ | 48.51 | |||||||||||||||||||||||||||||||||||||
|
Average Price Differential ($/Bbl)(2)
|
$ | 4.88 | $ | 3.71 | $ | 1.84 | $ | 0.51 | $ | 2.62 | |||||||||||||||||||||||||||||||||||||
|
Average Price Differential Percentage(2)
|
9 | % | 8 | % | 4 | % | 1 | % | 5 | % | |||||||||||||||||||||||||||||||||||||
__________________
(1)Realized crude oil prices do not include the effect of derivative contract settlements.
(2)Price differential reflects the difference between realized crude oil prices and NYMEX WTI crude oil index prices.
Our market optionality on the crude oil gathering systems allows us to shift volumes between pipeline and rail markets in order to optimize price realizations. Crude oil produced and sold in the Williston Basin has historically sold at a discount to NYMEX WTI due to transportation costs and takeaway capacity. In the past, there have been periods when this discount has substantially increased due to crude oil production in the area increasing to a point that it temporarily surpassed the available pipeline transportation, rail transportation and refining capacity in the area. Expansions of both rail and pipeline facilities have reduced the prior constraint on crude oil transportation out of the Williston Basin and improved our price differentials received at the lease. In 2015, our price differentials relative to NYMEX WTI strengthened as new pipelines opened to eastern Canada and U.S. markets and transportation on rail gradually declined. In the Williston Basin, our crude oil price differentials averaged approximately $1.65 per barrel discount to NYMEX WTI during 2019. In the Delaware Basin, price differentials have improved throughout the year due to new pipelines coming online, averaging close to $0.20 above NYMEX WTI during the fourth quarter of 2019 as compared to more than $5.00 per barrel below NYMEX WTI in the first quarter of 2019. Expansions of pipelines will continue to improve differentials and provide ample takeaway for our Delaware Basin production.
We believe our large concentrated acreage position provides us with a multi-year inventory of drilling projects and requires forward planning visibility for obtaining services and necessary permits to drill wells. As a result of current crude oil prices, we are planning to decrease our well completions from 67 gross (41.6 net) operated wells in the Williston Basin in 2019 to approximately 45 to 55 gross operated wells in 2020. In the Delaware Basin, we are planning to increase in well completions from 11 gross (9.9 net) operated wells in 2019 to approximately 20 to 25 gross operated wells in 2020. Additionally, we have the ability to control the pace of completions to allow for additional financial flexibility. In 2019, we wrote off $0.6 million of leases that we did not expect to develop before their 2020 contract expirations, as we continue to focus our 2020 drilling activities in our core acreage in the Williston Basin and the Delaware Basin.
Our 2019, 2018 and 2017 activities included development and exploration drilling in the Williston Basin with activities in the Delaware Basin starting in 2018 and through 2019. Our current activities are focused on evaluating and developing our asset bases in the Williston Basin and the Delaware Basin and optimizing our operations. Based on the reserve reports prepared by our independent reserve engineers, we had 286.4 MMBoe of estimated net proved reserves with a PV-10 of $2,934.4 million and a Standardized Measure of $2,844.4 million at December 31, 2019, 320.5 MMBoe of estimated net proved reserves with a PV-10 of $4,674.3 million and a Standardized Measure of $4,050.3 million at December 31, 2018 and 312.2 MMBoe of estimated net proved reserves with a PV-10 of $3,683.7 million and a Standardized Measure of $3,300.7 million at December 31, 2017. Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to derivative transactions, and were held constant
61
throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months for the years ended December 31, 2019, 2018 and 2017 were $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas, $65.66 per Bbl for crude oil and $3.16 per MMBtu for natural gas and $51.34 per Bbl for crude oil and $2.99 per MMBtu for natural gas, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end. Changes in commodity prices and future operating costs may significantly affect the economic viability of drilling projects as well as the economic valuation and economic recovery of oil and gas reserves. A substantial or extended decline in crude oil prices could result in a significant decrease in our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure in the future.
Expected forward commodity prices and estimates of future production also play a significant role in determining impairment of proved oil and gas properties. In 2018, we recorded impairment charges of $134.8 million to write down our proved properties held for sale to their estimated fair value, less costs to sell. No proved impairment charges were recorded during the year ended December 31, 2019. As a result of lower commodity prices and lower recoverable reserves in the Williston Basin and the Delaware Basin and their impact on our estimated future cash flows, we have continued to review our proved oil and gas properties for impairment. As of December 31, 2019, the excess of our estimated undiscounted future cash flows over the carrying value of our proved oil and gas properties was $186.1 million in the Williston Basin and $430.7 million in the Delaware Basin. Our estimated undiscounted future cash flows include the cost benefits from consolidating our midstream and well services business segments as well as the impact of transitioning our well fracturing services from OWS to a third-party provider in March 2020. If we discontinued or no longer had a controlling financial interest in the operations of the midstream business segment, our expected future costs would increase, which may cause the estimated undiscounted future cash flows to decline below the carrying value of our proved oil and gas properties.
The underlying commodity prices included in our estimated undiscounted cash flows were determined using NYMEX forward strip prices for five years as of December 31, 2019, escalating 3% per year thereafter. Our estimated undiscounted future cash flows also included a 3% inflation factor applied to the future operating and development costs after five years and every year thereafter. Expected future commodity prices have decreased since December 31, 2019, and we may record a proved property impairment charge in 2020. If expected future commodity prices decline by approximately 2% as compared to December 31, 2019, holding all other factors constant, the estimated undiscounted future cash flows may not exceed the carrying value of our proved oil and gas properties in the Williston Basin, and if expected future commodity prices decline by approximately 20% as compared to December 31, 2019, holding all other factors constant, the estimated undiscounted future cash flows may not exceed the carrying value of our proved oil and gas properties in the Delaware Basin.
If our estimated future cash flows decline below the carrying value of our proved oil and gas properties, we may recognize proved property impairment charges in the future for the Williston Basin and the Delaware Basin, and such impairment charges could exceed $2 billion and $455 million, respectively, assuming a discount rate of 10%. This sensitivity analysis decreased the expected future prices of both crude oil and natural gas, but a decline in the realized price of either commodity, an increase to costs or an increase in discount rate greater than those described above may independently impact our estimated future cash flows.
Highlights
•Our production volumes averaged 88,061 Boepd (71.0% oil) for the year ended December 31, 2019.
•We participated in 130 gross (52.1 net) wells that were completed and placed on production, and, as operator, we completed and placed on production 78 gross (51.5 net) operated wells, including 67 gross (41.6 net) operated wells in the Williston Basin and 11 gross (9.9 net) operated wells in the Delaware Basin, while investing $594.2 million of E&P capital expenditures, which excludes acquisitions, other capital and midstream capital, during 2019.
•Our crude oil differentials improved to $1.68 off of NYMEX WTI in 2019.
•Net cash provided by operating activities was $892.9 million for the year ended December 31, 2019. Adjusted EBITDA, a non-GAAP financial measure, was $1,039.5 million for the year ended December 31, 2019. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to net income (loss) including non-controlling interests and net cash provided by operating activities, see “Non-GAAP Financial Measures” below.
62
Results of Operations
Revenues
Our crude oil and natural gas revenues are derived from the sale of crude oil and natural gas production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices. Our purchased oil and gas sales are primarily derived from the sale of crude oil and natural gas purchased through our marketing activities primarily to optimize transportation costs or for blending at our crude oil terminal. Revenues and expenses from crude oil and natural gas sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis.
Our midstream revenues are primarily derived from natural gas gathering and processing, produced and flowback water gathering and disposal, crude oil gathering and transportation and fresh water sales. Our well services revenues are derived from well services, product sales and equipment rentals. A majority of our midstream revenues and substantially all of our well services revenues are from services for third-party working interest owners in OPNA’s operated wells. Intercompany revenues for work performed by OMS and OWS for OPNA’s working interests are eliminated in consolidation and are therefore not included in midstream and well services revenues.
The following table summarizes our revenues and production data for the periods presented:
| Year ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| Operating results (in thousands) | |||||||||||||||||||||||||||||
| Revenues | |||||||||||||||||||||||||||||
| Crude oil revenues | $ | 1,261,413 | $ | 1,425,409 | $ | 912,806 | |||||||||||||||||||||||
| Natural gas revenues | 147,358 | 164,615 | 121,828 | ||||||||||||||||||||||||||
|
Purchased oil and gas sales(1)
|
408,791 | 550,344 | 133,542 | ||||||||||||||||||||||||||
|
Midstream revenues(1)
|
212,208 | 120,504 | 72,752 | ||||||||||||||||||||||||||
| Well services revenues | 41,974 | 61,075 | 52,791 | ||||||||||||||||||||||||||
| Total revenues | $ | 2,071,744 | $ | 2,321,947 | $ | 1,293,719 | |||||||||||||||||||||||
| Production data | |||||||||||||||||||||||||||||
| Williston Basin | |||||||||||||||||||||||||||||
| Crude oil (MBbls) | 20,722 | 21,786 | 18,818 | ||||||||||||||||||||||||||
| Natural gas (MMcf) | 52,813 | 40,550 | 31,946 | ||||||||||||||||||||||||||
| Oil equivalents (MBoe) | 29,524 | 28,544 | 24,143 | ||||||||||||||||||||||||||
| Average daily production (Boe per day) | 80,889 | 78,203 | 66,144 | ||||||||||||||||||||||||||
| Delaware Basin | |||||||||||||||||||||||||||||
| Crude oil (MBbls) | 2,102 | 1,264 | — | ||||||||||||||||||||||||||
| Natural gas (MMcf) | 3,093 | 1,880 | — | ||||||||||||||||||||||||||
| Oil equivalents (MBoe) | 2,618 | 1,578 | — | ||||||||||||||||||||||||||
| Average daily production (Boe per day) | 7,172 | 4,322 | — | ||||||||||||||||||||||||||
| Average sales prices | |||||||||||||||||||||||||||||
| Crude oil, without derivative settlements (per Bbl) | $ | 55.27 | $ | 61.84 | $ | 48.51 | |||||||||||||||||||||||
|
Crude oil, with derivative settlements (per Bbl)(2)
|
55.89 | 52.65 | 47.99 | ||||||||||||||||||||||||||
|
Natural gas, without derivative settlements (per Mcf)(3)
|
2.64 | 3.88 | 3.81 | ||||||||||||||||||||||||||
|
Natural gas, with derivative settlements (per Mcf)(2)(3)
|
2.72 | 3.84 | 3.86 | ||||||||||||||||||||||||||
__________________
(1)For the year ended December 31, 2018, midstream revenues have been adjusted to include $1.5 million for certain sales which were previously recognized in purchased oil and gas sales on our Consolidated Statements of Operations.
(2)Realized prices include gains or losses on cash settlements for our commodity derivatives, which do not qualify for or were not designated as hedging instruments for accounting purposes. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
63
(3)Natural gas prices include the value for natural gas and NGLs.
Year ended December 31, 2019 as compared to year ended December 31, 2018
Crude oil and natural gas revenues. Our crude oil and natural gas revenues decreased $181.2 million, or 11%, to $1,408.8 million during the year ended December 31, 2019 as compared to the year ended December 31, 2018. This decrease was primarily driven by a $204.2 million decrease due to lower crude oil and natural gas sales prices, coupled with a $12.5 million decrease driven by lower crude oil production amounts sold year over year. These decreases were partially offset by a $35.5 million increase driven by higher natural gas production amounts sold year over year. Average crude oil sales prices, without derivative settlements, decreased by $6.57 per barrel to an average of $55.27 per barrel, and average natural gas sales prices, without derivative settlements and which include the value for natural gas and NGLs, decreased by $1.24 per Mcf to an average of $2.64 per Mcf for the year ended December 31, 2019 as compared to the year ended December 31, 2018. Average daily production sold increased by 5,536 Boe per day to 88,061 Boe per day during the year ended December 31, 2019 as compared to the year ended December 31, 2018, primarily due to an increase in natural gas production, offset by a decrease in crude oil production. The increase in average daily production sold was primarily a result of our well completions during the year, offset by our divestitures of various upstream packages. During the year ended December 31, 2019, we completed 42.1 total net wells in the Williston Basin and 10.0 total net wells in the Delaware Basin.
Purchased oil and gas sales. Purchased oil and gas sales, which consist primarily of the sale of crude oil purchased to optimize transportation costs or for blending at our crude oil terminal, decreased $141.6 million to $408.8 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018, primarily due to lower crude oil volumes purchased and sold in the Williston Basin.
Midstream revenues. Midstream revenues were $212.2 million for the year ended December 31, 2019, which was a $91.7 million increase year over year. This increase was primarily driven by a $69.4 million increase related to higher natural gas sales resulting from the commencement of third-party natural gas purchase arrangements in the fourth quarter of 2018, coupled with a $20.6 million increase related to higher natural gas volumes gathered, compressed and processed as a result of the start-up of our second natural gas processing plant in Wild Basin during the fourth quarter of 2018.
Well services revenues. Well services revenues decreased by $19.1 million to $42.0 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018, which was primarily attributable to a $9.4 million decrease in well completion revenues due to decreased activity as a result of reducing to one fracturing crew in the third quarter of 2019, coupled with an $8.1 million decrease in product sales to third parties and a $1.5 million decrease in equipment rentals.
Year ended December 31, 2018 as compared to year ended December 31, 2017
For the comparison of the years ended December 31, 2018 and 2017, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 1, 2019.
64
Expenses and other income
The following table summarizes our operating expenses, gain (loss) on sale of properties, other income and expenses and net income (loss) attributable to non-controlling interests for the periods presented:
| Year ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands, except per Boe of production) | |||||||||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||
| Lease operating expenses | $ | 223,384 | $ | 193,912 | $ | 177,134 | |||||||||||||||||||||||
|
Midstream expenses(1)
|
62,146 | 32,758 | 17,589 | ||||||||||||||||||||||||||
| Well services expenses | 28,761 | 41,200 | 37,228 | ||||||||||||||||||||||||||
| Marketing, transportation and gathering expenses | 128,806 | 107,193 | 55,740 | ||||||||||||||||||||||||||
|
Purchased oil and gas expenses(1)
|
409,180 | 553,461 | 134,615 | ||||||||||||||||||||||||||
| Production taxes | 112,592 | 133,696 | 88,133 | ||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 787,192 | 636,296 | 530,802 | ||||||||||||||||||||||||||
| Exploration expenses | 6,658 | 27,432 | 11,600 | ||||||||||||||||||||||||||
| Rig termination | 384 | — | — | ||||||||||||||||||||||||||
| Impairment | 10,257 | 384,228 | 6,887 | ||||||||||||||||||||||||||
| General and administrative expenses | 143,506 | 121,346 | 91,797 | ||||||||||||||||||||||||||
| Total operating expenses | 1,912,866 | 2,231,522 | 1,151,525 | ||||||||||||||||||||||||||
| Gain (loss) on sale of properties | (4,455) | 28,587 | 1,774 | ||||||||||||||||||||||||||
| Operating income | 154,423 | 119,012 | 143,968 | ||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||
| Net gain (loss) on derivative instruments | (106,314) | 28,457 | (71,657) | ||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (176,223) | (159,085) | (146,837) | ||||||||||||||||||||||||||
| Gain (loss) on extinguishment of debt | 4,312 | (13,848) | — | ||||||||||||||||||||||||||
| Other income (expense) | 440 | 121 | (1,332) | ||||||||||||||||||||||||||
| Total other expense, net | (277,785) | (144,355) | (219,826) | ||||||||||||||||||||||||||
| Loss before income taxes | (123,362) | (25,343) | (75,858) | ||||||||||||||||||||||||||
| Income tax benefit | 32,715 | 5,843 | 203,304 | ||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | (90,647) | (19,500) | 127,446 | ||||||||||||||||||||||||||
|
Less: Net income attributable to non-controlling interests(2)
|
37,596 | 15,796 | 3,650 | ||||||||||||||||||||||||||
| Net income (loss) attributable to Oasis | $ | (128,243) | $ | (35,296) | $ | 123,796 | |||||||||||||||||||||||
| Costs and expenses (per Boe of production) | |||||||||||||||||||||||||||||
| Lease operating expenses | $ | 6.95 | $ | 6.44 | $ | 7.34 | |||||||||||||||||||||||
| Marketing, transportation and gathering expenses | 4.01 | 3.56 | 2.31 | ||||||||||||||||||||||||||
| Production taxes | 3.50 | 4.44 | 3.65 | ||||||||||||||||||||||||||
__________________
(1)For the year ended December 31, 2018, midstream expenses have been adjusted to include $0.8 million for certain expenses which were previously recognized in purchased oil and gas expenses on our Consolidated Statements of Operations.
(2)As OMP completed its initial public offering on September 25, 2017, net income attributable to non-controlling interests represents the OMP interest owned by the public for the period from September 25, 2017 through December 31, 2018. See Note 3 to our consolidated financial statements for more information with respect to OMP.
Year ended December 31, 2019 as compared to year ended December 31, 2018
Lease operating expenses. Lease operating expenses increased $29.5 million to $223.4 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018. This increase was primarily due to higher fixed costs and workover costs, coupled with higher costs associated with operating an increased number of producing wells as a result of our well completions during the year ended December 31, 2019. We completed and placed on production 52.1 total net wells, including
65
42.1 total net wells in the Williston Basin and 10.0 total net wells in the Delaware Basin, during the year ended December 31, 2019. Lease operating expenses per Boe increased from $6.44 per Boe to $6.95 per Boe primarily due to the higher aforementioned costs, offset by higher production volumes year over year.
Midstream expenses. Midstream expenses represent third-party working interest owners’ share of operating expenses incurred by OMS. The $29.4 million increase for the year ended December 31, 2019 as compared to the year ended December 31, 2018 was primarily related to a $19.5 million increase in natural gas purchases from third parties, coupled with a $10.9 million increase in natural gas gathering, compression and processing expenses driven by increased production as a result of the start-up of our second natural gas processing plant in Wild Basin during the fourth quarter of 2018 and increased costs related to downtime at our natural gas processing complex during 2019. These increases were partially offset by a $1.5 million decrease related to lower produced and flowback water operating expenses year over year.
Well services expenses. Well services expenses represent third-party working interest owners’ share of completion service costs, cost of goods sold and operating expenses incurred by OWS. The $12.4 million decrease for the year ended December 31, 2019 as compared to the year ended December 31, 2018 was primarily attributable to a $6.6 million decrease in well completion expenses due to decreased activity as a result of reducing to one fracturing crew in the third quarter of 2019, coupled with a $5.8 million decrease in product sales to third parties.
Marketing, transportation and gathering (“MT&G”) expenses. MT&G expenses increased $21.6 million year over year, or a $0.45 increase per Boe, which was primarily attributable to higher natural gas gathering and processing expenses due to additional well connections on our midstream infrastructure and our second natural gas processing plant, coupled with higher oil gathering and transportation expenses related to increased throughput on the Dakota Access Pipeline to market our equity barrels. Cash MT&G expenses, which excludes non-cash valuation adjustments, on a per Boe basis increased to $3.93 for the year ended December 31, 2019 as compared to $3.41 for the year ended December 31, 2018 primarily due to the higher aforementioned costs. For a definition of Cash MT&G and a reconciliation of MT&G to Cash MT&G, see “Non-GAAP Financial Measures” below.
Purchased oil and gas expenses. Purchased oil and gas expenses, which represent the crude oil purchased primarily to optimize transportation costs or for blending at our crude oil terminal, decreased $144.3 million to $409.2 million for the year ended December 31, 2019 as compared to December 31, 2018 primarily due to lower crude oil volumes purchased and sold in the Williston Basin.
Production taxes. Our production taxes for the years ended December 31, 2019 and 2018 were 8.0% and 8.4%, respectively, as a percentage of crude oil and natural gas sales. The production tax rate decreased year over year primarily due to a lower crude oil production mix, coupled with the addition of Delaware Basin assets, which bear a lower average production tax rate than the Williston Basin assets. North Dakota’s natural gas production tax is $0.0712 per Mcf, while its crude oil tax structure is based on a 5% production tax and a 5% crude oil extraction tax, resulting in a combined tax rate of 10% on crude oil revenues.
Depreciation, depletion and amortization (“DD&A”). DD&A expense increased $150.9 million to $787.2 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018. This increase was primarily due to production increases from our wells completed during 2019, coupled with an increase in the average DD&A rate to $24.49 per Boe for the year ended December 31, 2019 as compared to $21.12 per Boe for the year ended December 31, 2018. The increase in the DD&A rate was primarily due to lower recoverable reserves in the Williston Basin and the Delaware Basin, coupled with higher well costs in the Delaware Basin.
Exploration expenses. Exploration expenses decreased $20.7 million to $6.7 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018. This decrease was primarily due to lower write-off costs of $15.1 million related to exploratory well locations that are no longer in our current development plan.
Impairment. During the years ended December 31, 2019 and 2018, we recorded total impairment charges of $10.3 million and $384.2 million, respectively. During the year ended December 31, 2019, we pursued an exit from the well services business and recorded an impairment loss of $4.4 million to adjust the carrying value of certain inventory and equipment held for sale to their estimated fair value (see Note 12—Assets Held for Sale). There were no impairment charges of proved oil and gas or other properties recorded during the year ended December 31, 2019. During the year ended December 31, 2018, we recorded an impairment loss of $383.4 million to adjust the carrying value of our properties for the Foreman Butte Divestiture to their estimated fair value, determined based on the expected sales price less costs to sell (see Note 11—Divestitures). As a result of expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of our unproved properties, we recorded an impairment loss on our unproved oil and gas properties of $5.4 million and $0.9 million for the years ended December 31, 2019 and 2018, respectively, related to acreage expiring in future periods because there were no current plans to drill or extend the leases prior to their expiration. Due to fluctuating commodity prices, we recorded an impairment loss of $0.5 million to adjust the carrying value of our long-term inventory to its net realizable value during the year ended December 31, 2019. There were no such impairment charges recorded during year ended December 31, 2018.
66
General and administrative (“G&A”) expenses. Our G&A expenses increased $22.2 million to $143.5 million for the year ended December 31, 2019 from $121.3 million for the year ended December 31, 2018. E&P G&A increased $16.2 million year over year primarily due to a $20.0 million loss accrual, which we believe is the estimable amount of loss that could potentially be incurred from our pending legal proceedings based upon currently available information (see Note 22—Commitments and Contingencies). This increase was coupled with increased costs related to employee compensation expenses as a result of organizational growth during the first half of 2019, coupled with severance expenses related to a reduction in force during the third quarter of 2019, and partially offset by the decrease in costs related to the Permian Basin Acquisition, which were incurred during the year ended December 31, 2018. OMS G&A increased $2.5 million year over year primarily due to increased shared services expenses as a result of the growth of our midstream business. OWS G&A increased $3.4 million due to severance expenses resulting from a reduction in force to one fracturing crew during the third quarter of 2019. Consolidated G&A expenses included non-cash amortization for equity-based compensation of $33.6 million and $29.3 million in 2019 and 2018, respectively. Our full-time employee headcount decreased 16% year over year.
Gain (loss) on sale of properties. For the year ended December 31, 2019, we recognized a $4.5 million net loss primarily due to completing the final closing statements for the sale of non-strategic oil and gas properties and certain other property and equipment in the Williston Basin. For the year ended December 31, 2018, we recognized a $28.6 million net gain related to the sale of three separate divestitures to sell certain non-strategic oil and gas properties in the Williston Basin (see Note 11—Divestitures).
Derivative instruments. As a result of entering into derivative contracts and the effect of the forward strip crude oil and natural gas price changes, we incurred a $106.3 million net loss on derivative instruments, including net cash settlement receipts of $19.1 million, for the year ended December 31, 2019, and a $28.5 million net gain on derivative instruments, including net cash settlement payments of $213.5 million, for the year ended December 31, 2018. Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
Interest expense, net of capitalized interest. Interest expense increased $17.1 million to $176.2 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018 primarily due to a $10.0 million increase in interest expense related to our borrowings under our OMP Credit Facility, coupled with a decrease in capitalized interest of $5.3 million due to lower costs for work in progress assets year over year. For the year ended December 31, 2019, the weighted average debt outstanding under the Oasis Credit Facility and the OMP Credit Facility was $511.5 million and $392.1 million, respectively, and the weighted average interest rate incurred on the outstanding borrowings was 4.0% and 4.1%, respectively. For the year ended December 31, 2018, the weighted average debt outstanding under the Oasis Credit Facility and the OMP Credit Facility was $554.7 million and $166.2 million, respectively, and the weighted average interest rate incurred on the outstanding borrowings was 3.9% and 3.8%, respectively. We capitalized $12.0 million and $17.2 million of interest costs for the years ended December 31, 2019 and 2018, respectively, which will be amortized over the life of the related assets.
Gain (loss) on extinguishment of debt. During the year ended December 31, 2019, we repurchased an aggregate principal amount of $56.8 million of our outstanding senior unsecured notes and senior unsecured convertible notes for an aggregate cost of $45.8 million. For the year ended December 31, 2019, we recognized a pre-tax gain related to the repurchase of $4.3 million, which included the write-off of unamortized deferred financing costs and unamortized debt discount of $6.7 million. During the year ended December 31, 2018, we repurchased an aggregate principal amount of $413.5 million of our outstanding senior unsecured notes for an aggregate cost of $423.1 million, including fees. For the year ended December 31, 2018, we recognized a pre-tax loss related to the repurchase of $13.8 million, which included unamortized deferred financing costs write-offs of $4.0 million.
Income tax benefit. Our income tax benefit for the years ended December 31, 2019 and 2018 was recorded at 26.5% and 23.1%, respectively, of pre-tax loss. The 3.4% increase in the effective tax rate recorded is primarily due to (i) the impact of non-deductible executive compensation, (ii) equity-based compensation shortfalls in 2019 exceeding the equity-based compensation shortfalls in 2018, (iii) impacts from the Tax Act recorded in 2018 and (iv) the increase in valuation allowance recorded against our Montana net operating loss carryforwards in 2018. This was partially offset by (i) the impact of non-controlling interests and (ii) the impact of a change in the state rate at which deferred taxes are recorded in 2018.
Year ended December 31, 2018 as compared to year ended December 31, 2017
For the comparison of the years ended December 31, 2018 and 2017, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on March 1, 2019.
67
Liquidity and Capital Resources
Our primary sources of liquidity as of the date of this report have been cash flows from operations, proceeds from the sale of certain non-strategic oil and gas properties, cash settlements of derivative contracts and borrowings under a $1,300.0 million senior secured revolving credit facility among OPNA, as Borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “Oasis Credit Facility”) and a $575.0 million senior secured revolving credit facility among OMP, as parent, OMP Operating LLC, a subsidiary of OMP, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “OMP Credit Facility,” and, together with the Oasis Credit Facility, our “Revolving Credit Facilities”). Our primary uses of cash have been for the development and acquisition of oil and gas properties and midstream infrastructure, repurchases of our Senior Notes (as defined below), distributions to non-controlling interests and interest payments on outstanding debt. We continually monitor potential capital sources, including equity and debt financings and potential asset monetization opportunities, in order to enhance liquidity and decrease leverage. Although we have financial flexibility with our cash balance and the ability to draw on our Revolving Credit Facilities, we continue to be committed to our capital discipline strategy of investing within our cash flows from operations and cash settlements of derivative contracts.
Our cash flows for the years ended December 31, 2019, 2018 and 2017 are presented below:
| Year ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 892,853 | $ | 996,421 | $ | 507,876 | |||||||||||||||||||||||
| Net cash used in investing activities | (828,756) | (1,613,536) | (714,760) | ||||||||||||||||||||||||||
| Net cash provided by (used in) financing activities | (66,268) | 622,585 | 212,378 | ||||||||||||||||||||||||||
| Net change in cash and cash equivalents | $ | (2,171) | $ | 5,470 | $ | 5,494 | |||||||||||||||||||||||
Our cash flows depend on many factors, including the price of crude oil and natural gas and the success of our development and exploration activities as well as future acquisitions. Prices for crude oil began to show upward movements during 2017 and the majority of 2018 resulting in increased cash flows provided by operating activities. In late 2018, crude oil prices declined and have remained relatively flat throughout 2019 resulting in decreased cash flows provided by operating activities for the year ended December 31, 2019. We actively manage our exposure to commodity price fluctuations by executing derivative transactions to mitigate the change in crude oil and natural gas prices on a portion of our production, thereby mitigating our exposure to crude oil and natural gas price declines, but these transactions may also limit our cash flow in periods of rising crude oil and natural gas prices. As of December 31, 2019, our derivative contracts in place cover 16.6 MMBbls of crude oil in 2020 and 2021.
Our existing Revolving Credit Facilities provide additional liquidity. The Oasis Credit Facility has a current borrowing base of $1,300.0 million and an elected commitment amount of $1,100.0 million. The next redetermination of the borrowing base for the Oasis Credit Facility is scheduled for April 1, 2020. The OMP Credit Facility has a current borrowing capacity of $575.0 million.
We believe we have adequate liquidity to fund planned 2020 capital expenditures and to meet our near-term future obligations. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”
Cash flows provided by operating activities
Net cash provided by operating activities was $892.9 million, $996.4 million and $507.9 million for the years ended December 31, 2019, 2018 and 2017, respectively. The decrease in cash flows provided by operating activities for the year ended December 31, 2019 as compared to 2018 was primarily the result of an 11% decrease in realized crude oil prices, coupled with a 32% decrease in realized natural gas prices and a 1% decrease in crude oil production. These decreases were partially offset by a 32% increase in natural gas production. The increase in cash flows provided by operating activities for the year ended December 31, 2018 as compared to 2017 was primarily the result of a 22% increase in crude oil production, a 27% increase in realized prices for crude oil, a 33% increase in natural gas production and a 2% increase in realized prices for natural gas.
Working capital. Our working capital fluctuates primarily as a result of changes in commodity pricing and production volumes, capital spending to fund our exploratory and development initiatives and acquisitions and the impact of our outstanding derivative instruments. We had a working capital deficit of $165.5 million at December 31, 2019 due to the impact of decreases in the forward commodity price curve on our short-term derivative instruments and decreases in accounts receivable, partially offset by decreases in accrued liabilities for crude oil and natural gas purchases used to optimize transportation costs or for blending and accrued liabilities for G&A expenses. However, we believe we have adequate liquidity to meet our working capital requirements. As of December 31, 2019, we had $882.7 million of liquidity available, including $20.0 million in cash
68
and cash equivalents and $862.7 million of aggregate unused borrowing capacity available under our Revolving Credit Facilities. As of December 31, 2018, we had a working capital deficit of $57.6 million.
Cash flows used in investing activities
We had net cash flows used in investing activities of $828.8 million, $1,613.5 million and $714.8 million for the years ended December 31, 2019, 2018 and 2017, respectively, primarily as a result of our capital expenditures for acquisition, drilling and development costs. The decrease in cash used in investing activities for the year ended December 31, 2019 as compared to the year ended December 31, 2018 was primarily attributable to a decrease in cash used for acquisitions year over year, and a 24% decrease in cash capital expenditures primarily for drilling and development costs. Net cash used in investing activities during the year ended December 31, 2019 was primarily attributable to $869.2 million in capital expenditures, coupled with $21.0 million in acquisitions, partially offset by $42.4 million for proceeds from sale of properties and $19.1 million for derivative settlements received as a result of lower crude oil prices. Net cash used in investing activities during the year ended December 31, 2018 was primarily attributable to $1,149.0 million in other capital expenditures for the development of our properties, including E&P capital, the second natural gas processing plant, and other midstream infrastructure coupled with $581.7 million for acquisitions, primarily for the Permian Basin Acquisition and an acquisition to acquire certain exploration and production assets adjacent to the our existing Delaware position (“Other Delaware Acquisition”), and $213.5 million for derivative settlements paid as a result of higher crude oil prices, partially offset by $333.2 million for proceeds from sale of properties. Net cash used in investing activities during the year ended December 31, 2017 was primarily attributable to $647.3 million in other capital expenditures for the development of our properties, including E&P capital, the second natural gas processing plant and other midstream infrastructure, coupled with $61.9 million for acquisitions, including the deposit of $47.3 million paid as part of the Permian Basin Acquisition, and $8.3 million for derivative settlements paid as a result of higher crude oil prices, partially offset by $5.8 million for proceeds from sale of properties.
Expenditures for the acquisition and development of oil and gas properties are the primary use of our capital resources. Our capital expenditures for the years ended December 31, 2019, 2018 and 2017 are summarized in the following table:
| Year ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Capital expenditures | |||||||||||||||||||||||||||||
| E&P | $ | 594,217 | $ | 942,179 | $ | 517,329 | |||||||||||||||||||||||
| Well services | 282 | 7,831 | 12,537 | ||||||||||||||||||||||||||
|
Other capital expenditures(1)
|
15,478 | 23,947 | 17,215 | ||||||||||||||||||||||||||
| Total capital expenditures before acquisitions and midstream | $ | 609,977 | $ | 973,957 | $ | 547,081 | |||||||||||||||||||||||
|
Midstream(2)
|
212,381 | 277,626 | 235,090 | ||||||||||||||||||||||||||
| Total capital expenditures before acquisitions | 822,358 | 1,251,583 | 782,171 | ||||||||||||||||||||||||||
| Acquisitions | 21,010 | 951,870 | 54,033 | ||||||||||||||||||||||||||
|
Total capital expenditures(3)
|
$ | 843,368 | $ | 2,203,453 | $ | 836,204 | |||||||||||||||||||||||
__________________
(1)Other capital expenditures includes administrative capital and capitalized interest.
(2)Midstream capital expenditures attributable to OMP were $198.6 million and $116.6 million for the years ended December 31, 2019 and 2018, respectively.
(3)Total capital expenditures (including acquisitions) reflected in the table above differs from the amounts for capital expenditures and acquisitions shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis. In addition, for the year ended December 31, 2018, total capital expenditures (including acquisitions) reflected in the table includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition. See Note 10 to our consolidated financial statements for more information on the Permian Basin Acquisition.
In 2019, we spent $843.4 million on capital expenditures, which represented a 62% decrease as compared to the $2,203.5 million spent during 2018. This decrease was primarily due to a $930.9 million decrease in acquisitions year over year. Excluding acquisitions, capital expenditures decreased 34% as compared to 2018. This decrease was attributable to decreased drilling and completion activity as a result of lower commodity prices in 2019, coupled with lower capital expenditures for midstream as a result of completing the second natural gas processing plant in Wild Basin during the fourth quarter of 2018.
On February 22, 2019, we entered into a memorandum of understanding (the “MOU”) with OMP regarding the funding of Bobcat DevCo’s expansion capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”).
69
Pursuant to the MOU, in exchange for increasing its percentage ownership interest in Bobcat DevCo, OMP agreed to make up to $80.0 million of the capital contributions to Bobcat DevCo that OMS would otherwise have been required to contribute. During the year ended December 31, 2019, OMP made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $73.0 million. As a result, OMS’s ownership interest in Bobcat DevCo decreased from 75% as of December 31, 2018 to 64.7% as of December 31, 2019. The 2019 Capital Expenditures Arrangement ended on December 31, 2019.
As a result of current crude oil prices, we have decreased our planned 2020 capital expenditures as compared to 2019 capital expenditures, excluding acquisitions. We anticipate investing between $685 million and $715 million in 2020 as follows:
| Plan for the year ended December 31, 2020 | |||||
| (In thousands) | |||||
|
E&P and other capital(1)
|
$575,000 - $595,000 | ||||
|
Midstream capital(2)
|
110,000 - 120,000 | ||||
| Total capital expenditures | $685,000 - $715,000 | ||||
__________________
(1)E&P and other capital expenditures includes administrative capital and excludes capitalized interest of approximately $12.5 million.
(2)Midstream capital expenditures include approximately $42 million to $45 million for midstream capital expenditures attributable to Oasis.
While we have planned approximately $685 million to $715 million for total capital expenditures in 2020, the ultimate amount of capital we will expend may fluctuate materially based on market conditions and the success of our drilling and operations results as the year progresses. Furthermore, if we acquire additional acreage, our capital expenditures may be higher than planned. We believe that cash on hand, including cash flows from operating activities, proceeds from cash settlements under our derivative contracts and availability under our Revolving Credit Facilities should be sufficient to fund our 2020 capital expenditure plan and to meet our future obligations. However, because the operated wells funded by our 2020 drilling plan represent only a small percentage of our potential drilling locations, we will be required to generate or raise multiples of this amount of capital to develop our entire inventory of potential drilling locations should we elect to do so.
Our capital plan may further be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If crude oil prices decline substantially or for an extended period of time, we could defer a significant portion of our planned capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control. We actively review acquisition opportunities on an ongoing basis. Our ability to make significant acquisitions for cash would require us to obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us or at all.
Cash flows provided by (used in) financing activities
Net cash provided by (used in) financing activities was $(66.3) million, $622.6 million and $212.4 million for the years ended December 31, 2019, 2018 and 2017, respectively. For the year ended December 31, 2019, net cash used in financing activities was primarily attributable to the repurchase of a portion of our Senior Notes (as defined below) and distributions to non-controlling interests. For the year ended December 31, 2018, cash sourced through financing activities was provided by the borrowings under our Revolving Credit Facilities, proceeds from the issuance of senior unsecured notes and net proceeds from the sale of OMP common units (see Note 3—Oasis Midstream Partners), net of offering costs, offset by principal payments on our Revolving Credit Facilities and the repurchase of a portion of our Senior Notes. For the year ended December 31, 2017, cash sourced through financing activities was provided by net proceeds from the issuance of our common stock, net of offering costs, and net proceeds from the sale of OMP common units, net of offering costs, partially offset by principal payments on our Revolving Credit Facilities.
Senior secured revolving line of credit. We have the Oasis Credit Facility, which has an overall senior secured line of credit of $3,000.0 million as of December 31, 2019. The Oasis Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. The maturity date of the Oasis Credit Facility is the earlier of (i) October 16, 2023, (ii) 90 days prior to the maturity date of our 2022 and 2023 Senior Notes (as defined below), of which $1,242.9 million is outstanding, to the extent such 2022 and 2023 Senior Notes are not retired or refinanced to have a maturity date at least 90 days after October 16, 2023 and (iii) 90 days prior to the maturity date of our 2023 Senior Convertible Notes (as defined below), of which $267.8 million is outstanding, to the extent such 2023 Senior
70
Convertible Notes are not retired, converted, redeemed or refinanced to have a maturity date at least 90 days after October 16, 2023.
On April 15, 2019, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2019, which reaffirmed the borrowing base and the aggregate elected commitment at $1,600.0 million and $1,350.0 million, respectively. In connection with the April 1, 2019 borrowing base redetermination, we entered into the First Amendment to the Third Amended and Restated Credit Agreement to the Oasis Credit Facility, dated April 15, 2019, which, among other things, incorporated the ability for us to request swingline loans subject to a swingline loans sublimit of $50.0 million.
On November 4, 2019, the lenders under the Oasis Credit Facility completed their semi-annual redetermination of the borrowing base scheduled for October 1, 2019. As a result, the borrowing base decreased from $1,600.0 million to $1,300.0 million. The next redetermination of the Oasis Credit Facility’s borrowing base is scheduled for April 1, 2020. Additionally, we entered into the third amendment to the Oasis Credit Facility, which among other things, decreased the aggregate elected commitment from $1,350.0 million to $1,100.0 million in conjunction with the redetermination.
As of December 31, 2019, the Oasis Credit Facility contains covenants that include, among others:
•a prohibition against incurring debt, subject to permitted exceptions;
•a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
•a prohibition against making investments, loans and advances, subject to permitted exceptions;
•restrictions on creating liens and leases on our assets and our subsidiaries, subject to permitted exceptions;
•restrictions on merging and selling assets outside the ordinary course of business;
•restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
•a provision limiting crude oil and natural gas derivative financial instruments;
•a requirement that we maintain a ratio of consolidated EBITDAX (as defined in the Oasis Credit Facility) to consolidated Interest Expense (as defined in the Oasis Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter;
•a requirement that we maintain a Current Ratio (as defined in the Oasis Credit Facility) of consolidated current assets (including unused borrowing capacity and with exclusions as described in the Oasis Credit Facility) to consolidated current liabilities (with exclusions as described in the Oasis Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter; and
•if the Aggregate Elected Commitment Amounts (as defined in the Oasis Credit Facility) exceed 85% of the effective borrowing base (“Trigger”), we are required to maintain a ratio of total debt (as defined in the Oasis Credit Facility) to consolidated EBITDAX (as defined in the Oasis Credit Facility) (the “Leverage Ratio”). The Leverage Ratio will be first tested during the quarter in which the Trigger occurs. The Leverage Ratio shall continue to be tested as long as the Aggregate Elected Commitment Amounts exceed 85% of the effective borrowing base, and shall not exceed 4.25 to 1.00 for the first two quarters and 4.00 to 1.00 for each fiscal quarter thereafter.
The Oasis Credit Facility contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Oasis Credit Facility to be immediately due and payable.
As of December 31, 2019, we had $337.0 million of borrowings at a weighted average interest rate of 3.5% and $15.1 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $747.9 million. As of December 31, 2018, we had $468.0 million of borrowings at a weighted average interest rate of 4.2% and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $868.0 million. We were in compliance with the financial covenants of the Oasis Credit Facility as of December 31, 2019 and 2018. Given the fluctuation in commodity prices, we continue to closely monitor our financial covenants and do not anticipate a covenant violation in the next twelve months.
OMP Operating LLC revolving line of credit. Through our majority ownership of OMP, we have access to the OMP Credit Facility, which is available to fund working capital and to finance acquisitions and other capital expenditures of OMP. On May 6, 2019, OMP entered into an amendment to the OMP Credit Facility to (i) increase the aggregate amount of commitments from $400.0 million to $475.0 million; (ii) provide for the ability to further increase commitments to $675.0 million; and (iii) add a new lender to the bank group. On August 16, 2019, OMP entered into the third amendment to the OMP Credit Facility to (i) increase the aggregate amount of commitments from $475.0 million to $575.0 million and (ii) provide for the ability to further increase commitments to $775.0 million. As of December 31, 2019, the OMP Credit Facility has an aggregate amount of commitments of $575.0 million and has a maturity date of September 25, 2022.
71
As of December 31, 2019, we had $458.5 million of borrowings outstanding at a weighted average interest rate of 3.8% and $1.7 million of outstanding letters of credit issued under the OMP Credit Facility, resulting in an unused borrowing capacity of $114.8 million. As of December 31, 2018, we had $318.0 million of borrowings outstanding at a weighted average interest rate of 4.2% under the OMP Credit Facility, resulting in an unused borrowing capacity of $82.0 million.
The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated total leverage ratio, (2) consolidated senior secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as described in the OMP Credit Agreement). All obligations of OMP Operating LLC, as the borrower under the OMP Credit Facility, are unconditionally guaranteed on a joint and several basis by OMP, Bighorn DevCo and Panther DevCo. OMP Operating LLC was in compliance with the financial covenants of the OMP Credit Facility at December 31, 2019.
Senior unsecured notes. As of December 31, 2019, our long-term debt includes outstanding senior unsecured note obligations of $1,714.8 million for senior unsecured notes (the “Senior Notes”), including $71.8 million of 6.50% senior unsecured notes due November 1, 2021 (the “2021 Notes”), $891.0 million of 6.875% senior unsecured notes due March 15, 2022 (the “2022 Notes”), $352.0 million of 6.875% senior unsecured notes due January 15, 2023 (the “2023 Notes”) and $400.0 million of 6.25% senior unsecured notes due May 1, 2026 (the “2026 Notes”).
During the fourth quarter of 2019, we repurchased an aggregate principal amount of $24.6 million of our outstanding Senior Notes, consisting of $10.5 million principal amount of the 2022 Notes and $14.1 million principal amount of the 2023 Notes, for an aggregate cost of $22.8 million. As a result of these repurchases, we recognized a pre-tax gain of $1.6 million, which was net of unamortized deferred financing costs write-offs of $0.2 million, and is reflected in gain on extinguishment of debt in our Consolidated Statements of Operations for the year ended December 31, 2019.
Prior to certain dates, we have the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. We may from time to time seek to retire or purchase our outstanding Senior Notes through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
The indentures governing the Senior Notes restrict our ability and the ability of certain of our subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when our Senior Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and we will cease to be subject to such covenants. We were in compliance with the terms of the indentures for the Senior Notes as of December 31, 2019.
Senior unsecured convertible notes. At December 31, 2019, we had $267.8 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”). The Senior Convertible Notes will mature on September 15, 2023 unless earlier converted in accordance with their terms.
During the fourth quarter of 2019, we repurchased a principal amount of $32.2 million of our outstanding Senior Convertible Notes, for an aggregate cost of $23.0 million. As a result of these repurchases, we recognized a pre-tax gain of $2.7 million, which was net of the unamortized debt discount write-offs of $6.2 million and the unamortized deferred financing costs write-offs of $0.3 million, and is reflected in gain on extinguishment of debt in our Consolidated Statements of Operations for the year ended December 31, 2019.
We have the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at out election. Our intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on September 30, 2016 (and only during such calendar quarter), if the last reported sale price of our common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “Measurement Period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the Measurement Period is less than 98% of the product of the last reported sale price of our common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding the September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of our common stock per $1,000 principal amount of the notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in
72
some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, we will increase the conversion rate for a holder who elects to convert the Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of December 31, 2019, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met. In addition, we were in compliance with the terms of the indentures for the Senior Convertible Notes as of December 31, 2019.
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by our material subsidiaries.
Subsequent to December 31, 2019, we repurchased a principal amount of $27.9 million of our outstanding Notes, for an aggregate cost of $22.2 million, including accrued interest, which will be reflected in our Consolidated Financial Statements subsequent to the year ended December 31, 2019.
Obligations and commitments
We have the following contractual obligations and commitments as of December 31, 2019:
| Payments due by period | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Contractual obligations | Total |
Within 1
year |
1-3 years | 3-5 years |
More than
5 years |
||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Senior unsecured notes(1)
|
$ | 1,982,568 | $ | — | $ | 962,815 | $ | 619,753 | $ | 400,000 | |||||||||||||||||||||||||||||||||||||||||||
|
Interest payments on senior unsecured notes(1)
|
450,676 | 122,288 | 209,442 | 81,446 | 37,500 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Borrowings under Oasis Credit Facility(1)
|
337,000 | — | — | 337,000 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Borrowings under OMP Credit Facility(1)
|
458,500 | — | 458,500 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Interest payments on borrowings under Oasis Credit Facility(1)
|
365 | 365 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Interest payments on borrowings under OMP Credit Facility(1)
|
508 | 508 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Asset retirement obligations(2)
|
56,784 | 1,909 | 1,987 | 175 | 52,713 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Finance leases(3)
|
7,908 | 3,009 | 3,909 | 351 | 639 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Operating leases(3)
|
60,791 | 20,217 | 11,476 | 10,019 | 19,079 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Volume commitment agreements(4)
|
594,537 | 82,515 | 202,078 | 169,662 | 140,282 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total contractual cash obligations | $ | 3,949,637 | $ | 230,811 | $ | 1,850,207 | $ | 1,218,406 | $ | 650,213 | |||||||||||||||||||||||||||||||||||||||||||
__________________
(1)See Note 13 to our consolidated financial statements for a description of our senior unsecured notes, Revolving Credit Facilities and related interest payments. As of December 31, 2019, we had $337.0 million of borrowings and $15.1 million of outstanding letters of credit issued under the Oasis Credit Facility and $458.5 million of borrowings and $1.7 million of outstanding letters of credit issued under the OMP Credit Facility.
(2)Amounts represent the present value of estimated costs expected to be incurred in the future to plug, abandon and remediate our oil and gas properties and produced and flowback water disposal wells at the end of their productive lives. 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 14 to our consolidated financial statements.
(3)See Note 20 to our consolidated financial statements for a description of our operating and finance leases.
(4)See Note 22 to our consolidated financial statements for a description of our volume commitment agreements.
Critical accounting policies and estimates
The discussion and analysis of our financial condition and results of operations are based upon our audited consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that
73
are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments used in preparation of our consolidated financial statements below. See Note 2 to our consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
Method of accounting for oil and gas properties
Crude oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.
The provision for DD&A of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate in which case a gain or loss is recognized currently.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in our Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
For sales of entire working interests in unproved properties, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
Crude oil and natural gas reserve quantities and standardized measure of future net revenue
Our independent reserve engineers and technical staff prepare our estimates of crude oil and natural gas reserves and associated future net revenues. While the SEC rules allow us to disclose proved, probable and possible reserves, we have elected to disclose only proved reserves in this Annual Report on Form 10-K. The SEC’s rules define proved reserves as the quantities of crude oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Our independent reserve engineers and technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates are updated annually and consider recent production levels and other technical information about each field. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. Accordingly, reserve estimates are generally different from the quantities of crude oil and natural gas that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of assets that may be material.
74
Revenue recognition
We apply the Accounting Standards Codification Topic 606 (“ASC 606”) using the modified retrospective method. We apply ASC 606 to all new contracts entered into after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of December 31, 2017. ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.
Crude oil, natural gas and NGL revenues from our interests in producing wells are recognized when we satisfy a performance obligation by transferring control of a product to a customer. Substantially all of our crude oil and natural gas production is sold to purchasers under short-term (less than twelve-month) contracts at market-based prices, and our NGL production is sold to purchasers under long-term (more than twelve-month) contracts at market-based prices. The sales prices for crude oil, natural gas and NGLs are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for crude oil, natural gas and NGL, we sell the majority of our production soon after it is produced at various locations. As a result, we maintain a minimum amount of product inventory in storage.
Our purchased crude oil and natural gas sales are derived from the sales of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as we act as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, we enter into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with Accounting Standards Codification 845, Nonmonetary Transactions.
Midstream revenues consist of revenues from midstream services provided through OMS, including (i) crude oil gathering, stabilization, blending, storage and transportation, (ii) natural gas gathering, gas lift, compression and processing, (iii) produced and flowback water gathering and disposal and (iv) freshwater supply and distribution. Midstream revenues are earned through fee-based arrangements, under which we receive fees for midstream services it provides to customers and recognizes revenue based upon the transaction price at month-end under the right to invoice practical expedient, or through purchase arrangements, under which we take control of the product prior to sale and act as the principal in the transaction, and therefore, recognize revenues and expenses on a gross basis. Well services revenues result from well services, product sales and equipment rentals provided by OWS primarily for OPNA’s operated wells. Midstream and well services revenues are recognized when services have been performed or related volumes or products have been delivered. The revenues related to OPNA’s working interests are eliminated in consolidation, and only the revenues related to other working interest owners in OPNA’s wells are included in our Consolidated Statements of Operations.
Impairment of proved properties
We review our proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the expected undiscounted future cash flows of our oil and gas properties by field and compare such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to our judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to our judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, our estimated undiscounted future cash flows and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges for proved oil and gas properties will be recorded. Please see “Overview” for a discussion of potential future impairment charges.
Impairment of unproved properties
The assessment of unproved properties to determine any possible impairment requires significant judgment. We assess our unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage.
75
We recognize impairment expense for unproved properties at the time when the lease term has expired or sooner based on management’s periodic assessments. We consider the following factors in our assessment of the impairment of unproved properties:
•the remaining amount of unexpired term under our leases;
•our ability to actively manage and prioritize our capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;
•our ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
•our ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
•our evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations in the Williston Basin and the Bone Spring and Wolfcamp formations in the Delaware Basin by us or by other operators in areas adjacent to or near our unproved properties.
Business combinations
We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.
We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, we review comparable purchases and sales of oil and gas properties within the same regions, and use that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Asset retirement obligations
We record the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The asset retirement obligation (“ARO”) represents the estimated amount we will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period, and the capitalized costs are amortized on the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in our Consolidated Statements of Operations.
Some of our midstream assets, including certain pipelines and our natural gas processing plants, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned. We are not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement dates are indeterminable given our expected continued use of the assets with proper maintenance. We will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably determinable.
We determine the ARO by calculating the present value of estimated future cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to future revisions, which could result in an increase to the existing ARO liability and could ultimately result in a higher potential impact on our operations and cash flows
76
for settlement charges. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Derivatives
We record all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. The significant inputs used to estimate fair value are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. We have not designated any derivative instruments as hedges for accounting purposes, and we do not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported under other income (expense) in our Consolidated Statements of Operations. Our cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on our derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in our Consolidated Statements of Cash Flows.
Equity-based compensation
Restricted stock awards
We recognize compensation expense for all restricted stock awards made to our employees and directors. Equity-based compensation expense is measured at the grant date based on the fair value of the award and is recognized as expense ratably over the requisite service period, which is generally the vesting period. The fair value of restricted stock grants is based on the closing sales price of our common stock on the date of grant or, if applicable, the date of modification. Any such changes could result in different valuations and thus impact the amount of equity-based compensation expense recognized. Equity-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on our Consolidated Statements of Operations. Forfeitures associated with restricted stock awards granted are accounted for when they occur.
Performance share units
We recognize compensation expense for our performance share units (“PSUs”) granted to our officers. The fair value of the PSUs is based on the calculation derived from a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment (see Note 16 to our consolidated financial statements for a description of the inputs used in this model). Equity-based compensation expense recorded for PSUs is included in general and administrative expenses on our Consolidated Statements of Operations. Forfeitures associated with PSUs granted are accounted for when they occur.
OMP Phantom Unit Awards
We recognize compensation expense for phantom unit awards based on OMP common units (collectively, the “OMP Phantom Unit Awards,” and each an “OMP Phantom Unit”) granted to our employees. The OMP Phantom Unit Awards are accounted for as liability-classified awards since the awards will settle in cash. The OMP Phantom Unit Awards vest in equal amounts each year over a three-year period, and compensation expense will be recognized over the requisite service period and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. Compensation cost is remeasured each reporting period at fair value based upon the closing price of a publicly traded common unit. The Company will directly pay, or will reimburse OMP, for the cash settlement amount of these awards. Forfeitures associated with OMP Phantom Unit Awards granted are accounted for when they occur.
Income taxes
Our provision for taxes includes both federal and state taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP, which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.
77
We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.
Recent accounting pronouncements
See Note 2 to our consolidated financial statements for a description of the effect of recent accounting pronouncements 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 our results of operations for the years ended December 31, 2019, 2018 and 2017. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy, and in the past, we have tended to experience inflationary pressure on the cost of midstream and oilfield services and equipment as increasing crude oil and natural gas prices increased drilling activity in our areas of operations.
Off-balance sheet arrangements
Currently, we do not have any off-balance sheet arrangements as defined by the SEC. In the ordinary course of business, we enter into various commitment agreements and other contractual obligations, some of which are not recognized in our consolidated financial statements in accordance with GAAP. See “Obligations and commitments” above and Note 22 to our consolidated financial statements for a description of our commitments and contingencies.
Non-GAAP Financial Measures
E&P Cash G&A, Cash MT&G, Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share are supplemental non-GAAP financial measures that are used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. These non-GAAP financial measures should not be considered in isolation or as a substitute for general and administrative expenses, marketing, transportation and gathering expense, interest expense, net income (loss), operating income (loss), net cash provided by (used in) operating activities, earnings (loss) per share or any other measures prepared under GAAP. Because E&P Cash G&A, Cash MT&G, Cash Interest, Adjusted EBITDA, Free Cash Flow, Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share exclude some but not all items that affect net income (loss) and may vary among companies, the amounts presented may not be comparable to similar metrics of other companies.
E&P Cash G&A
We define E&P Cash G&A as the total general and administrative expenses included in our exploration and production segment less non-cash equity-based compensation expenses and other non-cash charges included in our exploration and production segment. E&P Cash G&A is not a measure of general and administrative expenses as determined by GAAP. Management believes that the presentation of E&P Cash G&A provides useful additional information to investors and analysts to assess our operating costs in comparison to peers without regard to equity-based compensation programs, which can vary substantially from company to company.
The following table presents a reconciliation of the GAAP financial measure of general and administrative expenses included in our exploration and production segment to the non-GAAP financial measure of E&P Cash G&A for the periods presented:
| Exploration and Production | ||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
| General and administrative expenses | $ | 118,701 | $ | 102,482 | $ | 77,560 | ||||||||||||||||||||||||||
| Equity-based compensation expenses | (32,251) | (27,910) | (25,436) | |||||||||||||||||||||||||||||
|
Litigation contingency expenses(1)
|
(20,000) | — | — | |||||||||||||||||||||||||||||
| E&P Cash G&A | $ | 66,450 | $ | 74,572 | $ | 52,124 | ||||||||||||||||||||||||||
____________________
78
(1)In 2019, we incurred a charge to establish a loss accrual of $20.0 million, which we believe is the estimable amount of loss that could potentially be incurred from our pending legal proceedings based upon currently available information.
Cash MT&G
We define Cash MT&G as the total marketing, transportation and gathering expenses less non-cash valuation charges on pipeline imbalances. Cash MT&G is not a measure of marketing, transportation and gathering expenses as determined by GAAP. Management believes that the presentation of Cash MT&G provides useful additional information to investors and analysts to assess the cash costs incurred to get its commodities to market without regard for the change in value of its pipeline imbalances, which vary monthly based on commodity prices.
The following table presents a reconciliation of the GAAP financial measure of marketing, transportation and gathering expenses to the non-GAAP financial measure of Cash MT&G for the periods presented:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Marketing, transportation and gathering expenses | $ | 128,806 | $ | 107,193 | $ | 55,740 | |||||||||||||||||||||||
| Pipeline imbalances | (2,446) | (4,331) | 812 | ||||||||||||||||||||||||||
| Cash MT&G | $ | 126,360 | $ | 102,862 | $ | 56,552 | |||||||||||||||||||||||
Cash Interest
We define Cash Interest as interest expense plus capitalized interest less amortization and write-offs of deferred financing costs and debt discounts included in interest expense. Cash Interest is not a measure of interest expense as determined by GAAP. Management believes that the presentation of Cash Interest provides useful additional information to investors and analysts for assessing the interest charges incurred on our debt, excluding non-cash amortization, and our ability to maintain compliance with our debt covenants.
The following table presents a reconciliation of the GAAP financial measure of interest expense to the non-GAAP financial measure of Cash Interest for the periods presented:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Interest expense | $ | 176,223 | $ | 159,085 | $ | 146,837 | |||||||||||||||||||||||
| Capitalized interest | 11,964 | 17,226 | 12,797 | ||||||||||||||||||||||||||
| Amortization of deferred financing costs | (8,832) | (7,590) | (6,907) | ||||||||||||||||||||||||||
| Amortization of debt discount | (12,164) | (11,120) | (10,080) | ||||||||||||||||||||||||||
| Cash Interest | $ | 167,191 | $ | 157,601 | $ | 142,647 | |||||||||||||||||||||||
Adjusted EBITDA and Free Cash Flow
We define Adjusted EBITDA as earnings (loss) before interest expense, income taxes, DD&A, exploration expenses and other similar non-cash or non-recurring charges. Adjusted EBITDA is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Adjusted EBITDA provides useful additional information to investors and analysts for assessing our results of operations, financial performance and our ability to generate cash from our business operations without regard to our financing methods or capital structure coupled with our ability to maintain compliance with our debt covenants.
We define Free Cash Flow as Adjusted EBITDA attributable to Oasis less Cash Interest and capital expenditures, excluding capitalized interest. Free Cash Flow is not a measure of net income (loss) or cash flows as determined by GAAP. Management believes that the presentation of Free Cash Flow provides useful additional information to investors and analysts for assessing our financial performance as compared to our peers and our ability to generate cash from our business operations after interest and capital spending. In addition, Free Cash Flow excludes changes in operating assets and liabilities that relate to the timing of cash receipts and disbursements, which we may not control, and changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.
79
The following table presents reconciliations of the GAAP financial measures of net income (loss) including non-controlling interests and net cash provided by operating activities to the non-GAAP financial measures of Adjusted EBITDA and Free Cash Flow for the periods presented:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | $ | (90,647) | $ | (19,500) | $ | 127,446 | |||||||||||||||||||||||
| (Gain) loss on sale of properties | 4,455 | (28,587) | (1,774) | ||||||||||||||||||||||||||
| (Gain) loss on extinguishment of debt | (4,312) | 13,848 | — | ||||||||||||||||||||||||||
| Net (gain) loss on derivative instruments | 106,314 | (28,457) | 71,657 | ||||||||||||||||||||||||||
|
Derivative settlements(1)
|
19,098 | (213,528) | (8,264) | ||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | 176,223 | 159,085 | 146,837 | ||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 787,192 | 636,296 | 530,802 | ||||||||||||||||||||||||||
| Impairment | 10,257 | 384,228 | 6,887 | ||||||||||||||||||||||||||
| Rig termination | 384 | — | — | ||||||||||||||||||||||||||
| Exploration expenses | 6,658 | 27,432 | 11,600 | ||||||||||||||||||||||||||
| Equity-based compensation expenses | 33,607 | 29,273 | 26,534 | ||||||||||||||||||||||||||
| Income tax benefit | (32,715) | (5,843) | (203,304) | ||||||||||||||||||||||||||
|
Litigation contingency expenses(2)
|
20,000 | — | — | ||||||||||||||||||||||||||
| Other non-cash adjustments | 3,035 | 4,435 | (745) | ||||||||||||||||||||||||||
| Adjusted EBITDA | 1,039,549 | 958,682 | 707,676 | ||||||||||||||||||||||||||
| Adjusted EBITDA attributable to non-controlling interests | 51,525 | 21,703 | 3,904 | ||||||||||||||||||||||||||
| Adjusted EBITDA attributable to Oasis | 988,024 | 936,979 | 703,772 | ||||||||||||||||||||||||||
| Cash Interest | (167,191) | (157,601) | (142,647) | ||||||||||||||||||||||||||
|
Capital expenditures(3)
|
(843,368) | (2,203,453) | (836,204) | ||||||||||||||||||||||||||
| Capitalized interest | 11,964 | 17,226 | 12,797 | ||||||||||||||||||||||||||
| Free Cash Flow | $ | (10,571) | $ | (1,406,849) | $ | (262,282) | |||||||||||||||||||||||
| Net cash provided by operating activities | $ | 892,853 | $ | 996,421 | $ | 507,876 | |||||||||||||||||||||||
|
Derivative settlements(1)
|
19,098 | (213,528) | (8,264) | ||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | 176,223 | 159,085 | 146,837 | ||||||||||||||||||||||||||
| Rig termination | 384 | — | — | ||||||||||||||||||||||||||
| Exploration expenses | 6,658 | 27,432 | 11,600 | ||||||||||||||||||||||||||
| Deferred financing costs amortization and other | (27,263) | (29,057) | (18,311) | ||||||||||||||||||||||||||
| Current tax expense | (16) | 23 | (421) | ||||||||||||||||||||||||||
| Changes in working capital | (51,423) | 13,871 | 69,104 | ||||||||||||||||||||||||||
|
Litigation contingency expenses(2)
|
20,000 | — | — | ||||||||||||||||||||||||||
| Other non-cash adjustments | 3,035 | 4,435 | (745) | ||||||||||||||||||||||||||
| Adjusted EBITDA | 1,039,549 | 958,682 | 707,676 | ||||||||||||||||||||||||||
| Adjusted EBITDA attributable to non-controlling interests | 51,525 | 21,703 | 3,904 | ||||||||||||||||||||||||||
| Adjusted EBITDA attributable to Oasis | 988,024 | 936,979 | 703,772 | ||||||||||||||||||||||||||
| Cash Interest | (167,191) | (157,601) | (142,647) | ||||||||||||||||||||||||||
|
Capital expenditures(3)
|
(843,368) | (2,203,453) | (836,204) | ||||||||||||||||||||||||||
| Capitalized interest | 11,964 | 17,226 | 12,797 | ||||||||||||||||||||||||||
| Free Cash Flow | $ | (10,571) | $ | (1,406,849) | $ | (262,282) | |||||||||||||||||||||||
____________________
(1)Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
80
(2)In 2019, we incurred a charge to establish a loss accrual of $20.0 million, which we believe is the estimable amount of loss that could potentially be incurred from our pending legal proceedings based upon currently available information.
(3)Capital expenditures (including acquisitions) reflected in the table above differ from the amounts shown in the statements of cash flows in our consolidated financial statements because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the statements of cash flows are presented on a cash basis. Acquisitions totaled $21.0 million, $951.9 million and $54.0 million for the years ended December 31, 2019, 2018 and 2017, respectively. In addition, capital expenditures (including acquisitions) reflected in the table above includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition for the year ended December 31, 2018. See Note 10 to our consolidated financial statements for more information on the Permian Basin Acquisition.
The following tables present reconciliations of the GAAP financial measure of income (loss) before income taxes including non-controlling interests to the non-GAAP financial measure of Adjusted EBITDA for our three reportable business segments on a gross basis for the periods presented:
| Exploration and Production | ||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
| Loss before income taxes including non-controlling interests | $ | (332,069) | $ | (167,292) | $ | (179,129) | ||||||||||||||||||||||||||
| (Gain) loss on sale of properties | 4,455 | (38,188) | (1,774) | |||||||||||||||||||||||||||||
| (Gain) loss on extinguishment of debt | (4,312) | 13,848 | — | |||||||||||||||||||||||||||||
| Net (gain) loss on derivative instruments | 106,314 | (28,457) | 71,657 | |||||||||||||||||||||||||||||
|
Derivative settlements(1)
|
19,098 | (213,528) | (8,264) | |||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | 159,287 | 156,742 | 146,818 | |||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 766,959 | 618,402 | 519,853 | |||||||||||||||||||||||||||||
| Impairment | 5,856 | 384,228 | 6,887 | |||||||||||||||||||||||||||||
| Exploration expenses | 6,658 | 27,432 | 11,600 | |||||||||||||||||||||||||||||
| Rig termination | 384 | — | — | |||||||||||||||||||||||||||||
| Equity-based compensation expenses | 32,251 | 27,910 | 25,436 | |||||||||||||||||||||||||||||
|
Litigation contingency expenses(2)
|
20,000 | — | — | |||||||||||||||||||||||||||||
| Other non-cash adjustments | 2,446 | 4,331 | (812) | |||||||||||||||||||||||||||||
| Adjusted EBITDA | $ | 787,327 | $ | 785,428 | $ | 592,272 | ||||||||||||||||||||||||||
____________________
(1)Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)In 2019, we incurred a charge to establish a loss accrual of $20.0 million, which we believe is the estimable amount of loss that could potentially be incurred from our pending legal proceedings based upon currently available information.
| Midstream | ||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
| Income before income taxes including non-controlling interests | $ | 224,096 | $ | 141,001 | $ | 102,340 | ||||||||||||||||||||||||||
| Loss on sale of properties | — | 9,622 | — | |||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | 16,936 | 2,343 | 19 | |||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 37,152 | 29,282 | 15,999 | |||||||||||||||||||||||||||||
| Equity-based compensation expenses | 1,744 | 1,547 | 1,461 | |||||||||||||||||||||||||||||
| Adjusted EBITDA | $ | 279,928 | $ | 183,795 | $ | 119,819 | ||||||||||||||||||||||||||
81
| Well Services | ||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
| Income (loss) before income taxes including non-controlling interests | $ | (1,866) | $ | 31,023 | $ | 15,091 | ||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 13,631 | 15,698 | 12,939 | |||||||||||||||||||||||||||||
| Impairment | 4,401 | — | — | |||||||||||||||||||||||||||||
| Equity-based compensation expenses | 1,397 | 1,588 | 1,264 | |||||||||||||||||||||||||||||
| Other non-cash adjustments | 589 | 104 | 67 | |||||||||||||||||||||||||||||
| Adjusted EBITDA | $ | 18,152 | $ | 48,413 | $ | 29,361 | ||||||||||||||||||||||||||
Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share
We define Adjusted Net Income (Loss) Attributable to Oasis as net income (loss) after adjusting for (1) the impact of certain non-cash items, including non-cash changes in the fair value of derivative instruments, impairment and other similar non-cash charges or non-recurring items, (2) the impact of net income attributable to non-controlling interests and (3) the non-cash and non-recurring items’ impact on taxes based on our effective tax rate applicable to those adjusting items, excluding net income attributable to non-controlling interests, in the same period. Adjusted Net Income (Loss) Attributable to Oasis is not a measure of net income (loss) as determined by GAAP. We define Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share as Adjusted Net Income (Loss) Attributable to Oasis divided by diluted weighted average shares outstanding. Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share is not a measure of diluted earnings (loss) per share as determined by GAAP. Management believes that the presentation of Adjusted Net Income (Loss) Attributable to Oasis and Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share provides useful additional information to investors and analysts for evaluating our operational trends and performance in comparison to our peers. This measure is more comparable to earnings estimates provided by securities analysts, and charges or amounts excluded cannot be reasonably estimated and are excluded from guidance provided by us.
82
The following table presents reconciliations of the GAAP financial measure of net income (loss) attributable to Oasis to the non-GAAP financial measure of Adjusted Net Income (Loss) Attributable to Oasis and the GAAP financial measure of diluted earnings (loss) attributable to Oasis per share to the non-GAAP financial measure of Adjusted Diluted Earnings (Loss) Attributable to Oasis Per Share for the periods presented:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||||||||||||||
| Net income (loss) attributable to Oasis | $ | (128,243) | $ | (35,296) | $ | 123,796 | |||||||||||||||||||||||
| Tax reform rate change adjustments | — | — | (171,900) | ||||||||||||||||||||||||||
| (Gain) loss on sale of properties | 4,455 | (28,587) | (1,774) | ||||||||||||||||||||||||||
| (Gain) loss on extinguishment of debt | (4,312) | 13,848 | — | ||||||||||||||||||||||||||
| Net (gain) loss on derivative instruments | 106,314 | (28,457) | 71,657 | ||||||||||||||||||||||||||
|
Derivative settlements(1)
|
19,098 | (213,528) | (8,264) | ||||||||||||||||||||||||||
| Impairment | 10,257 | 384,228 | 6,887 | ||||||||||||||||||||||||||
| Rig termination | 384 | — | — | ||||||||||||||||||||||||||
| Amortization of deferred financing costs | 8,832 | 7,591 | 6,907 | ||||||||||||||||||||||||||
| Amortization of debt discount | 12,164 | 11,120 | 10,080 | ||||||||||||||||||||||||||
|
Litigation contingency expenses(2)
|
20,000 | — | — | ||||||||||||||||||||||||||
| Other non-cash adjustments | 3,035 | 4,435 | (745) | ||||||||||||||||||||||||||
|
Tax impact(3)
|
(42,782) | (35,759) | (31,696) | ||||||||||||||||||||||||||
| Adjusted Net Income Attributable to Oasis | $ | 9,202 | $ | 79,595 | $ | 4,948 | |||||||||||||||||||||||
| Diluted earnings (loss) attributable to Oasis per share | $ | (0.41) | $ | (0.11) | $ | 0.52 | |||||||||||||||||||||||
| Tax reform rate change adjustments | — | — | (0.72) | ||||||||||||||||||||||||||
| (Gain) loss on sale of properties | 0.01 | (0.09) | (0.01) | ||||||||||||||||||||||||||
| (Gain) loss on extinguishment of debt | (0.01) | 0.04 | — | ||||||||||||||||||||||||||
| Net (gain) loss on derivative instruments | 0.34 | (0.09) | 0.30 | ||||||||||||||||||||||||||
|
Derivative settlements(1)
|
0.06 | (0.69) | (0.03) | ||||||||||||||||||||||||||
| Impairment | 0.03 | 1.24 | 0.03 | ||||||||||||||||||||||||||
| Rig termination | — | — | — | ||||||||||||||||||||||||||
| Amortization of deferred financing costs | 0.03 | 0.02 | 0.03 | ||||||||||||||||||||||||||
| Amortization of debt discount | 0.04 | 0.04 | 0.04 | ||||||||||||||||||||||||||
|
Litigation contingency expenses(2)
|
0.06 | — | — | ||||||||||||||||||||||||||
| Other non-cash adjustments | 0.01 | 0.01 | — | ||||||||||||||||||||||||||
|
Tax impact(3)
|
(0.13) | (0.11) | (0.14) | ||||||||||||||||||||||||||
| Adjusted Diluted Earnings Attributable to Oasis Per Share | $ | 0.03 | $ | 0.26 | $ | 0.02 | |||||||||||||||||||||||
|
Diluted weighted average shares outstanding(4)
|
315,324 | 310,860 | 237,875 | ||||||||||||||||||||||||||
| Effective tax rate applicable to adjustment items | 23.7 | % | 23.7 | % | 37.4 | % | |||||||||||||||||||||||
____________________
(1)Cash settlements represent the cumulative gains and losses on our derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled.
(2)In 2019, we incurred a charge to establish a loss accrual of $20.0 million, which we believe is the estimable amount of loss that could potentially be incurred from our pending legal proceedings based upon currently available information.
(3)The tax impact is computed utilizing our effective tax rate applicable to the adjustments for certain non-cash and non-recurring items. The tax impact was not computed for the tax reform rate change adjustments.
(4)We included 322,000, 3,379,000 and 2,889,000 unvested stock awards for the years ended December 31, 2019, 2018 and 2017, respectively, in computing Adjusted Diluted Earnings Attributable to Oasis Per Share due to the dilutive effect under the treasury stock method.
83
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer risk. We address these risks through a program of risk management, including the use of derivative instruments.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGL and crude oil prices, and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.
Commodity price exposure risk. We are exposed to market risk as the prices of crude oil, natural gas and NGLs fluctuate as a result of changes in supply and demand and other factors. To partially reduce price risk caused by these market fluctuations, we have entered into derivative instruments in the past and expect to enter into derivative instruments in the future to cover a significant portion of our future production.
We utilize derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. Our crude oil contracts will settle monthly based on the average NYMEX WTI. Our natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”).
As of December 31, 2019, we utilized fixed price swaps and two-way and three-way costless collars to reduce the volatility of crude oil prices on a significant portion of our future expected crude oil production. Our fixed price swaps are comprised of a sold call and a purchased put established at the same price (both ceiling and floor), which we will receive for the volumes under contract. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) we will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) we will receive for the volumes under contract.
We recognize all derivative instruments at fair value. The credit standing of our counterparties is analyzed and factored into the fair value amounts recognized on our Consolidated Balance Sheets. Derivative assets and liabilities arising from our derivative contracts with the same counterparty are also reported on a net basis, as all counterparty contracts provide for net settlement.
The following is a summary of our outstanding commodity derivative instruments as of December 31, 2019:
| Commodity |
Settlement
Period |
Derivative
Instrument |
Index | Volumes | Weighted Average Prices |
Fair Value
Assets (Liabilities) |
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fixed Price Swaps | Sub-Floor | Floor | Ceiling | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2020 | Fixed price swaps | NYMEX WTI | 6,550,000 | Bbl | $ | 57.17 | $ | (14,087) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2020 | Two-way collar | NYMEX WTI | 3,296,000 | Bbl | $ | 51.76 | $ | 61.76 | (4,743) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2020 | Three-way collar | NYMEX WTI | 5,339,000 | Bbl | $ | 40.00 | $ | 52.79 | $ | 64.06 | (330) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2021 | Fixed price swaps | NYMEX WTI | 248,000 | Bbl | $ | 56.05 | 36 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2021 | Two-way collar | NYMEX WTI | 248,000 | Bbl | $ | 50.75 | $ | 59.13 | (86) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2021 | Three-way collar | NYMEX WTI | 889,000 | Bbl | $ | 40.00 | $ | 51.04 | $ | 63.61 | 569 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| $ | (18,641) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
A 10% increase in crude oil prices would decrease the fair value of our derivative position by approximately $71.4 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $62.6 million.
Interest rate risk. At December 31, 2019, we had (i) $71.8 million of senior unsecured notes at a fixed cash interest rate of 6.50% per annum, (ii) $1,242.9 million of senior unsecured notes at a fixed cash interest rate of 6.875% per annum, (iii) $267.8 million of senior unsecured convertible notes at a fixed cash interest rate of 2.625% per annum outstanding and (iv) $400.0 million of senior unsecured notes at a fixed cash interest rate of 6.25% per annum.
At December 31, 2019, we had $337.0 million of borrowings and $15.1 million of outstanding letters of credit issued under the Oasis Credit Facility, which were subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a LIBOR loan or a
84
domestic bank prime interest rate loan (defined in each of the Revolving Credit Facilities as an Alternate Based Rate or “ABR” loan). At December 31, 2019, the outstanding borrowings under the Oasis Credit Facility bore interest at LIBOR plus a 1.75% margin. On a quarterly basis, we also pay a commitment fee that can range from 0.375% to 0.500% on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.
At December 31, 2019, we had $458.5 million of borrowings and $1.7 million of outstanding letters of credit issued under the OMP Credit Facility, which were subject to a per annum interest rate equal to the applicable margin (as described below) plus (i) with respect to Eurodollar Loans, the Adjusted LIBO Rate (as defined in the OMP Credit Agreement) or (ii) with respect to ABR loans, the greatest of (A) the Prime Rate in effect on such day, (B) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (C) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in the OMP Credit Agreement). The applicable margin for borrowings under the OMP Credit Facility is based on OMP’s most recently tested consolidated total leverage ratio and varies from (a) in the case of Eurodollar Loans, 1.75% to 2.75%, and (b) in the case of ABR loans or swingline loans, 0.75% to 1.75%. The unused portion of the OMP Credit Facility is subject to a commitment fee ranging from 0.375% to 0.500%. At December 31, 2019, the outstanding borrowings under the OMP Credit Facility bore interest at LIBOR plus a 2.00% margin.
We do not currently, but may in the future, utilize interest rate derivatives to alter interest rate exposure in an attempt to reduce interest rate expense related to debt issued under the Oasis Credit Facility or the OMP Credit Facility. Interest rate derivatives would be used solely to modify interest rate exposure and not to modify the overall leverage of the debt portfolio.
Counterparty and customer credit risk. Joint interest receivables arise from billing entities which own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we choose to drill. We have limited ability to control participation in our wells. For the year ended December 31, 2019, we recorded $0.2 million in bad debt expense as a result of our assessment that it is probable certain receivables may not be collected. We are also subject to credit risk due to concentration of our crude oil and natural gas receivables with several significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
We monitor our exposure to counterparties on crude oil and natural gas sales primarily by reviewing credit ratings, financial statements and payment history. We extend credit terms based on our evaluation of each counterparty’s credit worthiness. We have not generally required our counterparties to provide collateral to secure crude oil and natural gas sales receivables owed to us. Historically, our credit losses on crude oil and natural gas sales receivables have been immaterial.
In addition, our crude oil and natural gas derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. However, in order to mitigate the risk of nonperformance, we only enter into derivative contracts with counterparties that are high credit-quality financial institutions. Most of the counterparties on our derivative instruments currently in place are Lenders under the Oasis Credit Facility with investment grade ratings. We are likely to enter into any future derivative instruments with these or other Lenders under the Oasis Credit Facility, which also carry investment grade ratings. This risk is also managed by spreading our derivative exposure across several institutions and limiting the volumes placed under individual contracts. Furthermore, the agreements with each of the counterparties on our derivative instruments contain netting provisions. As a result of these netting provisions, our maximum amount of loss due to credit risk is limited to the net amounts due to and from the counterparties under the derivative contracts. We had a net derivative asset position of $1.2 million and a net derivative liability position of $19.8 million at December 31, 2019.
85
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of disclosure controls and procedures
As required by Rule 13a-15(b) of the Exchange Act, management, under the supervision and with the participation of our Chief Executive Officer (“CEO”), our principal executive officer, and our Chief Financial Officer (“CFO”), our principal financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2019. Our disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our CEO and CFO as appropriate, to allow timely decisions regarding required disclosure. Based on the evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2019 at the reasonable assurance level.
Management’s report on internal control over financial reporting
Management, including our CEO and CFO, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
As of December 31, 2019, management assessed the effectiveness of our internal control over financial reporting. In making this assessment, management, including our CEO and CFO, used the criteria set forth by the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this assessment, our CEO and CFO have concluded that our internal control over financial reporting was effective as of December 31, 2019.
PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this annual report on Form 10-K, has also audited the effectiveness of our internal control over financial reporting as of December 31, 2019 and has issued an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2019. Please see their “Report of Independent Registered Public Accounting Firm” included in Item 8 – Financial Statements and Supplementary Data.
Changes in internal control over financial reporting
There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
86
Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
87
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Oasis Petroleum Inc.
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Oasis Petroleum Inc. and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of operations, of changes in stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2019, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s report on internal control over financial reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or
88
disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
The Impact of Proved Oil and Natural Gas Reserves on Proved Oil and Natural Gas Properties, Net
As described in Notes 2 and 9 to the consolidated financial statements, the Company’s consolidated proved oil and natural gas properties, net balance was $5.1 billion as of December 31, 2019. Depreciation, depletion and amortization (DD&A) expense for the year ended December 31, 2019 was $787.2 million. For the year ended December 31, 2019, the Company did not record impairment of proved oil and natural gas properties. Oil and natural gas exploration and development activities are accounted for using the successful efforts method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of its carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. As disclosed by management, the factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. Periodic revisions to the estimated reserves and related future net cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, oil and natural gas prices, cost changes, technological advances, new geological or geophysical data or other economic factors. The estimates of oil and natural gas reserves have been developed by specialists, specifically petroleum engineers.
The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on proved oil and natural gas properties, net is a critical audit matter are there was significant judgment by management, including the use of specialists, when developing the estimates of proved oil and natural gas reserves. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the significant assumptions used in developing those estimates, including future production, future price differentials, and future development costs.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves, the calculation of DD&A expense and the impairment assessment of proved oil and natural gas properties. These procedures also included, among others, evaluating the significant assumptions used by management in developing these estimates, including future production, future price differentials and future development costs. Procedures were also performed to test the unit-of-production rate used to calculate DD&A expense and to test the identification of triggering events. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications and objectivity were understood, as well as the methods and assumptions used by the specialists. The procedures performed also included tests of the data used by the specialists and an evaluation of the specialists’ findings. Evaluating the significant assumptions relating to the estimates of proved oil and natural gas reserves also involved obtaining evidence to support the reasonableness of the assumptions, including whether the assumptions used were reasonable considering the past and current performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit.
/s/PricewaterhouseCoopers LLP
Houston, Texas
February 26, 2020
We have served as the Company’s auditor since 2007.
89
Oasis Petroleum Inc.
Consolidated Balance Sheets
| December 31, | |||||||||||||||||
| 2019 | 2018 | ||||||||||||||||
| (In thousands, except share data) | |||||||||||||||||
| ASSETS | |||||||||||||||||
| Current assets | |||||||||||||||||
| Cash and cash equivalents | $ | 20,019 | $ | 22,190 | |||||||||||||
| Accounts receivable, net | 371,181 | 387,602 | |||||||||||||||
| Inventory | 35,259 | 33,128 | |||||||||||||||
| Prepaid expenses | 10,011 | 10,997 | |||||||||||||||
| Derivative instruments | 535 | 99,930 | |||||||||||||||
| Intangible assets, net | — | 125 | |||||||||||||||
| Other current assets | 346 | 183 | |||||||||||||||
| Total current assets | 437,351 | 554,155 | |||||||||||||||
| Property, plant and equipment | |||||||||||||||||
| Oil and gas properties (successful efforts method) | 9,463,038 | 8,912,189 | |||||||||||||||
| Other property and equipment | 1,279,653 | 1,151,772 | |||||||||||||||
| Less: accumulated depreciation, depletion, amortization and impairment | (3,764,915) | (3,036,852) | |||||||||||||||
| Total property, plant and equipment, net | 6,977,776 | 7,027,109 | |||||||||||||||
| Assets held for sale, net | 21,628 | — | |||||||||||||||
| Derivative instruments | 639 | 6,945 | |||||||||||||||
| Long-term inventory | 13,924 | 12,260 | |||||||||||||||
| Operating right-of-use assets | 18,497 | — | |||||||||||||||
| Other assets | 29,438 | 25,673 | |||||||||||||||
| Total assets | $ | 7,499,253 | $ | 7,626,142 | |||||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||||||||
| Current liabilities | |||||||||||||||||
| Accounts payable | $ | 17,948 | $ | 20,166 | |||||||||||||
| Revenues and production taxes payable | 233,090 | 216,695 | |||||||||||||||
| Accrued liabilities | 281,079 | 331,651 | |||||||||||||||
| Accrued interest payable | 37,388 | 38,040 | |||||||||||||||
| Derivative instruments | 19,695 | 84 | |||||||||||||||
| Advances from joint interest partners | 4,598 | 5,140 | |||||||||||||||
| Current operating lease liabilities | 6,182 | — | |||||||||||||||
| Other current liabilities | 2,903 | — | |||||||||||||||
| Total current liabilities | 602,883 | 611,776 | |||||||||||||||
| Long-term debt | 2,711,573 | 2,735,276 | |||||||||||||||
| Deferred income taxes | 267,357 | 300,055 | |||||||||||||||
| Asset retirement obligations | 56,305 | 52,384 | |||||||||||||||
| Derivative instruments | 120 | 20 | |||||||||||||||
| Operating lease liabilities | 17,915 | — | |||||||||||||||
| Other liabilities | 6,019 | 7,751 | |||||||||||||||
| Total liabilities | 3,662,172 | 3,707,262 | |||||||||||||||
|
Commitments and contingencies (Note 22)
|
|||||||||||||||||
| Stockholders’ equity | |||||||||||||||||
90
|
Common stock, $0.01 par value: 900,000,000 shares authorized; 324,198,057 shares issued and 321,231,319 shares outstanding at December 31, 2019 and 320,469,049 shares issued and 318,377,161 shares outstanding at December 31, 2018
|
3,189 | 3,157 | |||||||||
|
Treasury stock, at cost: 2,966,738 and 2,091,888 shares at December 31, 2019 and December 31, 2018, respectively
|
(33,881) | (29,025) | |||||||||
| Additional paid-in capital | 3,112,384 | 3,077,755 | |||||||||
| Retained earnings | 554,446 | 682,689 | |||||||||
| Oasis share of stockholders’ equity | 3,636,138 | 3,734,576 | |||||||||
| Non-controlling interests | 200,943 | 184,304 | |||||||||
| Total stockholders’ equity | 3,837,081 | 3,918,880 | |||||||||
| Total liabilities and stockholders’ equity | $ | 7,499,253 | $ | 7,626,142 | |||||||
The accompanying notes are an integral part of these consolidated financial statements.
91
Oasis Petroleum Inc.
Consolidated Statements of Operations
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||||||||||||||
| Revenues | |||||||||||||||||||||||||||||
| Oil and gas revenues | $ | 1,408,771 | $ | 1,590,024 | $ | 1,034,634 | |||||||||||||||||||||||
| Purchased oil and gas sales | 408,791 | 550,344 | 133,542 | ||||||||||||||||||||||||||
| Midstream revenues | 212,208 | 120,504 | 72,752 | ||||||||||||||||||||||||||
| Well services revenues | 41,974 | 61,075 | 52,791 | ||||||||||||||||||||||||||
| Total revenues | 2,071,744 | 2,321,947 | 1,293,719 | ||||||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||
| Lease operating expenses | 223,384 | 193,912 | 177,134 | ||||||||||||||||||||||||||
| Midstream expenses | 62,146 | 32,758 | 17,589 | ||||||||||||||||||||||||||
| Well services expenses | 28,761 | 41,200 | 37,228 | ||||||||||||||||||||||||||
| Marketing, transportation and gathering expenses | 128,806 | 107,193 | 55,740 | ||||||||||||||||||||||||||
| Purchased oil and gas expenses | 409,180 | 553,461 | 134,615 | ||||||||||||||||||||||||||
| Production taxes | 112,592 | 133,696 | 88,133 | ||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 787,192 | 636,296 | 530,802 | ||||||||||||||||||||||||||
| Exploration expenses | 6,658 | 27,432 | 11,600 | ||||||||||||||||||||||||||
| Rig termination | 384 | — | — | ||||||||||||||||||||||||||
| Impairment | 10,257 | 384,228 | 6,887 | ||||||||||||||||||||||||||
| General and administrative expenses | 143,506 | 121,346 | 91,797 | ||||||||||||||||||||||||||
| Total operating expenses | 1,912,866 | 2,231,522 | 1,151,525 | ||||||||||||||||||||||||||
| Gain (loss) on sale of properties | (4,455) | 28,587 | 1,774 | ||||||||||||||||||||||||||
| Operating income | 154,423 | 119,012 | 143,968 | ||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||
| Net gain (loss) on derivative instruments | (106,314) | 28,457 | (71,657) | ||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (176,223) | (159,085) | (146,837) | ||||||||||||||||||||||||||
| Gain (loss) on extinguishment of debt | 4,312 | (13,848) | — | ||||||||||||||||||||||||||
| Other income (expense) | 440 | 121 | (1,332) | ||||||||||||||||||||||||||
| Total other expense, net | (277,785) | (144,355) | (219,826) | ||||||||||||||||||||||||||
| Loss before income taxes | (123,362) | (25,343) | (75,858) | ||||||||||||||||||||||||||
| Income tax benefit | 32,715 | 5,843 | 203,304 | ||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | (90,647) | (19,500) | 127,446 | ||||||||||||||||||||||||||
| Less: Net income attributable to non-controlling interests | 37,596 | 15,796 | 3,650 | ||||||||||||||||||||||||||
| Net income (loss) attributable to Oasis | $ | (128,243) | $ | (35,296) | $ | 123,796 | |||||||||||||||||||||||
| Earnings (loss) attributable to Oasis per share: | |||||||||||||||||||||||||||||
|
Basic (Note 18)
|
$ | (0.41) | $ | (0.11) | $ | 0.53 | |||||||||||||||||||||||
|
Diluted (Note 18)
|
(0.41) | (0.11) | 0.52 | ||||||||||||||||||||||||||
| Weighted average shares outstanding: | |||||||||||||||||||||||||||||
|
Basic (Note 18)
|
315,002 | 307,480 | 234,986 | ||||||||||||||||||||||||||
|
Diluted (Note 18)
|
315,002 | 307,480 | 237,875 | ||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
92
Oasis Petroleum Inc.
Consolidated Statements of Changes in Stockholders’ Equity
| Attributable to Oasis | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Common Stock | Treasury Stock | Additional Paid-in-Capital |
Retained
Earnings (Deficit) |
Non-controlling Interests | Total Stockholders’ Equity | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2016 | 236,344 | $ | 2,331 | 857 | $ | (15,950) | $ | 2,345,271 | $ | 591,505 | $ | — | $ | 2,923,157 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cumulative-effect adjustment for adoption of ASU 2016-09 (Note 15) | — | — | — | — | 2,040 | 2,684 | — | 4,724 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fees (2016 issuance of common stock) | — | — | — | — | (55) | — | — | (55) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of common stock, net of offering costs | 32,000 | 320 | — | — | 301,871 | — | — | 302,191 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 1,426 | 17 | — | — | 28,090 | — | 53 | 28,160 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of Oasis Midstream common units, net of offering costs | — | — | — | — | — | — | 134,185 | 134,185 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Treasury stock - tax withholdings | (475) | — | 475 | (6,229) | — | — | — | (6,229) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income | — | — | — | — | — | 123,796 | 3,650 | 127,446 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2017 | 269,295 | 2,668 | 1,332 | (22,179) | 2,677,217 | 717,985 | 137,888 | 3,513,579 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Permian Basin Acquisition issuance | 46,000 | 460 | — | — | 370,760 | — | — | 371,220 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 3,842 | 29 | — | — | 30,659 | — | 356 | 31,044 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Issuance of Oasis Midstream common units, net of offering costs | — | — | — | — | — | — | 44,503 | 44,503 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to non-controlling interest owners | — | — | — | — | — | — | (14,114) | (14,114) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Treasury stock - tax withholdings | (760) | — | 760 | (6,846) | — | — | — | (6,846) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | (881) | — | (125) | (1,006) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | (35,296) | 15,796 | (19,500) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2018 | 318,377 | 3,157 | 2,092 | (29,025) | 3,077,755 | 682,689 | 184,304 | 3,918,880 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 3,729 | 32 | — | — | 34,982 | — | 378 | 35,392 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to non-controlling interest owners | — | — | — | — | — | — | (21,270) | (21,270) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Treasury stock - tax withholdings | (875) | — | 875 | (4,856) | — | — | — | (4,856) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | (353) | — | (65) | (418) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | (128,243) | 37,596 | (90,647) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance as of December 31, 2019 | 321,231 | $ | 3,189 | 2,967 | $ | (33,881) | $ | 3,112,384 | $ | 554,446 | $ | 200,943 | $ | 3,837,081 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
93
Oasis Petroleum Inc.
Consolidated Statements of Cash Flows
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | $ | (90,647) | $ | (19,500) | $ | 127,446 | |||||||||||||||||||||||
| Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities: | |||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 787,192 | 636,296 | 530,802 | ||||||||||||||||||||||||||
| (Gain) loss on extinguishment of debt | (4,312) | 13,848 | — | ||||||||||||||||||||||||||
| (Gain) loss on sale of properties | 4,455 | (28,587) | (1,774) | ||||||||||||||||||||||||||
| Impairment | 10,257 | 384,228 | 6,887 | ||||||||||||||||||||||||||
| Deferred income taxes | (32,699) | (5,866) | (202,884) | ||||||||||||||||||||||||||
| Derivative instruments | 106,314 | (28,457) | 71,657 | ||||||||||||||||||||||||||
| Equity-based compensation expenses | 33,607 | 29,273 | 26,534 | ||||||||||||||||||||||||||
| Deferred financing costs amortization and other | 27,263 | 29,057 | 18,311 | ||||||||||||||||||||||||||
| Working capital and other changes: | |||||||||||||||||||||||||||||
| Change in accounts receivable, net | 13,729 | (23,508) | (166,386) | ||||||||||||||||||||||||||
| Change in inventory | (5,893) | (14,346) | (2,501) | ||||||||||||||||||||||||||
| Change in prepaid expenses | 325 | (2,354) | (838) | ||||||||||||||||||||||||||
| Change in accounts payable, interest payable and accrued liabilities | 53,051 | 26,116 | 123,107 | ||||||||||||||||||||||||||
| Change in other assets and liabilities, net | (9,789) | 221 | (22,485) | ||||||||||||||||||||||||||
| Net cash provided by operating activities | 892,853 | 996,421 | 507,876 | ||||||||||||||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||||||||||||||
| Capital expenditures | (869,221) | (1,148,961) | (647,349) | ||||||||||||||||||||||||||
| Acquisitions | (21,009) | (581,650) | (61,874) | ||||||||||||||||||||||||||
| Proceeds from sale of properties | 42,376 | 333,229 | 5,774 | ||||||||||||||||||||||||||
| Costs related to sale of properties | — | (2,850) | (366) | ||||||||||||||||||||||||||
| Derivative settlements | 19,098 | (213,528) | (8,264) | ||||||||||||||||||||||||||
| Other | — | 224 | (2,681) | ||||||||||||||||||||||||||
| Net cash used in investing activities | (828,756) | (1,613,536) | (714,760) | ||||||||||||||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||||||||||||||
| Proceeds from Revolving Credit Facilities | 1,982,000 | 3,224,000 | 1,162,000 | ||||||||||||||||||||||||||
| Principal payments on Revolving Credit Facilities | (1,972,500) | (2,586,000) | (1,377,000) | ||||||||||||||||||||||||||
| Repurchase of senior unsecured notes | (45,790) | (423,340) | — | ||||||||||||||||||||||||||
| Proceeds from issuance of senior unsecured notes | — | 400,000 | — | ||||||||||||||||||||||||||
| Deferred financing costs | (1,052) | (13,862) | (2,714) | ||||||||||||||||||||||||||
| Proceeds from sale of common stock, net of offering costs | — | — | 302,191 | ||||||||||||||||||||||||||
| Proceeds from sale of Oasis Midstream common units, net of offering costs | — | 44,503 | 134,185 | ||||||||||||||||||||||||||
| Purchases of treasury stock | (4,856) | (6,846) | (6,229) | ||||||||||||||||||||||||||
| Distributions to non-controlling interests | (21,270) | (14,114) | — | ||||||||||||||||||||||||||
| Payments on finance lease liabilities | (2,382) | — | — | ||||||||||||||||||||||||||
| Other | (418) | (1,756) | (55) | ||||||||||||||||||||||||||
| Net cash provided by (used in) financing activities | (66,268) | 622,585 | 212,378 | ||||||||||||||||||||||||||
| Increase (decrease) in cash and cash equivalents | (2,171) | 5,470 | 5,494 | ||||||||||||||||||||||||||
94
| Cash and cash equivalents: | |||||||||||||||||
| Beginning of period | 22,190 | 16,720 | 11,226 | ||||||||||||||
| End of period | $ | 20,019 | $ | 22,190 | $ | 16,720 | |||||||||||
| Supplemental cash flow information: | |||||||||||||||||
| Cash paid for interest, net of capitalized interest | $ | 155,833 | $ | 141,196 | $ | 129,463 | |||||||||||
| Cash paid for income taxes | 111 | 38 | 12 | ||||||||||||||
| Cash received for income tax refunds | 146 | 25 | 281 | ||||||||||||||
| Supplemental non-cash transactions: | |||||||||||||||||
| Change in accrued capital expenditures | $ | (82,414) | $ | 68,946 | $ | 83,508 | |||||||||||
| Change in asset retirement obligations | 4,917 | 3,880 | (789) | ||||||||||||||
| Installment notes from acquisition | — | — | 4,875 | ||||||||||||||
| Issuance of shares in connection with acquisition | — | 371,220 | — | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
95
Oasis Petroleum Inc.
Notes to Consolidated Financial Statements
1. Organization and Operations of the Company
Oasis Petroleum Inc. (together with its consolidated subsidiaries, “Oasis” or the “Company”) was originally formed in 2007 and was incorporated pursuant to the laws of the State of Delaware in 2010. The Company is an independent exploration and production company focused on the acquisition and development of onshore, unconventional crude oil and natural gas resources in the United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC (“OP Permian”) conduct the Company’s exploration and production activities and own its oil and gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Delaware Basin, respectively. In addition to its exploration and production segment, the Company also operates a midstream business segment through Oasis Midstream Partners LP (“OMP”) and Oasis Midstream Services LLC (“OMS”) and a well services business segment through Oasis Well Services LLC (“OWS”), both of which are separate reportable business segments that are complementary to the Company’s primary development and production activities. OMP is a growth-oriented, fee-based master limited partnership that develops and operates a diversified portfolio of midstream assets. The Company owns a substantial majority of the general partner and a majority of the outstanding units of OMP. In March 2020, the Company intends to transition its well fracturing services from OWS to a third-party provider who will provide services to the Company under a long-term agreement (see Note 12—Assets Held for Sale).
2. Summary of Significant Accounting Policies
Basis of Presentation
The accompanying consolidated financial statements of the Company include the accounts of Oasis, the accounts of its wholly owned subsidiaries and the accounts of OMP and its general partner, OMP GP LLC (“OMP GP”). The Company has determined that the partners with equity at risk in OMP lack the authority, through voting rights or similar rights, to direct the activities that most significantly impact OMP’s economic performance. Therefore, as the limited partners of OMP do not have substantive kick-out or substantive participating rights over OMP GP, OMP is a variable interest entity. Through the Company’s ownership interest in OMP GP, the Company has the authority to direct the activities that most significantly affect economic performance and the right to receive benefits that could be potentially significant to OMP. Therefore, the Company is considered the primary beneficiary and consolidates OMP and records a non-controlling interest for the interest owned by the public. All intercompany balances and transactions have been eliminated upon consolidation. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Certain reclassifications of prior year balances have been made to conform such amounts to current year classifications. These reclassifications have no impact on net income.
Use of Estimates
Preparation of the Company’s consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved crude oil and natural gas reserves and related cash flow estimates used in impairment tests of long-lived assets, estimates of future development, dismantlement and abandonment costs, estimates relating to certain crude oil and natural gas revenues and expenses and estimates of expenses related to legal, environmental and other contingencies. Certain of these estimates require assumptions regarding future commodity prices, future costs and expenses and future production rates. Actual results could differ from those estimates.
Estimates of crude oil and natural gas reserves and their values, future production rates and future costs and expenses are inherently uncertain for numerous reasons, including many factors beyond the Company’s control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, prevailing commodity prices, operating costs and other factors. These revisions may be material and could materially affect future depreciation, depletion and amortization (“DD&A”) expense, dismantlement and abandonment costs, and impairment expense.
Risks and Uncertainties
As a crude oil and natural gas producer, the Company’s revenue, profitability and future growth are substantially dependent upon the prevailing and future prices for crude oil and natural gas, which are dependent upon numerous factors beyond its control such as economic, political and regulatory developments and competition from other energy sources. The energy
96
markets have historically been very volatile and there can be no assurance that crude oil and natural gas prices will not be subject to wide fluctuations in the future. As a result of current commodity prices, the Company plans to decrease its 2020 capital expenditures, excluding acquisitions, as compared to 2019, while continuing to concentrate its drilling activities in its core acreage, including in the Bakken and Three Forks formations in the Williston Basin and the Bone Spring and Wolfcamp formations in the Delaware Basin.
A substantial or extended decline in prices for crude oil and, to a lesser extent, natural gas, could have a material adverse effect on the Company’s financial position, results of operations, cash flows and quantities of crude oil and natural gas reserves that may be economically produced.
Cash Equivalents
The Company invests in certain money market funds, commercial paper and time deposits, all of which are stated at fair value or cost which approximates fair value due to the short-term maturity of these investments. The Company classifies all such investments with original maturity dates less than 90 days as cash equivalents.
Accounts Receivable
Accounts receivable are carried at cost on a gross basis, with no discounting, which approximates fair value due to their short-term maturities. The Company’s accounts receivable consist mainly of receivables from crude oil and natural gas purchasers and joint interest owners on properties the Company operates.
The Company regularly assesses the recoverability of all material trade and other receivables to determine their collectability. The Company accrues a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Generally, the Company’s crude oil and natural gas receivables are collected within two months, and to date, the Company has had minimal bad debts. At December 31, 2019 and 2018, the Company had an allowance for doubtful accounts of $1.3 million and $1.5 million, respectively.
Inventory
Crude oil inventory includes crude oil in tanks and linefill. Linefill that represents the minimum volume of product in a pipeline system that enables the system to operate is generally not available to be withdrawn from the pipeline system until the expiration of the transportation contract. Crude oil in tanks and linefill in third party pipelines that is expected to be withdrawn within one year is included in inventory on the Company’s Consolidated Balance Sheets, and crude oil linefill in third party pipelines that is not expected to be withdrawn within one year is included in long-term inventory on the Company’s Consolidated Balance Sheets (see Note 5—Inventory).
Equipment and materials consist primarily of proppant, chemicals, tubular goods, well equipment to be used in future drilling or repair operations, well fracturing equipment and spare parts and equipment for the Company’s midstream assets. Equipment and materials are included in inventory on the Company’s Consolidated Balance Sheets (see Note 5—Inventory).
Inventory, including long-term inventory, is stated at the lower of cost and net realizable value with cost determined on an average cost method. The Company assesses the carrying value of inventory and uses estimates and judgment when making any adjustments necessary to reduce the carrying value to net realizable value. Among the uncertainties that impact the Company’s estimates are the applicable quality and location differentials to include in the Company’s net realizable value analysis. Additionally, the Company estimates the upcoming liquidation timing of the inventory. Changes in assumptions made as to the timing of a sale can materially impact net realizable value.
Joint Interest Partner Advances
The Company participates in the drilling of crude oil and natural gas wells with other working interest partners. Due to the capital intensive nature of crude oil and natural gas drilling activities, the working interest partner responsible for conducting the drilling operations may request advance payments from other working interest partners for their share of the costs. The Company expects such advances to be applied by working interest partners against joint interest billings for its share of drilling operations within 90 days from when the advance is paid. Advances to joint interest partners are included in other current assets on the Company’s Consolidated Balance Sheets.
Property, Plant and Equipment
Proved Oil and Gas Properties
Crude oil and natural gas exploration and development activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred,
97
pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. The costs of development wells are capitalized whether productive or nonproductive.
The provision for DD&A of oil and gas properties is calculated using the unit-of-production method. All capitalized well costs and leasehold costs of proved properties are amortized on a unit-of-production basis over the remaining life of proved developed reserves and total proved reserves, respectively, related to the associated field. Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of crude oil. The calculation for the unit-of-production DD&A method takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values.
Costs of retired, sold or abandoned properties that constitute a part of an amortization base are charged or credited, net of proceeds, to accumulated DD&A unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized currently.
Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in operating condition are expensed as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. Estimated dismantlement and abandonment costs for oil and gas properties are capitalized, net of salvage, at their estimated net present value and amortized on a unit-of-production basis over the remaining life of the related proved developed reserves.
The Company reviews its proved oil and gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of its carrying value may have occurred. The Company estimates the expected undiscounted future cash flows of its oil and gas properties by field and compares such undiscounted future cash flows to the carrying amount of the oil and gas properties in the applicable field to determine if the carrying amount is recoverable. The factors used to determine the undiscounted future cash flows are subject to management’s judgment and expertise and include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates and estimates of operating and development costs. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows, net of estimated operating and development costs using estimates of proved reserves, the Company’s estimated undiscounted future cash flows and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges for proved oil and gas properties will be recorded.
Unproved Oil and Gas Properties
Unproved properties consist of costs incurred to acquire unproved leases, or lease acquisition costs. Lease acquisition costs are capitalized until the leases expire or when the Company specifically identifies leases that will revert to the lessor, at which time the Company expenses the associated lease acquisition costs. The expensing of the lease acquisition costs is recorded as impairment in the Consolidated Statements of Operations. Lease acquisition costs related to successful exploratory drilling are reclassified to proved properties and depleted on a unit-of-production basis.
The Company assesses its unproved properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage. The Company considers the following factors in its assessment of the impairment of unproved properties:
•the remaining amount of unexpired term under its leases;
•its ability to actively manage and prioritize its capital expenditures to drill leases and to make payments to extend leases that may be close to expiration;
•its ability to exchange lease positions with other companies that allow for higher concentrations of ownership and development;
•its ability to convey partial mineral ownership to other companies in exchange for their drilling of leases; and
•its evaluation of the continuing successful results from the application of completion technology in the Bakken and Three Forks formations in the Williston Basin and Bone Springs and Wolfcamp formations in the Delaware Basin by the Company or by other operators in areas adjacent to or near the Company’s unproved properties.
For sales of entire working interests in unproved properties, a gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property.
98
Capitalized Interest
The Company capitalizes a portion of its interest expense incurred on its outstanding debt. The amount capitalized is determined by multiplying the capitalization rate by the average amount of eligible accumulated capital expenditures and is limited to actual interest costs incurred during the period. The accumulated capital expenditures included in the capitalized interest calculation begin when the first costs are incurred and end when the asset is either placed into production or written off. The Company capitalized $12.0 million, $17.2 million and $12.8 million of interest costs for the years ended December 31, 2019, 2018 and 2017, respectively. These amounts are amortized over the life of the related assets.
Other Property and Equipment
The Company’s produced and flowback water disposal facilities, natural gas processing plants, pipelines, buildings, furniture, software, equipment and leasehold improvements are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets. The Company uses estimated lives of 30 years for its produced and flowback water disposal facilities, natural gas processing plants and pipelines, 20 years for its buildings, two to seven years for its furniture, software and equipment and the remaining lease term for its leasehold improvements. The calculation for the straight-line DD&A method for its produced and flowback water disposal facilities takes into consideration estimated future dismantlement, restoration and abandonment costs, which are net of estimated salvage values. The cost of assets disposed of and the associated accumulated DD&A are removed from the Company’s Consolidated Balance Sheets with any gain or loss realized upon the sale or disposal included in the Company’s Consolidated Statements of Operations.
Exploration Expenses
Exploration costs, including certain geological and geophysical expenses and the costs of carrying and retaining undeveloped acreage, are charged to expense as incurred.
Costs from drilling exploratory wells are initially capitalized, but charged to expense if and when a well is determined to be unsuccessful. Determination is usually made on or shortly after drilling or completing the well, however, in certain situations a determination cannot be made when drilling is completed. The Company defers capitalized exploratory drilling costs for wells that have found a sufficient quantity of producible hydrocarbons but cannot be classified as proved because they are located in areas that require major capital expenditures or governmental or other regulatory approvals before production can begin. These costs continue to be deferred as wells-in-progress as long as development is underway, is firmly planned for in the near future or the necessary approvals are actively being sought.
Net changes in capitalized exploratory well costs are reflected in the following table for the periods presented:
| December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Beginning of period | $ | 4,457 | $ | — | $ | 2,097 | |||||||||||||||||||||||
| Exploratory well cost additions (pending determination of proved reserves) | — | 26,497 | 10 | ||||||||||||||||||||||||||
| Exploratory well cost reclassifications (successful determination of proved reserves) | (4,222) | (22,040) | (571) | ||||||||||||||||||||||||||
| Exploratory well dry hole costs (unsuccessful in adding proved reserves) | (235) | — | (1,536) | ||||||||||||||||||||||||||
| End of period | $ | — | $ | 4,457 | $ | — | |||||||||||||||||||||||
As of December 31, 2019, the Company had no exploratory well costs that were capitalized for a period of greater than one year after the completion of drilling.
Business Combinations
The Company accounts for business combinations under the acquisition method of accounting. Accordingly, the Company recognizes amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. Transaction and integration costs associated with business combinations are expensed as incurred.
The Company makes various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and gas properties. The fair values of these properties are measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of reserves, future operating and development costs, future commodity prices and a market-based weighted average cost of capital rate. The market-based weighted average cost of capital rate is subjected to additional project-specific risking factors. In addition, when appropriate, the Company reviews comparable
99
purchases and sales of oil and gas properties within the same regions and uses that data as a proxy for fair market value; for example, the amount a willing buyer and seller would enter into in exchange for such properties.
Any excess of the acquisition price over the estimated fair value of net assets acquired is recorded as goodwill. Any excess of the estimated fair value of net assets acquired over the acquisition price is recorded in current earnings as a gain on bargain purchase. Deferred taxes are recorded for any differences between the assigned values and the tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known.
Assets Held for Sale
The Company occasionally markets non-core oil and gas properties and other property and equipment. At the end of each reporting period, the Company evaluates the properties being marketed to determine whether any should be reclassified as held-for-sale. The held-for-sale criteria include: management commits to a plan to sell; the asset is available for immediate sale; an active program to locate a buyer exists; the sale of the asset is probable and expected to be completed within one year; the asset is being actively marketed for sale; and it is unlikely that significant changes to the plan will be made. If each of these criteria is met, the property is reclassified as held-for-sale on the Company’s Consolidated Balance Sheets and measured at the lower of their carrying amount or estimated fair value less costs to sell. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, indicative bids or indicative market pricing, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale.
Deferred Financing Costs
The Company capitalizes costs incurred in connection with obtaining financing. These costs are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method. The amortization expense is recorded as a component of interest expense in the Company’s Consolidated Statements of Operations. The deferred financing costs related to the Company’s senior unsecured notes as well as the Revolving Credit Facilities are included in long-term debt and other assets, respectively, on the Company’s Consolidated Balance Sheets.
Asset Retirement Obligations
In accordance with the Financial Accounting Standard Board’s (“FASB”) authoritative guidance on asset retirement obligations (“ARO”), the Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred and can be reasonably estimated with the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. For oil and gas properties, this is the period in which the well is drilled or acquired. The ARO represents the estimated amount the Company will incur to plug, abandon and remediate the properties at the end of their productive lives, in accordance with applicable state laws. The liability is accreted to its present value each period and the capitalized costs are amortized using the unit-of-production method. The accretion expense is recorded as a component of depreciation, depletion and amortization in the Company’s Consolidated Statements of Operations.
Some of the Company’s midstream assets, including certain pipelines and the natural gas processing plants, have contractual or regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities, when the assets are abandoned. The Company is not able to reasonably estimate the fair value of the asset retirement obligations for these assets because the settlement dates are indeterminable given the expected continued use of the assets with proper maintenance. The Company will record asset retirement obligations for these assets in the periods in which the settlement dates are reasonably determinable.
The Company determines the ARO by calculating the present value of estimated cash flows related to the liability. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. Inherent in the fair value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. These assumptions represent Level 3 inputs, as further discussed in Note 7 — Fair Value Measurements. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the related asset.
100
Revenue Recognition
In the first quarter of 2018, the Company adopted Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, and a series of related accounting standards updates incorporated into GAAP as Accounting Standards Codification Topic 606 (“ASC 606”) using the modified retrospective method. The Company applies ASC 606 to all new contracts entered into after January 1, 2018 and all existing contracts for which all (or substantially all) of the revenue has not been recognized under legacy revenue guidance as of December 31, 2017. ASC 606 includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the Company expects to be entitled in exchange for those goods or services. Enhanced disclosures in accordance with ASC 606 have been provided in Note 4—Revenue Recognition.
The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied.
Crude oil, natural gas and natural gas liquids (“NGL”) revenues from the Company’s interests in producing wells are recognized when it satisfies a performance obligation by transferring control of a product to a customer. Substantially all of the Company’s crude oil and natural gas production is sold to purchasers under short-term (less than twelve-month) contracts at market-based prices, and the Company’s NGL production is sold to purchasers under long-term (more than twelve-month) contracts at market-based prices. The sales prices for crude oil, natural gas and NGLs are adjusted for transportation and other related deductions. These deductions are based on contractual or historical data and do not require significant judgment. Subsequently, these revenue deductions are adjusted to reflect actual charges based on third-party documents. Since there is a ready market for crude oil, natural gas and NGLs, the Company sells the majority of its production soon after it is produced at various locations. As a result, the Company maintains a minimum amount of product inventory in storage.
The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from third parties. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with ASC 845.
Midstream revenues consist of revenues from midstream services provided through OMS, including (i) crude oil gathering, stabilization, blending, storage and transportation, (ii) natural gas gathering, gas lift, compression and processing, (iii) produced and flowback water gathering and disposal and (iv) freshwater supply and distribution. Well services revenues result from well services, product sales and equipment rentals provided by OWS primarily for OPNA’s operated wells. Midstream and well services revenues are recognized when services have been performed or related volumes or products have been delivered. The revenues related to OPNA’s working interests are eliminated in consolidation, and only the revenues related to other working interest owners in OPNA’s wells are included in the Company’s Consolidated Statements of Operations. Midstream revenues are earned through fee-based arrangements, under which the Company receives fees for midstream services it provides to customers and recognizes revenue based upon the transaction price at month-end under the right to invoice practical expedient, or through purchase arrangements, under which the Company takes control of the product prior to sale and is the principal in the transaction, and therefore, recognizes revenues and expenses on a gross basis.
Revenues and Production Taxes Payable
The Company calculates and pays taxes and royalties on crude oil and natural gas in accordance with the particular contractual provisions of the lease, license or concession agreements and the laws and regulations applicable to those agreements.
Leases
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842), which requires lessees to recognize a right-of-use (“ROU”) asset and related liability on the balance sheet for leases with durations greater than twelve months and also requires certain quantitative and qualitative disclosures about leasing arrangements. Accounting Standards Codification 842, Leases (“ASC 842”), was subsequently amended by Accounting Standards Update No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”); Accounting Standards Update No. 2018-10, Codification Improvements to Topic 842; Accounting Standards Update No. 2018-11, Targeted Improvements; and Accounting Standards Update No. 2019-01, Leases (Topic 842): Codification Improvements.
The Company adopted the new standard as of January 1, 2019 using the required modified retrospective approach and elected the option to recognize a cumulative effect adjustment of initially applying the guidance to the opening balance of retained earnings in the period of adoption. Prior period amounts were not adjusted.
101
ASU 2018-01 provides a number of optional practical expedients in transition. The Company elected the package of practical expedients under the transition guidance within the new standard, including the practical expedient to not reassess under the new standard any prior conclusions about lease identification, lease classification and initial direct costs; the use-of hindsight practical expedient; the practical expedient to not reassess the prior accounting treatment for existing or expired land easements; and the practical expedient pertaining to combining lease and non-lease components for all asset classes. In addition, the Company elected not to apply the recognition requirements of ASC 842 to leases with terms of one year or less, and as such, recognition of lease payments for short-term leases are recognized in net income on a straight line basis. See Note 20—Leases for the adoption impact and disclosures required by ASC 842.
Concentrations of Market and Credit Risk
The future results of the Company’s crude oil and natural gas operations will be affected by the market prices of crude oil and natural gas. The availability of a ready market for crude oil and natural gas products in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of crude oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of crude oil, natural gas and liquid products, the regulatory environment, the economic environment, and other regional and political events, none of which can be predicted with certainty. The current global oversupply of crude oil has caused a sharp decline in crude oil prices since mid-2014, though recently crude oil prices have been improving. A substantial or extended decline in the price of crude oil could have a material adverse effect on the Company’s financial position, cash flows and results of operations.
The Company operates in the exploration, development and production sector of the crude oil and gas industry. The Company’s receivables include amounts due from purchasers of its crude oil and natural gas production and amounts due from joint interest partners for their respective portions of operating expenses and exploration and development costs. While certain of these customers and joint interest partners are affected by periodic downturns in the economy in general or in their specific segment of the crude oil or natural gas industry, including the current period of low commodity prices, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations over the long-term. In addition, a portion of the Company’s trade receivables are collateralized.
The Company manages and controls market and counterparty credit risk. In the normal course of business, collateral is not required for financial instruments with credit risk. Financial instruments which potentially subject the Company to credit risk consist principally of temporary cash balances and derivative financial instruments. The Company maintains cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. The Company has not experienced any significant losses from such investments. The Company attempts to limit the amount of credit exposure to any one financial institution or company. The Company believes the credit quality of its customers is generally high. In the normal course of business, letters of credit or parent guarantees are required for counterparties which management perceives to have a higher credit risk.
Risk Management
The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. As of December 31, 2019, the Company utilized fixed price swaps and two-way and three-way costless collar options to reduce the volatility of crude oil prices on a significant portion of its future expected crude oil production (see Note 8—Derivative Instruments).
The Company records all derivative instruments on the Consolidated Balance Sheets as either assets or liabilities measured at their estimated fair value. Derivative assets and liabilities arising from derivative contracts with the same counterparty are reported on a net basis, as all counterparty contracts provide for net settlement. The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. Gains and losses from valuation changes in commodity derivative instruments are reported in the other income (expense) section of the Company’s Consolidated Statements of Operations. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making or receiving a payment to or from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments for the periods presented and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.
Derivative financial instruments that hedge the price of crude oil and natural gas are executed with major financial institutions that expose the Company to market and credit risks and which may, at times, be concentrated with certain counterparties or groups of counterparties. At December 31, 2019, the Company has derivatives in place with nine counterparties. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of nonperformance by the counterparties are substantially smaller. The credit worthiness of the counterparties is subject to continual review. The Company believes the risk of nonperformance by its counterparties is low. Full performance is
102
anticipated, and the Company has no past-due receivables from its counterparties. The Company’s policy is to execute financial derivatives only with major, credit-worthy financial institutions.
The Company’s derivative contracts are documented with industry standard contracts known as a Schedule to the Master Agreement and International Swaps and Derivatives Association, Inc. Master Agreement (“ISDA”). Typical terms for the ISDAs include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Revolving Credit Facilities (see Note 13 — Long-Term Debt). The Company has limitations under the Revolving Credit Facilities, including a provision limiting the total amount of production that may be hedged by the Company to certain percentages of forecasted and current production amounts. As of December 31, 2019, the Company was in compliance with these limitations.
Contingencies
Certain conditions may exist as of the date the Company’s consolidated financial statements are issued that may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. The Company’s management, with input from legal counsel, assesses such contingent liabilities, and such assessment inherently involves judgment. In assessing loss contingencies related to legal proceedings that are pending against the Company or unasserted claims that may result in proceedings, the Company’s management, with input from legal counsel, evaluates the perceived merits of any legal proceedings or unasserted claims as well as the perceived merits of the amount of relief sought or expected to be sought therein.
If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of liability can be estimated, then the estimated undiscounted liability is accrued in the Company’s consolidated financial statements. If the assessment indicates that a potentially material loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the range of possible loss if determinable and material, is disclosed. Actual results could vary from these estimates and judgments.
Loss contingencies considered remote are generally not disclosed unless they involve guarantees, in which case the guarantees would be disclosed. See Note 22—Commitments and Contingencies for additional information regarding the Company’s contingencies.
Environmental Costs
Environmental expenditures are expensed or capitalized, as appropriate, depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations, and which do not have future economic benefit, are expensed. Liabilities related to future costs are recorded on an undiscounted basis when environmental assessments and/or remediation activities are probable and the costs can be reasonably estimated.
Equity-Based Compensation
Restricted Stock Awards
The Company has granted restricted stock awards to its employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the closing sales price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense is recognized ratably over the requisite service period. Equity-based compensation expense recorded for restricted stock awards is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. Forfeitures associated with restricted stock awards granted are accounted for when they occur.
Performance Share Units
The Company recognizes compensation expense for its performance share units (“PSUs”) granted to its officers under its Amended and Restated 2010 Long Term Incentive Plan. The fair value of the PSUs is based on the calculation derived from a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment (see Note 16—Equity-Based Compensation for a description of the inputs used in this model). Equity-based compensation expense recorded for the PSUs is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. Forfeitures associated with PSUs granted are accounted for when they occur.
OMP Phantom Unit Awards
The Company has granted phantom unit awards based on OMP common units (collectively, the “OMP Phantom Unit Awards,” and each an “OMP Phantom Unit”) to its employees under its Amended and Restated 2010 Long Term Incentive Plan and OMP GP has granted OMP Phantom Unit Awards to employees of the Company under the Oasis Midstream Partners LP 2017 Long Term Incentive Plan (“OMP LTIP”). The OMP Phantom Unit Awards are accounted for as liability-classified awards since the
103
awards will settle in cash, and equity-based compensation cost is accounted for under the fair value method in accordance with GAAP. The OMP Phantom Unit Awards generally vest in equal installments each year over a three-year period, and compensation expense will be recognized over the requisite service period. Compensation expense is remeasured each reporting period at fair value based upon the closing price of a publicly traded common unit. The Company will directly pay, or will reimburse OMP, for the cash settlement amount of these awards. Forfeitures associated with OMP Phantom Unit Awards granted are accounted for when they occur.
Associated Excess Tax Benefits
Any excess tax benefit arising from the Company’s equity-based compensation plan is recognized as a credit to income tax expense or benefit in the Company’s Consolidated Statements of Operations.
Treasury Stock
Treasury stock shares represent shares withheld by the Company equivalent to the payroll tax withholding obligations due from employees upon the vesting of restricted stock awards. The Company includes the withheld shares as treasury stock on its Consolidated Balance Sheets and separately pays the payroll tax obligation. These retained shares are not part of a publicly announced program to repurchase shares of the Company’s common stock and are accounted for at cost. The Company does not have a publicly announced program to repurchase shares of its common stock.
Income Taxes
The Company’s provision for taxes includes both federal and state taxes. The Company records its federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
The Company applies significant judgment in evaluating its tax positions and estimating its provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from the Company’s estimates, which could impact its financial position, results of operations and cash flows.
The Company also accounts for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority. The Company did not have any uncertain tax positions outstanding and, as such, did not record a liability for the years ended December 31, 2019 and 2018. All deferred tax assets and liabilities, along with any related valuation allowance, are classified as noncurrent on the Company’s Consolidated Balance Sheets.
Recent Accounting Pronouncements
Fair Value Measurement
In August 2018, the FASB issued Accounting Standards Update No. 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which improves the effectiveness of the disclosure requirements for fair value measurements. The changes affect all companies that are required to include fair value measurement disclosures. ASU 2018-13 is effective for fiscal years beginning after December 15, 2019, including interim periods within those years. An entity is permitted to early adopt the removed or modified disclosures upon the issuance of ASU 2018-13 and may delay adoption of the additional disclosures until their effective date. The Company does not expect the adoption of this guidance to have an impact on its financial position, cash flows or results of operations, but it may result in changes to disclosures.
Financial Instruments - Credit Losses
In June 2016, the FASB issued Accounting Standards Update No. 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which replaces the incurred loss impairment methodology in current GAAP with a methodology that reflects expected credit losses and requires consideration of a broader range of reasonable and supportable information, including forecasts, to develop credit loss estimates. ASU 2016-13 requires
104
entities to use the new methodology to measure impairment of financial instruments, including trade and joint interest billing receivables, and may result in earlier recognition of credit losses than under current GAAP. ASU 2016-13 is effective for fiscal years beginning after December 15, 2019. Although the Company continues to evaluate ASU 2016-13, based on our current credit portfolio the Company does not expect the adoption of this standard to have a material impact on its financial position, cash flows or results of operations, but it may result in changes to disclosures.
Income Taxes
In December 2019, the FASB issued Accounting Standards Update No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which simplifies the accounting for income taxes by removing certain exceptions to the general principles and also simplification of areas such as separate entity financial statements and interim recognition of enactment of tax laws or rate changes. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, including interim reporting periods within those years. The Company is currently evaluating the effect of ASU 2019-12, but does not expect the adoption of this guidance to have a material impact on its financial position, cash flows or result of operations.
3. Oasis Midstream Partners
Oasis Midstream Partners LP
OMP is a growth-oriented, fee-based master limited partnership formed by the Company to own, develop, operate and acquire a diversified portfolio of midstream assets in North America that are integral to the crude oil and natural gas operations of Oasis and are strategically positioned to capture volumes from other producers.
In 2017, OMP completed its initial public offering (“IPO”) of common units representing limited partner interests, and the OMP common units are traded on The Nasdaq Stock Market LLC under the symbol OMP. In exchange for contributed assets, Oasis received 5,125,000 common units and 13,750,000 subordinated units, representing a 68.6% limited partner interest in OMP and the right to receive cash distributions from OMP. In addition to and concurrent with the closing of the IPO, OMP GP retained a non-economic general partnership interest and was issued incentive distribution rights in OMP.
Contractual arrangements
The Company entered into several long-term, fee-based contractual arrangements with OMP for midstream services, including (i) natural gas gathering, compression, processing and gas lift services; (ii) crude oil gathering, stabilization, blending, storage and transportation services; (iii) produced and flowback water gathering and disposal services; and (iv) freshwater supply and distribution services. In addition, the Company provides substantial labor and overhead support for OMP. Upon completion of the OMP IPO, the Company entered into a 15-year services and secondment agreement with OMP pursuant to which the Company provides all personnel, equipment, electricity, chemicals and services (including third-party services) required for OMP to operate such assets, and OMP reimburses the Company for its share of the actual costs of operating such assets. In addition, pursuant to the services and secondment agreement, the Company performs centralized corporate, general and administrative services for OMP, such as legal, corporate recordkeeping, planning, budgeting, regulatory, accounting, billing, business development, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, investor relations, cash management and banking, payroll, internal audit, taxes and engineering. The Company has also seconded to OMP certain of its employees to operate, construct, manage and maintain its assets, and OMP reimburses the Company for direct general and administrative expenses incurred by the Company for the provision of the above services. The expenses of executive officers and non-executive employees are allocated to OMP based on the amount of time spent managing its business and operations.
Oasis Midstream Partners LP public offering and dropdown
On November 14, 2018, OMP completed a public offering of 2,300,000 common units (including 300,000 common units issued pursuant to the underwriters’ option to purchase additional common units) representing limited partnership interests, at a price to the public of $20.00 per common unit. OMP received net proceeds from the public offering of $44.5 million, after deducting underwriting discounts, commissions and offering costs, which were used to fund a portion of its acquisition of additional ownership interest in Bobcat DevCo LLC (“Bobcat DevCo”) and Beartooth DevCo LLC (“Beartooth DevCo”).
In connection with the OMP public offering, on November 19, 2018, OMP acquired an additional 15% ownership interest in Bobcat DevCo increasing its ownership to 25% and an additional 30% ownership interest in Beartooth DevCo increasing its ownership to 70% in exchange for consideration of $251.4 million (“OMP Dropdown”).
The $251.4 million consideration consisted of $172.4 million in cash and 3,950,000 common units representing limited partner interests in OMP. OMP funded the cash portion of the consideration with a combination of borrowings under the revolving credit facility among OMP, as parent, OMP Operating LLC (“OMP Operating”), a subsidiary of OMP, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “OMP Credit Facility”) and proceeds from its public offering of common units. The effective date of the OMP Dropdown was July 1, 2018, and the OMP Dropdown closed
105
on November 19, 2018. The OMP Dropdown did not have a material impact on the Company’s consolidated financial statements. After the OMP Dropdown, OMS owned 75% of the non-controlling interests of Bobcat DevCo and 30% of the non-controlling interests of Beartooth DevCo.
2019 Capital Expenditures Arrangement
On February 22, 2019, the Company entered into a memorandum of understanding (the “MOU”) with OMP regarding the funding of Bobcat DevCo’s expansion capital expenditures for the 2019 calendar year (the “2019 Capital Expenditures Arrangement”). Pursuant to the MOU, in exchange for increasing its percentage ownership interest in Bobcat DevCo, OMP agreed to make up to $80.0 million of the capital contributions to Bobcat DevCo that OMS would otherwise have been required to contribute. During the year ended December 31, 2019, OMP made capital contributions to Bobcat DevCo pursuant to the 2019 Capital Expenditures Arrangement of $73.0 million. As a result, OMS’s ownership interest in Bobcat DevCo decreased from 75% as of December 31, 2018 to 64.7% as of December 31, 2019. The 2019 Capital Expenditures Arrangement ended on December 31, 2019.
Assignment of midstream assets in Delaware Basin
Effective November 1, 2019, the Company assigned to Panther DevCo LLC (“Panther DevCo”), an indirect, wholly-owned subsidiary of OMP, certain crude oil gathering and produced water gathering and disposal assets (the “Delaware Midstream Assets”) under development to support the Company’s production in the Delaware Basin. OMP agreed to reimburse the Company for all capital expenditures previously made with respect to the Delaware Midstream Assets, which were approximately $24.9 million. OMP funded this amount with borrowings under its revolving credit facility. Also, effective November 1, 2019, Panther DevCo entered into long-term commercial agreements with the Company, including a Crude Oil Gathering Agreement and a Produced Water Gathering and Disposal Agreement (collectively, the “Delaware Basin Commercial Agreements”), for crude oil and produced water midstream services in the Delaware Basin, which generally contain terms similar to those contained in the existing commercial agreements between OMP and the Company for midstream services in the Williston Basin. The Delaware Basin Commercial Agreements additionally provide the Company with certain purchase rights with respect to the Delaware Midstream Assets, and provide Panther DevCo with certain sale rights with respect to the Delaware Midstream Assets, in the event of a change of control of OMP or Panther DevCo, which purchase and sale rights will expire after two years.
4. Revenue Recognition
Exploration and production revenues
The Company’s exploration and production revenues are derived from contracts for crude oil, natural gas and natural gas liquids (“NGL”) sales, as described below. Generally, for the majority of these contracts: (i) each unit (barrel (“bbl”), mcf, gallon, etc.) of commodity product is a separate performance obligation, as the Company’s promise is to sell multiple distinct units of commodity product at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on the Company’s right to invoice at month end for the value of commodity product sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity product’s standalone selling price and recognized as revenue upon delivery of the commodity product, which is the point in time when the customer obtains control of the commodity product and the Company’s performance obligation is satisfied. The sales of crude oil, natural gas and NGLs as presented on the Company’s Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling crude oil, natural gas and NGLs on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports the revenue on a net basis. To the extent actual volumes and prices of crude oil and natural gas sales are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and prices for those properties are estimated and recorded. The Company’s contracts with customers typically require payments for crude oil, natural gas and NGL sales within 30 days following the calendar month of delivery.
Crude oil revenues. The Company sells a substantial majority of its crude oil through bulk sales at delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be delivered and sold to the customer at a specified delivery point. The customer pays a market-based transaction price, which incorporates differentials that include, but are not limited to, transportation costs.
Natural gas and NGL revenues. The Company’s natural gas sales consist of unprocessed gas sales and residue gas sales. Unprocessed gas is sold at delivery points at or near the wellhead under various contracts, in which the customer pays a transaction price based on its sale of the bifurcated NGLs and residue gas, less any associated fees. Revenue is recorded on a net basis, with processing fees deducted within revenue rather than as a separate expense line item, as title and control transfer at the delivery point. Residue gas from the Company’s gas processing plants located in Wild Basin is sold at the tailgate or transported and sold at other downstream sales points, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold. NGLs from the Company’s gas processing plants located in Wild Basin are sold at the tailgate
106
or trucked and sold at other downstream locations, and the customer pays a transaction price based on a market indexed per-unit rate for the quantities sold.
Purchased crude oil and natural gas sales. The Company’s purchased crude oil and natural gas sales are derived from the sale of crude oil and natural gas purchased from a third party. The Company sells the purchased commodities to a variety of customers under short-term contracts that include specified quantities of crude oil and natural gas to be sold and delivered to the customer at a specified delivery point. The customer pays a market-based transaction price, which is based on the price index applicable for the location of the sale. Revenues and expenses from these sales and purchases are generally recorded on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased crude oil or natural gas before it is transferred to the customer. In certain cases, the Company enters into sales and purchases with the same counterparty in contemplation of one another, and these transactions are recorded on a net basis in accordance with ASC 845.
Prior period performance obligations. For sales of commodities, the Company records revenue in the month production is delivered to the purchaser. However, settlement statements and payment may not be received for 20 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales once payment is received from the purchaser. Such differences have historically not been significant. The Company uses knowledge of its properties, its properties’ historical performance, spot market prices and other factors as the basis for these estimates. For the year ended December 31, 2019 and 2018, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
Revenues associated with contracts with customers for crude oil, natural gas and NGL sales were as follows for the years ended December 31, 2019, 2018 and 2017:
Midstream revenues
The Company’s midstream revenues are derived from its contracts with customers for midstream services and product sales under the following arrangements:
Fee-based arrangements. Under fee-based arrangements, the Company receives a fee for midstream services provided to its customers, and revenues are recognized using the output method for measuring the satisfaction of performance obligations. Revenues earned under fee-based arrangements are generally directly related to the volume of crude oil, natural gas and produced and flowback water that flows through the Company’s systems, and the Company does not take ownership to the volumes it handles for its customers. Payments under fee-based arrangements are generally due 30 days after receipt of invoice. The Company generates revenues under fee-based arrangements as follows:
•Crude oil and natural gas revenues. The Company is party to certain contracts for crude oil gathering, stabilization, blending, storage and transportation, as well as natural gas gathering, compression, processing and gas lift services. Under these customer contracts, the Company provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient.
•Produced and flowback water revenues. The Company is party to certain contracts with customers for produced and flowback water gathering and disposal services, under which it provides daily integrated midstream services on a stand ready basis over a period of time, which represents a single performance obligation since the customer simultaneously receives and consumes the benefits of these services on a daily basis. Satisfaction of the Company’s performance obligation is measured as each day of service is completed, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized based upon the transaction price at month-end under the right to invoice practical expedient.
107
Purchase arrangements. Under purchase arrangements, revenues and expenses are recognized on a gross basis since the Company takes control of the product prior to sale and is the principal in the transaction. Revenues are recognized using the output method for measuring the satisfaction of performance obligations based upon the volume of natural gas, NGLs or freshwater delivered to customers. Payments under purchase arrangements are generally due 30 days after receipt of invoice. The Company generates revenues under purchase arrangements as follows:
•Purchased crude oil sales. The Company purchases and sells crude oil at various delivery points on crude oil gathering systems to a variety of customers under short-term contracts that include a specified quantity of crude oil to be sold and delivered to the customer at a specified delivery point. The Company purchases and sells the crude oil to different counterparties at market-based prices. Market-based pricing is based on the price index applicable for the location of the sale.
•Natural gas and NGL revenues. The Company is party to certain purchase arrangements with third parties pursuant to which the Company purchases natural gas from third parties at a connection point and obtains control prior to performing services and is the principal in the transaction. The Company gathers, compresses and/or processes the gas and then redelivers the residue gas and NGLs to different counterparties at market-based prices.
•Freshwater revenues. Under these customer contracts, the Company supplies and distributes freshwater to its customers for hydraulic fracturing and production optimization. These contracts contain multiple distinct performance obligations since each freshwater barrel can be sold separately and is not dependent nor highly interrelated with other barrels.
Prior period performance obligations. The Company records revenue for midstream services or product sales when the performance obligations under the terms of its customer contracts are satisfied. The Company measures the satisfaction of its performance obligations using the output method based upon the volume of crude oil, natural gas or water that flows through its systems. In certain cases, the Company is required to estimate these volumes during a reporting period and record any differences between the estimated volumes and actual volumes in the following reporting period. Such differences have historically not been significant. For the years ended December 31, 2019, 2018 and 2017, revenue recognized related to performance obligations satisfied in prior reporting periods was not material.
Revenues associated with contracts with customers for midstream services were as follows for the years ended December 31, 2019, 2018 and 2017:
|
Midstream Revenues(1)
|
||||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | ||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||||||||||
| Midstream service revenues | ||||||||||||||||||||||||||||||||||||||||||||
| Crude oil and natural gas revenues | $ | 95,399 | $ | 73,028 | $ | 37,369 | ||||||||||||||||||||||||||||||||||||||
| Produced and flowback water revenues | 40,534 | 37,791 | 30,727 | |||||||||||||||||||||||||||||||||||||||||
| Total midstream service revenues | $ | 135,933 | $ | 110,819 | $ | 68,096 | ||||||||||||||||||||||||||||||||||||||
| Midstream product revenues | ||||||||||||||||||||||||||||||||||||||||||||
| Purchased crude oil sales | $ | 30 | $ | 3,633 | $ | — | ||||||||||||||||||||||||||||||||||||||
| Natural gas and NGL revenues | 70,746 | 1,464 | — | |||||||||||||||||||||||||||||||||||||||||
| Freshwater revenues | 5,529 | 8,221 | 4,656 | |||||||||||||||||||||||||||||||||||||||||
| Total midstream product revenues | $ | 76,305 | $ | 13,318 | $ | 4,656 | ||||||||||||||||||||||||||||||||||||||
| Total midstream revenues | $ | 212,238 | $ | 124,137 | $ | 72,752 | ||||||||||||||||||||||||||||||||||||||
__________________
(1)Represents midstream revenues excluding all intercompany revenues for work performed by the midstream services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in midstream services revenues.
Well services revenues
Hydraulic fracturing revenues. Hydraulic fracturing revenue is recognized upon the completion of each hydraulic fracturing of a well. These services are composed of various components, such as personnel, equipment and hydraulic fracturing materials, but management determined that each component is not distinct, as it cannot be used on its own or together with a resource readily available to the customer. Revenue is recognized when the performance obligations of hydraulic fracturing a well in its totality are completed; generally, this is over a period of time due to all work being performed for a customer occurring on the
108
customer’s property, where the customer has control over the work in process as it is being performed. In addition, the Company’s assets being used to perform the obligations have no alternative use at the time of performance and the Company has the right to payment for performance to date. Payments from customers are generally received by the Company within one month after the month in which services are provided. In addition, revenue from product sales to third parties is generated when OPNA requests that third-party hydraulic fracturing companies hydraulic fracture OPNA’s wells. Although the labor is provided by the third-party hydraulic fracturing company, the materials (e.g., sand, chemicals, etc.) used in the hydraulic fracturing of the wells are provided by OWS. The third-party hydraulic fracturing company or OPNA pays OWS for the materials delivered to the wells. Revenue is recognized once the performance obligations to transfer hydraulic fracturing materials are completed.
Equipment rental revenues. Equipment rental revenue is generated when OPNA or a third-party hydraulic fracturing company rents equipment from OWS. This equipment is used in the preparation stage of hydraulic fracturing services or after the hydraulic fracturing services have been completed. Equipment rental revenues are calculated based on the equipment’s daily rental rate and the number of days that the equipment was rented by the customer. OWS’s performance obligation is satisfied when the entire rental period is completed. Equipment rental revenues are recognized over a period of time due to the customer simultaneously receiving and consuming the benefits of the rental equipment provided by OWS on a daily basis. Satisfaction of the Company’s performance obligation is measured at the completion of each day’s rental period, which directly corresponds with its right to consideration from the customer. Revenues associated with these contracts are recognized at the time of invoicing for the entire rental period under the right to invoice practical expedient. Payments from customers are generally received by the Company within one month after the month in which services are provided.
Revenues associated with contracts with customers for hydraulic fracturing services and equipment rental sales were as follows for the years ended December 31, 2019, 2018 and 2017:
__________________
(1)Represents well services revenues excluding all intercompany revenues for work performed by the well services business segment for the Company’s working interests that are eliminated in consolidation and are therefore not included in well services revenues.
Contract balances
Contract balances are the result of timing differences between revenue recognition, billings and cash collections. Contract liabilities are recorded for consideration received from customers primarily related to (i) temporary deficiency quantities under minimum volume commitments which are recognized as revenue when the customer makes up the volumes or the deficiency makeup period expires and (ii) aid in construction payments received from customers which are recognized as revenue over the expected period of future benefit. The Company does not recognize contract assets or contract liabilities under its customer contracts for which invoicing occurs once the Company’s performance obligations have been satisfied and payment is unconditional. Contract liabilities are classified as current or long-term based on the timing of when the Company expects to recognize revenue. As of December 31, 2018, there were no contract balances outstanding. The following table reflects the changes in the Company’s contract liabilities during the year ended December 31, 2019:
| (In thousands) | |||||
| Balance as of December 31, 2018 | $ | — | |||
| Cash received | 2,174 | ||||
| Revenues recognized | (69) | ||||
| Balance as of December 31, 2019 | $ | 2,105 | |||
109
Remaining performance obligations
ASC 606 requires presentation of information about partially and wholly unsatisfied performance obligations under contracts that exist as of the end of the period. The following table presents estimated revenue allocated to remaining performance obligations for contracted revenues that are unsatisfied (or partially satisfied) as of December 31, 2019:
| (In thousands) | |||||
| 2020 | $ | 18,452 | |||
| 2021 | 20,203 | ||||
| 2022 | 19,244 | ||||
| 2023 | 12,642 | ||||
| 2024 | 11,870 | ||||
| Thereafter | 2,768 | ||||
| Total | $ | 85,179 | |||
The partially and wholly unsatisfied performance obligations presented in the table above are generally limited to customer contracts which have fixed pricing and fixed volume terms and conditions, which generally include customer contracts with minimum volume commitment payment obligations.
The Company has elected practical expedients, pursuant to ASC 606, to exclude from the presentation of remaining performance obligations: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services and (ii) contracts with an original expected duration of one year or less.
5. Inventory
The following table sets forth the Company’s inventory:
| December 31, | |||||||||||||||||
| 2019 | 2018 | ||||||||||||||||
| (In thousands) | |||||||||||||||||
| Inventory | |||||||||||||||||
| Crude oil inventory | $ | 18,296 | $ | 14,933 | |||||||||||||
| Equipment and materials | 16,963 | 18,195 | |||||||||||||||
| Total inventory | $ | 35,259 | $ | 33,128 | |||||||||||||
| Long-term inventory | |||||||||||||||||
| Linefill in third-party pipelines | $ | 13,924 | $ | 12,260 | |||||||||||||
| Long-term inventory | $ | 13,924 | $ | 12,260 | |||||||||||||
| Total | $ | 49,183 | $ | 45,388 | |||||||||||||
110
6. Additional Balance Sheet Information
Certain balance sheet amounts are comprised of the following:
| December 31, | |||||||||||||||||
| 2019 | 2018 | ||||||||||||||||
| (In thousands) | |||||||||||||||||
| Accounts receivable, net | |||||||||||||||||
| Trade accounts | $ | 276,629 | $ | 245,546 | |||||||||||||
| Joint interest accounts | 82,112 | 133,375 | |||||||||||||||
| Other accounts | 13,699 | 10,207 | |||||||||||||||
| Total | 372,440 | 389,128 | |||||||||||||||
| Allowance for doubtful accounts | (1,259) | (1,526) | |||||||||||||||
| Total accounts receivable, net | $ | 371,181 | $ | 387,602 | |||||||||||||
| Revenues and production taxes payable | |||||||||||||||||
| Revenue suspense | $ | 78,950 | $ | 75,685 | |||||||||||||
| Royalties payable | 133,092 | 124,884 | |||||||||||||||
| Production taxes payable | 21,048 | 16,126 | |||||||||||||||
| Total revenue and production taxes payable | $ | 233,090 | $ | 216,695 | |||||||||||||
| Accrued liabilities | |||||||||||||||||
| Accrued capital costs | $ | 128,592 | $ | 216,079 | |||||||||||||
| Accrued lease operating expenses | 34,151 | 26,988 | |||||||||||||||
| Accrued oil and gas purchases | 51,087 | 32,713 | |||||||||||||||
| Accrued general and administrative expenses | 41,843 | 23,901 | |||||||||||||||
| Accrued midstream and well services operating expenses | 17,958 | 17,521 | |||||||||||||||
| Other accrued liabilities | 7,448 | 14,449 | |||||||||||||||
| Total accrued liabilities | $ | 281,079 | $ | 331,651 | |||||||||||||
7. Fair Value Measurements
In accordance with the FASB’s authoritative guidance on fair value measurements, the Company’s financial assets and liabilities are measured at fair value on a recurring basis. The Company’s financial instruments, including certain cash and cash equivalents, accounts receivable, accounts payable and other payables, are carried at cost, which approximates their respective fair market values due to their short-term maturities. The Company recognizes its non-financial assets and liabilities, such as ARO (see Note 14—Asset Retirement Obligations) and proved oil and gas properties upon impairment (see Note 9—Property, Plant and Equipment), at fair value on a non-recurring basis.
As defined in the authoritative guidance, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). To estimate fair value, the Company utilizes market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable.
The authoritative guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (“Level 1” measurements) and the lowest priority to unobservable inputs (“Level 3” measurements). The three levels of the fair value hierarchy are as follows:
Level 1 — Unadjusted quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
111
Level 2 — Pricing inputs, other than unadjusted quoted prices in active markets included in Level 1, are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Level 3 — Pricing inputs are generally less observable from objective sources, requiring internally developed valuation methodologies that result in management’s best estimate of fair value.
Financial Assets and Liabilities
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The following tables set forth by level within the fair value hierarchy the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis:
| Fair value at December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||||||||||||||
| Money market funds | $ | 146 | $ | — | $ | — | $ | 146 | |||||||||||||||||||||||||||||||||
| Commodity derivative instruments (see Note 8) | — | 1,174 | — | 1,174 | |||||||||||||||||||||||||||||||||||||
| Total assets | $ | 146 | $ | 1,174 | $ | — | $ | 1,320 | |||||||||||||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||||||||||||||
| Commodity derivative instruments (see Note 8) | $ | — | $ | 19,815 | $ | — | $ | 19,815 | |||||||||||||||||||||||||||||||||
| Total liabilities | $ | — | $ | 19,815 | $ | — | $ | 19,815 | |||||||||||||||||||||||||||||||||
| Fair value at December 31, 2018 | |||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | ||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||
| Assets: | |||||||||||||||||||||||||||||||||||||||||
| Money market funds | $ | 143 | $ | — | $ | — | $ | 143 | |||||||||||||||||||||||||||||||||
| Commodity derivative instruments (see Note 8) | — | 106,875 | — | 106,875 | |||||||||||||||||||||||||||||||||||||
| Total assets | $ | 143 | $ | 106,875 | $ | — | $ | 107,018 | |||||||||||||||||||||||||||||||||
| Liabilities: | |||||||||||||||||||||||||||||||||||||||||
| Commodity derivative instruments (see Note 8) | $ | — | $ | 104 | $ | — | $ | 104 | |||||||||||||||||||||||||||||||||
| Total liabilities | $ | — | $ | 104 | $ | — | $ | 104 | |||||||||||||||||||||||||||||||||
The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s Consolidated Balance Sheets at December 31, 2019 and 2018. The Company’s money market funds represent cash equivalents backed by the assets of high-quality major banks and financial institutions. The Company identifies the money market funds as Level 1 instruments because the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained, and there are active markets for the underlying investments.
The Level 2 instruments presented in the tables above consist of commodity derivative instruments, which include crude oil and natural gas swaps and collars. The fair values of the Company’s commodity derivative instruments are based upon a third-party preparer’s calculation using mark-to-market valuation reports provided by the Company’s counterparties for monthly settlement purposes to determine the valuation of its derivative instruments. The Company has the third-party preparer evaluate other readily available market prices for its derivative contracts as there is an active market for these contracts. The third-party preparer performs its independent valuation using a moment matching method similar to Turnbull-Wakeman for Asian options. The significant inputs used are crude oil prices, volatility, skew, discount rate and the contract terms of the derivative instruments. However, the Company does not have access to the specific proprietary valuation models or inputs used by its counterparties or third-party preparer. The Company compares the third-party preparer’s valuation to counterparty valuation statements, investigating any significant differences, and analyzes monthly valuation changes in relation to movements in crude oil and natural gas forward price curves. The determination of the fair value for derivative instruments also incorporates a credit adjustment for non-performance risk, as required by GAAP. The Company calculates the credit adjustment for derivatives in an
112
asset position using current credit default swap values for each counterparty. The credit adjustment for derivatives in a net liability position is based on the Company’s market credit spread. Based on these calculations, the Company recorded an adjustment to reduce the fair value of its net derivative liability by $0.5 million at December 31, 2019 and an adjustment to reduce the fair value of its net derivative asset by $0.2 million at December 31, 2018.
There were no transfers between fair value levels during the years ended December 31, 2019 and 2018.
8. Derivative Instruments
The Company utilizes derivative financial instruments to manage risks related to changes in crude oil and natural gas prices. The Company’s crude oil contracts will settle monthly based on the average NYMEX West Texas Intermediate crude oil index price (“NYMEX WTI”). The Company’s natural gas contracts will settle monthly based on the average NYMEX Henry Hub natural gas index price (“NYMEX HH”).
At December 31, 2019, the Company utilized fixed price swaps and two-way and three-way costless collars to reduce the volatility of crude oil prices on a significant portion of its future expected crude oil production. The Company’s fixed price swaps are comprised of a sold call and a purchased put established at the same price (both ceiling and floor), which the Company will receive for the volumes under contract. A two-way collar is a combination of options: a sold call and a purchased put. The purchased put establishes a minimum price (floor) and the sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract. A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The purchased put establishes a minimum price (floor), unless the market price falls below the sold put (sub-floor), at which point the minimum price would be the NYMEX index price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price (ceiling) the Company will receive for the volumes under contract.
All derivative instruments are recorded on the Company’s Consolidated Balance Sheets as either assets or liabilities measured at their fair value (see Note 7—Fair Value Measurements). The Company has not designated any derivative instruments as hedges for accounting purposes and does not enter into such instruments for speculative trading purposes. If a derivative does not qualify as a hedge or is not designated as a hedge, the changes in fair value are recognized in the other income (expense) section of the Company’s Consolidated Statements of Operations as a net gain or loss on derivative instruments. The Company’s cash flow is only impacted when the actual settlements under the derivative contracts result in making a payment to or receiving a payment from the counterparty. These cash settlements represent the cumulative gains and losses on the Company’s derivative instruments and do not include a recovery of costs that were paid to acquire or modify the derivative instruments that were settled. Cash settlements are reflected as investing activities in the Company’s Consolidated Statements of Cash Flows.
At December 31, 2019, the Company had the following outstanding commodity derivative instruments:
| Commodity |
Settlement
Period |
Derivative
Instrument |
Index | Volumes | Weighted Average Prices |
Fair Value
Assets (Liabilities) |
||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fixed Price Swaps | Sub-Floor | Floor | Ceiling | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2020 | Fixed price swaps | NYMEX WTI | 6,550,000 | Bbl | $ | 57.17 | $ | (14,087) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2020 | Two-way collar | NYMEX WTI | 3,296,000 | Bbl | $ | 51.76 | $ | 61.76 | (4,743) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2020 | Three-way collar | NYMEX WTI | 5,339,000 | Bbl | $ | 40.00 | $ | 52.79 | $ | 64.06 | (330) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2021 | Fixed price swaps | NYMEX WTI | 248,000 | Bbl | $ | 56.05 | 36 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2021 | Two-way collar | NYMEX WTI | 248,000 | Bbl | $ | 50.75 | $ | 59.13 | (86) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2021 | Three-way collar | NYMEX WTI | 889,000 | Bbl | $ | 40.00 | $ | 51.04 | $ | 63.61 | 569 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| $ | (18,641) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
113
Subsequent to December 31, 2019, the Company entered into additional swaps and two-way and three-way costless collars. As of February 26, 2020, the Company had the following outstanding commodity derivative contracts, which includes settlements from January 2020:
| Commodity |
Settlement
Period |
Derivative
Instrument |
Index | Volumes | Weighted Average Prices | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Fixed Price Swaps | Sub-Floor | Floor | Ceiling | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2020 | Fixed price swaps | NYMEX WTI | 6,948,000 | Bbl | $ | 57.14 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2020 | Two-way collar | NYMEX WTI | 3,296,000 | Bbl | $ | 51.99 | $ | 61.83 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2020 | Three-way collar | NYMEX WTI | 6,098,000 | Bbl | $ | 40.74 | $ | 53.28 | $ | 63.88 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2021 | Fixed price swaps | NYMEX WTI | 310,000 | Bbl | $ | 56.01 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2021 | Two-way collar | NYMEX WTI | 248,000 | Bbl | $ | 51.38 | $ | 59.33 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude oil | 2021 | Three-way collar | NYMEX WTI | 1,313,000 | Bbl | $ | 40.00 | $ | 50.79 | $ | 62.46 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The following table summarizes the location and amounts of gains and losses from the Company’s commodity derivative instruments recorded in the Company’s Consolidated Statements of Operations for the periods presented:
| Year Ended December 31, | ||||||||||||||||||||||||||||||||
| Statement of Operations Location | 2019 | 2018 | 2017 | |||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
| Net gain (loss) on derivative instruments | $ | (106,314) | $ | 28,457 | $ | (71,657) | ||||||||||||||||||||||||||
In accordance with the FASB’s authoritative guidance on disclosures about offsetting assets and liabilities, the Company is required to disclose both gross and net information about instruments and transactions eligible for offset in the statement of financial position as well as instruments and transactions subject to an agreement similar to a master netting agreement. The Company’s derivative instruments are presented as assets and liabilities on a net basis by counterparty, as all counterparty contracts provide for net settlement. No margin or collateral balances are deposited with counterparties, and as such, gross amounts are offset to determine the net amounts presented in the Company’s Consolidated Balance Sheets.
114
The following tables summarize the location and fair value of all outstanding commodity derivative instruments recorded in the Company’s Consolidated Balance Sheets:
| December 31, 2019 | ||||||||||||||||||||||||||||||||||||||
| Commodity | Balance Sheet Location | Gross Recognized Assets/Liabilities | Gross Amount Offset | Net Recognized Fair Value Assets/Liabilities | ||||||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||||
| Derivatives assets: | ||||||||||||||||||||||||||||||||||||||
| Commodity contracts | Derivative instruments — current assets | $ | 633 | $ | (98) | $ | 535 | |||||||||||||||||||||||||||||||
| Commodity contracts | Derivative instruments — non-current assets | 3,295 | (2,656) | 639 | ||||||||||||||||||||||||||||||||||
| Total derivatives assets | $ | 3,928 | $ | (2,754) | $ | 1,174 | ||||||||||||||||||||||||||||||||
| Derivatives liabilities: | ||||||||||||||||||||||||||||||||||||||
| Commodity contracts | Derivative instruments — current liabilities | $ | 33,812 | $ | (14,117) | $ | 19,695 | |||||||||||||||||||||||||||||||
| Commodity contracts | Derivative instruments — non-current liabilities | 686 | (566) | 120 | ||||||||||||||||||||||||||||||||||
| Total derivatives liabilities | $ | 34,498 | $ | (14,683) | $ | 19,815 | ||||||||||||||||||||||||||||||||
| December 31, 2018 | ||||||||||||||||||||||||||||||||||||||
| Commodity | Balance Sheet Location | Gross Recognized Assets/Liabilities | Gross Amount Offset | Net Recognized Fair Value Assets/Liabilities | ||||||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||||
| Derivatives assets: | ||||||||||||||||||||||||||||||||||||||
| Commodity contracts | Derivative instruments — current assets | $ | 110,729 | $ | (10,799) | $ | 99,930 | |||||||||||||||||||||||||||||||
| Commodity contracts | Derivative instruments — non-current assets | 8,251 | (1,306) | 6,945 | ||||||||||||||||||||||||||||||||||
| Total derivatives assets | $ | 118,980 | $ | (12,105) | $ | 106,875 | ||||||||||||||||||||||||||||||||
| Derivatives liabilities: | ||||||||||||||||||||||||||||||||||||||
| Commodity contracts | Derivative instruments — current liabilities | $ | 84 | $ | — | $ | 84 | |||||||||||||||||||||||||||||||
| Commodity contracts | Derivative instruments — non-current liabilities | 20 | — | 20 | ||||||||||||||||||||||||||||||||||
| Total derivatives liabilities | $ | 104 | $ | — | $ | 104 | ||||||||||||||||||||||||||||||||
9. Property, Plant and Equipment
The following table sets forth the Company’s property, plant and equipment:
| December 31, | |||||||||||||||||
| 2019 | 2018 | ||||||||||||||||
| (In thousands) | |||||||||||||||||
|
Proved oil and gas properties(1)
|
$ | 8,724,376 | $ | 7,878,104 | |||||||||||||
| Less: Accumulated depreciation, depletion, amortization and impairment | (3,601,019) | (2,853,353) | |||||||||||||||
| Proved oil and gas properties, net | 5,123,357 | 5,024,751 | |||||||||||||||
| Unproved oil and gas properties | 738,662 | 1,034,085 | |||||||||||||||
|
Other property and equipment(2)
|
1,279,653 | 1,151,772 | |||||||||||||||
| Less: Accumulated depreciation | (163,896) | (183,499) | |||||||||||||||
| Other property and equipment, net | 1,115,757 | 968,273 | |||||||||||||||
| Total property, plant and equipment, net | $ | 6,977,776 | $ | 7,027,109 | |||||||||||||
__________________
(1)Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $42.3 million and $40.5 million at December 31, 2019 and 2018, respectively.
(2)Included in the Company’s other property and equipment are estimates of future asset retirement costs of $1.4 million and $1.3 million at December 31, 2019 and 2018, respectively.
115
Impairment. The Company reviews its property, plant and equipment for impairment by asset group whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. If events occur that indicate an asset group may not be recoverable, the asset group is tested for recoverability. For its proved oil and gas properties, the Company estimates the expected undiscounted future cash flows of its proved oil and gas properties by field and then compares such amount to the carrying amount of the proved oil and gas properties in the applicable field to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will adjust the carrying amount of the proved oil and gas properties to fair value. The factors used to determine fair value are subject to management’s judgment and expertise and include, but are not limited to, recent sales prices of comparable properties, the present value of future cash flows net of estimated operating and development costs using estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the expected cash flows projected. These assumptions represent Level 3 inputs, as further discussed under Note 7 — Fair Value Measurements.
The Company reports assets held for sale at the lower of their carrying amount or estimated fair value less costs to sell, with an impairment loss recognized to the extent the carrying amount exceeds this value. During the year ended December 31, 2019, the Company recorded an impairment loss of $4.4 million to adjust the carrying value of certain inventory and equipment held for sale to their estimated fair value (see Note 12—Assets Held for Sale). As of December 31, 2018, the Company sold certain proved and unproved oil and gas properties (see Note 11—Divestitures). For the year ended December 31, 2018, the Company recorded an impairment loss of $383.4 million, which was included in its exploration and production segment to adjust the carrying amount of these assets, net of the associated ARO liabilities, to their estimated fair value. For the years ended, December 31, 2019 and 2017, the Company did not record impairment of proved oil and gas properties.
In addition, as a result of expiring leases, periodic assessments and drilling plan uncertainty on certain acreage of unproved properties, the Company recorded non-cash impairment charges on its unproved oil and gas properties of $5.4 million, $0.9 million and $6.9 million for the years ended December 31, 2019, 2018 and 2017, respectively.
The Company reviews its other property and equipment for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred.
10. Acquisitions
Permian Basin Acquisition. On February 14, 2018, the Company and OP Permian, a wholly owned subsidiary of the Company, acquired from Forge Energy, LLC (“Forge Energy”) approximately 22,000 net acres in the Delaware Basin (the “Permian Basin Acquisition”) for aggregate consideration consisting of approximately $549.8 million in cash, inclusive of a $47.3 million deposit paid to Forge Energy in December 2017, and 46,000,000 shares of the Company’s common stock (the “Purchase Price”), including customary post close adjustments. In connection with the closing of the Permian Basin Acquisition, the Company and Forge Energy entered into a Registration Rights Agreement that granted the equity holders of Forge Energy certain customary registration rights for the stock portion of the Purchase Price. The Company funded the cash portion of the Purchase Price with borrowings under a senior secured revolving line of credit among OPNA, as Borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders party thereto (the “Oasis Credit Facility,” and, together with the OMP Credit Facility, the “Revolving Credit Facilities”), and proceeds from the Company’s December 2017 issuance of its common stock.
The Permian Basin Acquisition represents the Company’s initial entry into the Delaware Basin. The assets underlying the Permian Basin Acquisition are primarily located in the Bone Spring and Wolfcamp formations of the Delaware sub-basin, across Ward, Winkler, Loving and Reeves Counties, Texas.
The Permian Basin Acquisition qualified as a business combination. As such, the Company estimated the fair value of the assets acquired and liabilities assumed as of the February 14, 2018 acquisition date. The fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of oil and gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as further discussed under Note 7 — Fair Value Measurements. The Company recorded the assets acquired and liabilities assumed in the Permian Basin Acquisition at their estimated fair value of $921.0 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. The Permian Basin Acquisition is considered a taxable transaction; therefore, no deferred tax amounts were recognized at the acquisition date as the tax basis of the assets acquired and liabilities assumed were also recorded at fair value.
116
The following table summarizes the consideration paid for the Company’s acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date.
| At February 14, 2018 | |||||
| (In thousands) | |||||
| Consideration paid to Forge Energy: | |||||
| Cash | $ | 549,770 | |||
|
Common stock: 46,000,000 shares issued
|
371,220 | ||||
| $ | 920,990 | ||||
| Recognized amounts of identifiable assets acquired and liabilities assumed: | |||||
| Proved developed properties | $ | 110,325 | |||
| Proved undeveloped properties | 166,552 | ||||
| Unproved lease acquisition costs | 645,068 | ||||
| Inventory | 293 | ||||
| Intangible assets | 1,000 | ||||
| Asset retirement obligations | (2,248) | ||||
| $ | 920,990 | ||||
The results of operations for the Permian Basin Acquisition have been included in the Company’s consolidated financial statements since the February 14, 2018 closing date, including $71.7 million of total revenue and $15.6 million of operating income for the year ended December 31, 2018.
The Company also recorded a $1.0 million finite-lived intangible asset on the Company’s Consolidated Balance Sheets for a non-compete agreement with a one-year life. Intangible assets are amortized on a straight-line basis over the useful life, and the Company includes the amortization in depreciation, depletion and amortization expenses on the Company’s Consolidated Statements of Operations. For the years ended December 31, 2018 and 2019, amortization expense recognized for this non-compete agreement was approximately $0.9 million and $0.1 million, respectively.
Summarized below are the consolidated results of operations for the year ended December 31, 2018, on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2017. The unaudited pro forma financial information was derived from the historical consolidated statements of operations of the Company and the statement of revenues and direct operating expenses for the Permian Basin Acquisition properties, which were derived from the historical accounting records of Forge Energy. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations.
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2018 | 2017 | ||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Unaudited | |||||||||||||||||||||||||||||
| Revenues | $ | 2,327,476 | $ | 1,337,468 | |||||||||||||||||||||||||
| Net income (loss) attributable to Oasis | (30,754) | 159,838 | |||||||||||||||||||||||||||
| Net income (loss) attributable to Oasis per share: | |||||||||||||||||||||||||||||
| Basic | $ | (0.10) | $ | 0.57 | |||||||||||||||||||||||||
| Diluted | (0.10) | 0.56 | |||||||||||||||||||||||||||
Other Delaware Acquisition. On September 12, 2018, the Company completed the initial closing with undisclosed sellers to acquire certain exploration and production assets adjacent to the Company’s existing Delaware position (the “Other Delaware Acquisition”) for total cash consideration of $59.5 million. The final closing statement was finalized in January 2019, subsequent to the year ended December 31, 2018. Based on the FASB’s authoritative guidance, the acquisition qualified as a business combination, and as such, the Company estimated the fair value of the assets acquired as of the acquisition date. The Company recorded the oil and gas properties acquired at their estimated fair value of $59.5 million, which the Company considers to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized.
117
The results of operations for the Other Delaware Acquisition have been included in the Company’s consolidated financial statements since the closing date. Pro forma information is not presented as the pro forma results would not be materially different from the information presented in the Company’s Consolidated Statement of Operations.
Acquisitions. The Company actively reviews acquisition opportunities on an ongoing basis and acquires additional acreage and producing assets to supplement its existing operations. In addition to the Permian Basin Acquisition and Other Delaware Acquisition in 2018, the Company spent $21.0 million and $18.7 million to purchase certain acreage and producing assets through multiple transactions during the years ended December 31, 2019 and 2018, respectively. Based on the FASB’s authoritative guidance, these transactions were considered asset acquisitions, and as such, the Company recorded the properties based on the fair value of the total cash consideration transferred on the acquisition dates.
11. Divestitures
The Company reviews portfolio opportunities on an ongoing basis and has engaged in various divestiture transactions over recent years.
Williston Non-Op Divestiture. On July 10, 2018, the Company completed the initial closing for the sale of certain non-operated oil and gas properties in the Williston Basin (the “Williston Non-Op Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in the fourth quarter of 2018. The Company recognized a $18.1 million net gain on sale of properties, which includes customary post close adjustments, in its Consolidated Statements of Operations for the year ended December 31, 2018. During the year ended December 31, 2019, the Company recognized an additional $1.2 million net loss on sale of properties, which includes customary closing adjustments, in its Consolidated Statements of Operations. The divested properties were in the Company’s exploration and production segment.
Foreman Butte Divestiture. On July 31, 2018, the Company completed the initial closing for the sale of oil and gas properties and certain other property and equipment primarily located in the Foreman Butte area of the Williston Basin (the “Foreman Butte Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in January 2019. During the second quarter of 2018, the Company recorded an impairment loss of $383.4 million, which was included in impairment on the Company’s Consolidated Statements of Operations, to adjust the carrying value of these assets to their estimated fair value, determined based on the expected sales price as negotiated with the purchaser, less costs to sell. The Company recognized a $10.7 million net loss on sale of properties, which includes customary post close adjustments, in its Consolidated Statements of Operations for the year ended December 31, 2018. During the year ended December 31, 2019, the Company recognized an additional $2.8 million net loss on sale of properties, which includes customary closing adjustments, in its Consolidated Statements of Operations. The Foreman Butte Divestiture consisted of oil and gas properties in the Company’s exploration and production segment and included certain other property and equipment in the Company’s midstream segment.
Other Williston Divestiture. On August 17, 2018, the Company completed the initial closing for the sale of additional non-strategic oil and gas properties in the Williston Basin (the “Other Williston Divestiture”). The transaction had an effective date of March 1, 2018, and the final closing statement was completed in March 2019. The Company recognized a $19.0 million net gain on sale of properties, which includes, and is subject to further, customary post close adjustments, in its Consolidated Statements of Operations for the year ended December 31, 2018. The divested properties were in the Company’s exploration and production segment.
The Company determined that the Williston Non-Op Divestiture, Foreman Butte Divestiture and Other Williston Divestiture did not represent a strategic shift in its operations or have a significant impact on its financial position or results of operations; therefore, the Company did not account for these divestitures as discontinued operations.
In addition to the aforementioned divestitures, the Company also sold partial interests in certain oil and gas properties in the Company’s exploration and production segment. During the year ended December 31, 2019, the Company recognized a $0.4 million net loss on sale of properties, which includes customary closing adjustments, in its Consolidated Statements of Operations.
Subsequent event. In January 2020, the Company completed the initial closing to sell certain oil and gas properties in the Williston Basin for total cash proceeds of $10.4 million. The transaction had an effective date of October 1, 2019, and the final closing statements for the transaction will be completed in July 2020. Upon the initial closing, the Company recognized a $10.4 million net gain on sale of properties, which includes customary closing adjustments, subsequent to the year ended December 31, 2019.
12. Assets Held for Sale
During the fourth quarter of 2019, the Company decided to pursue an exit from the well services business (the “Well Services Exit”) and began an active program to locate buyers for certain well services inventory and equipment included within the Company’s well services business segment. In March 2020, the Company intends to transition its well fracturing services from OWS to a third-party provider who will provide services to the Company under a long-term agreement. The assets expected to
118
be sold related to the Well Services Exit met the criteria for assets held for sale and are classified as such as of December 31, 2019.
During the year ended December 31, 2019, the Company recorded an impairment loss of $4.4 million, which was included in impairment on the Company’s Consolidated Statements of Operations, to adjust the carrying value of these assets to their estimated fair value less costs to sell, determined primarily based on indicative bids and indicative market pricing. The Company considered all available information at the time the estimates were made; however, the fair value that will be ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. The expected sale of assets related to the Well Services Exit does not represent a strategic shift that will have a major effect on the Company’s operations and financial results, and therefore, is not reported as discontinued operations.
The Company did not have any assets or liabilities classified as held for sale as of December 31, 2018. The following table presents balance sheet data related to the assets held for sale related to the Well Services Exit as of December 31, 2019:
| December 31, 2019 | |||||
| (In thousands) | |||||
| Inventory | $ | 3,124 | |||
| Other property and equipment | 95,560 | ||||
| Less: Accumulated depreciation and impairment | (77,056) | ||||
| Total assets held for sale, net | $ | 21,628 | |||
13. Long-Term Debt
The Company’s long-term debt consists of the following:
| December 31, | |||||||||||||||||
| 2019 | 2018 | ||||||||||||||||
| (In thousands) | |||||||||||||||||
| Oasis Credit Facility | $ | 337,000 | $ | 468,000 | |||||||||||||
| OMP Credit Facility | 458,500 | 318,000 | |||||||||||||||
| Senior unsecured notes | |||||||||||||||||
|
6.50% senior unsecured notes due November 1, 2021
|
71,835 | 71,835 | |||||||||||||||
|
6.875% senior unsecured notes due March 15, 2022
|
890,980 | 901,480 | |||||||||||||||
|
6.875% senior unsecured notes due January 15, 2023
|
351,953 | 366,094 | |||||||||||||||
|
6.25% senior unsecured notes due May 1, 2026
|
400,000 | 400,000 | |||||||||||||||
|
2.625% senior unsecured convertible notes due September 15, 2023
|
267,800 | 300,000 | |||||||||||||||
| Total principal of senior unsecured notes | 1,982,568 | 2,039,409 | |||||||||||||||
| Less: unamortized deferred financing costs on senior unsecured notes | (15,618) | (20,865) | |||||||||||||||
| Less: unamortized debt discount on senior unsecured convertible notes | (50,877) | (69,268) | |||||||||||||||
| Total long-term debt | $ | 2,711,573 | $ | 2,735,276 | |||||||||||||
The carrying amount of the Company’s long-term debt reported in the Consolidated Balance Sheets at December 31, 2019 is $2,711.6 million, which includes $1,982.6 million of senior unsecured notes, reductions for the unamortized debt discount related to the equity component of the senior unsecured convertible notes and the unamortized deferred financing costs on the senior unsecured notes of $50.9 million and $15.6 million, respectively, $337.0 million of borrowings under the Oasis Credit Facility and $458.5 million under the OMP Credit Facility. The Revolving Credit Facilities are recorded at values that approximate fair value since their variable interest rates are tied to current market rates. The fair value of the Company’s senior unsecured notes, which are publicly traded and therefore categorized as Level 1 liabilities, was $1,812.6 million at December 31, 2019.
The Company has $71.8 million, $891.0 million, $619.8 million and $400.0 million of Notes maturing in 2021, 2022, 2023 and 2026, respectively, and indebtedness under the Oasis Credit Facility and the OMP Credit Facility that become due in 2023 and 2022, respectively. The Company does not have any other debt that matures within the five years ending December 31, 2024.
Senior secured revolving line of credit. The Company has the Oasis Credit Facility with an overall senior secured line of credit of $3,000.0 million as of December 31, 2019, which has a maturity date of the earlier of (i) October 16, 2023, (ii) 90 days prior
119
to the maturity date of the Company’s senior unsecured notes due in 2022 and 2023, of which $1,242.9 million is outstanding, to the extent such senior unsecured notes are not retired or refinanced to have a maturity date at least 90 days after October 16, 2023 and (iii) 90 days prior to the maturity date of the Company’s senior unsecured convertible notes due in 2023, of which $267.8 million is outstanding, to the extent such senior unsecured convertible notes are not retired, converted, redeemed or refinanced to have a maturity date at least 90 days after October 16, 2023.
The Oasis Credit Facility is restricted to a borrowing base, which is reserve-based and subject to semi-annual redeterminations on April 1 and October 1 of each year. On April 15, 2019, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of the borrowing base scheduled for April 1, 2019, which reaffirmed the borrowing base and the aggregate elected commitment at $1,600.0 million and $1,350.0 million, respectively. In connection with the April 1, 2019 borrowing base redetermination, the Company entered into the First Amendment to the Third Amended and Restated Credit Agreement to the Oasis Credit Facility, dated April 15, 2019, which, among other things, incorporated the ability for the Company to request swingline loans subject to a swingline loans sublimit of $50.0 million.
On November 4, 2019, the lenders under the Oasis Credit Facility completed their regular semi-annual redetermination of the Company’s borrowing base scheduled for October 1, 2019. As a result, the borrowing base decreased from $1,600.0 million to $1,300.0 million. The next redetermination of the Oasis Credit Facility’s borrowing base is scheduled for April 1, 2020. Additionally, the Company entered into the third amendment to the Oasis Credit Facility, which among other things, decreased the aggregate elected commitment from $1,350.0 million to $1,100.0 million in conjunction with the redetermination.
Borrowings under the Oasis Credit Facility are collateralized by perfected first priority liens and security interests on substantially all of the Company’s assets, including mortgage liens on oil and gas properties having at least 90% (as of December 31, 2019) of the reserve value as determined by reserve reports.
Borrowings under the Oasis Credit Facility are subject to varying rates of interest based on (i) the total outstanding borrowings (including the value of all outstanding letters of credit) in relation to the borrowing base and (ii) whether the loan is a London interbank offered rate (“LIBOR”) loan or a domestic bank prime interest rate loan (defined in the Oasis Credit Facility as an Alternate Based Rate or “ABR” loan). As of December 31, 2019, any outstanding LIBOR and ABR loans would have borne their respective interest rates plus the applicable margin indicated in the following table:
| Total Commitment Utilization Percentage |
Applicable Margin
for LIBOR Loans |
Applicable Margin
for ABR Loans |
|||||||||
|
Less than 25%
|
1.50 | % | 0.00 | % | |||||||
|
Greater than or equal to 25% but less than 50%
|
1.75 | % | 0.25 | % | |||||||
|
Greater than or equal to 50% but less than 75%
|
2.00 | % | 0.50 | % | |||||||
|
Greater than or equal to 75% but less than 90%
|
2.25 | % | 0.75 | % | |||||||
|
Greater than or equal to 90%
|
2.50 | % | 1.00 | % | |||||||
A loan may be repaid at any time before the scheduled maturity of the Oasis Credit Facility upon the Company providing advance notification to the Lenders. Interest is paid quarterly on ABR loans based on the number of days an ABR loan is outstanding as of the last business day in March, June, September and December. The Company has the option to convert an ABR loan to a LIBOR-based loan upon providing advance notification to the Lenders. The minimum available loan term is one month and the maximum available loan term is six months for LIBOR-based loans (or twelve months with the consent of each leader). Interest for LIBOR loans is paid at the end of the applicable interest period for each loan or every three months for LIBOR loans that have loan terms greater than three months. At the end of a LIBOR loan term, the Oasis Credit Facility allows the Company to elect to repay the borrowing, continue a LIBOR loan with the same or differing loan term or convert the borrowing to an ABR loan.
On a quarterly basis, the Company also pays a commitment fee that can range from 0.375% to 0.500% on the average amount of borrowing base capacity not utilized during the quarter and fees calculated on the average amount of letter of credit balances outstanding during the quarter.
As of December 31, 2019, the Oasis Credit Facility contained covenants that included, among others:
•a prohibition against incurring debt, subject to permitted exceptions;
•a prohibition against making dividends, distributions and redemptions, subject to permitted exceptions;
•a prohibition against making investments, loans and advances, subject to permitted exceptions;
•restrictions on creating liens and leases on the assets of the Company and its subsidiaries, subject to permitted exceptions;
•restrictions on merging and selling assets outside the ordinary course of business;
•restrictions on use of proceeds, investments, transactions with affiliates or change of principal business;
120
•a provision limiting crude oil and natural gas derivative financial instruments;
•a requirement that the Company maintain a ratio of consolidated EBITDAX (as defined in the Oasis Credit Facility) to consolidated Interest Expense (as defined in the Oasis Credit Facility) of no less than 2.5 to 1.0 for the four quarters ended on the last day of each quarter;
•a requirement that the Company maintain a Current Ratio (as defined in the Oasis Credit Facility) of consolidated current assets (including unused borrowing capacity and with exclusions as described in the Oasis Credit Facility) to consolidated current liabilities (with exclusions as described in the Oasis Credit Facility) of no less than 1.0 to 1.0 as of the last day of any fiscal quarter; and
•if the Aggregate Elected Commitment Amounts (as defined in the Oasis Credit Facility) exceed 85% of the effective borrowing base (“Trigger”), the Company is required to maintain a ratio of total debt (as defined in the Oasis Credit Facility) to consolidated EBITDAX (as defined in the Oasis Credit Facility) (the “Leverage Ratio”). The Leverage Ratio will be first tested during the quarter in which the Trigger occurs. The Leverage Ratio shall continue to be tested as long as the Aggregate Elected Commitment Amounts exceed 85% of the effective borrowing base, and shall not exceed 4.25 to 1.00 for the first two quarters and 4.00 to 1.00 for each fiscal quarter thereafter.
The Oasis Credit Facility contains customary events of default. If an event of default occurs and is continuing, the Lenders may declare all amounts outstanding under the Oasis Credit Facility to be immediately due and payable.
As of December 31, 2019, the Company had $337.0 million of borrowings and $15.1 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $747.9 million. As of December 31, 2018, the Company had $468.0 million of borrowings and $14.0 million of outstanding letters of credit issued under the Oasis Credit Facility, resulting in an unused borrowing capacity of $868.0 million. As of December 31, 2019 and 2018, the weighted average interest rate on borrowings under the Oasis Credit Facility was 3.5% and 4.2%, respectively. The Company was in compliance with the financial covenants of the Oasis Credit Facility as of December 31, 2019 and 2018.
OMP Operating LLC revolving line of credit. Through its ownership of OMP, the Company has access to the OMP Credit Facility, which is available to fund working capital and to finance acquisitions and other capital expenditures of OMP. On May 6, 2019, OMP entered into an amendment to the OMP Credit Facility to (i) increase the aggregate amount of commitments from $400.0 million to $475.0 million; (ii) provide for the ability to further increase commitments to $675.0 million; and (iii) add a new lender to the bank group. On August 16, 2019, OMP entered into the third amendment to the OMP Credit Facility to (i) increase the aggregate amount of commitments from $475.0 million to $575.0 million and (ii) provide for the ability to further increase commitments to $775.0 million. As of December 31, 2019, the OMP Credit Facility has an aggregate amount of commitments of $575.0 million and has a maturity date of September 25, 2022.
The OMP Credit Facility includes a letter of credit sublimit of $10.0 million and a swingline loans sublimit of $10.0 million. All obligations of OMP Operating, as the borrower under the OMP Credit Facility, are unconditionally guaranteed on a joint and several basis by OMP, Bighorn DevCo and Panther DevCo.
Borrowings under the OMP Credit Facility bear interest at a rate per annum equal to the applicable margin (as described below) plus (i) with respect to Eurodollar Loans, the Adjusted LIBO Rate (as defined in the OMP Credit Agreement) or (ii) with respect to ABR loans, the greatest of (A) the Prime Rate in effect on such day, (B) the Federal Funds Effective Rate in effect on such day plus 1/2 of 1.00% or (C) the Adjusted LIBO Rate for a one-month interest period on such day plus 1.00% (each as defined in the OMP Credit Agreement). The applicable margin for borrowings under the OMP Credit Facility is determined in accordance with the OMP Credit Agreement as follows:
| Consolidated Total Leverage Ratio |
Applicable Margin
for Eurodollar Loans |
Applicable Margin
for ABR Loans |
Commitment Fee Rate | ||||||||||||||
|
Less than or equal to 3.00 to 1.00
|
1.75 | % | 0.75 | % | 0.375 | % | |||||||||||
|
Greater than 3.00 to 1.00 but less than or equal to 3.50 to 1.00
|
2.00 | % | 1.00 | % | 0.375 | % | |||||||||||
|
Greater than 3.50 to 1.00 but less than or equal to 4.00 to 1.00
|
2.25 | % | 1.25 | % | 0.500 | % | |||||||||||
|
Greater than 4.00 to 1.00 but less than or equal to 4.50 to 1.00
|
2.50 | % | 1.50 | % | 0.500 | % | |||||||||||
|
Greater than 4.50 to 1.00
|
2.75 | % | 1.75 | % | 0.500 | % | |||||||||||
The OMP Credit Facility includes certain financial covenants as of the end of each fiscal quarter, including a (1) consolidated total leverage ratio, (2) consolidated senior secured leverage ratio and (3) consolidated interest coverage ratio (each covenant as described in the OMP Credit Agreement).
As of December 31, 2019, the Company had $458.5 million of borrowings and $1.7 million of outstanding letters of credit issued under the OMP Credit Facility, resulting in an unused borrowing capacity of $114.8 million. As of December 31, 2018,
121
the Company had $318.0 million of borrowings under the OMP Credit Facility, resulting in an unused borrowing capacity of $82.0 million. As of December 31, 2019 and 2018, the weighted average interest rate on borrowings under the OMP Credit Facility was 3.8% and 4.2%, respectively. OMP Operating was in compliance with the financial covenants of the OMP Credit Facility as of December 31, 2019.
Senior unsecured notes. At December 31, 2019, the Company had $1,714.8 million principal amount of senior unsecured notes outstanding with maturities ranging from November 2021 to May 2026 and coupons ranging from 6.25% to 6.875% (the “Senior Notes”). Prior to certain dates, the Company has the option to redeem some or all of the Senior Notes for cash at certain redemption prices equal to a certain percentage of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date.
During the fourth quarter of 2019, the Company repurchased an aggregate principal amount of $24.6 million of its outstanding Senior Notes, consisting of $10.5 million principal amount of the 6.875% senior unsecured notes due March 15, 2022 and $14.1 million principal amount of the 6.875% senior unsecured notes due January 15, 2023, for an aggregate cost of $22.8 million. As a result of these repurchases, the Company recognized a pre-tax gain of $1.6 million, which was net of unamortized deferred financing costs write-offs of $0.2 million, and is reflected in gain on extinguishment of debt in the Company’s Consolidated Statements of Operations for the year ended December 31, 2019.
The indentures governing the Senior Notes restrict the Company’s ability and the ability of certain of the Company’s subsidiaries to: (i) incur additional debt or enter into sale and leaseback transactions; (ii) pay distributions on, redeem or repurchase equity interests; (iii) make certain investments; (iv) incur liens; (v) enter into transactions with affiliates; (vi) merge or consolidate with another company; and (vii) transfer and sell assets. These covenants are subject to a number of important exceptions and qualifications. If at any time when the Company’s Senior Notes are rated investment grade by both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate and the Company will cease to be subject to such covenants. The Company was in compliance with the terms of the indentures for the Senior Notes as of December 31, 2019.
Senior unsecured convertible notes. At December 31, 2019, the Company had $267.8 million of 2.625% senior unsecured convertible notes due September 2023 (the “Senior Convertible Notes”). During the fourth quarter of 2019, the Company repurchased a principal amount of $32.2 million of its outstanding Senior Convertible Notes, for an aggregate cost of $23.0 million. As a result of these repurchases, the Company recognized a pre-tax gain of $2.7 million, which was net of the unamortized debt discount write-offs of $6.2 million and the unamortized deferred financing costs write-offs of $0.3 million, and is reflected in gain on extinguishment of debt in the Company’s Consolidated Statements of Operations for the year ended December 31, 2019.
The Company has the option to settle conversions of these notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. Prior to March 15, 2023, the Senior Convertible Notes will be convertible only under the following circumstances: (i) during any calendar quarter commencing after the calendar quarter ending on September 30, 2016 (and only during such calendar quarter), if the last reported sale price of the Company’s common stock for at least 20 trading days (whether or not consecutive) during the period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter is greater than or equal to 130% of the conversion price on each applicable trading day; (ii) during the five business day period after any five consecutive trading day period (the “Measurement Period”) in which the trading price per $1,000 principal amount of the Senior Convertible Notes for each trading day of the Measurement Period is less than 98% of the product of the last reported sale price of the Company’s common stock and the conversion rate on each such trading day; or (iii) upon the occurrence of specified corporate events, including certain distributions or a fundamental change. On or after March 15, 2023, the Senior Convertible Notes will be convertible at any time until the second scheduled trading day immediately preceding their September 15, 2023 maturity date. The Senior Convertible Notes will be convertible at an initial conversion rate of 76.3650 shares of the Company’s common stock per $1,000 principal amount of the Senior Convertible Notes, which is equivalent to an initial conversion price of approximately $13.10. The conversion rate will be subject to adjustment in some events but will not be adjusted for any accrued and unpaid interest. In addition, following certain corporate events that occur prior to the maturity date or a notice of redemption, the Company will increase the conversion rate for a holder who elects to convert its Senior Convertible Notes in connection with such corporate event or redemption in certain circumstances. As of December 31, 2019, none of the contingent conditions allowing holders of the Senior Convertible Notes to convert these notes had been met. In addition, the Company was in compliance with the terms of the indentures for the Senior Convertible Notes as of December 31, 2019.
Interest on the Senior Notes and the Senior Convertible Notes (collectively, the “Notes”) is payable semi-annually in arrears. The Notes are guaranteed on a senior unsecured basis by the Company, along with its material subsidiaries (the “Guarantors”), which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors, subject to certain customary release provisions. The indentures governing the Notes contain customary events of default.
122
Subsequent to December 31, 2019, the Company repurchased a principal amount of $27.9 million of its outstanding Notes, for an aggregate cost of $22.2 million, including accrued interest, which will be reflected in the Company’s Consolidated Financial Statements subsequent to the year ended December 31, 2019.
Deferred financing costs. As of December 31, 2019, the Company had $22.9 million of deferred financing costs related to the Notes and the Revolving Credit Facilities. Deferred financing costs of $15.6 million related to the Notes are included in long-term debt on the Company’s Consolidated Balance Sheets as of December 31, 2019, and are being amortized over the respective terms of the Notes. Deferred financing costs of $4.8 million and $2.5 million related to the Oasis Credit Facility and OMP Credit Facility, respectively, are included in other assets on the Company’s Consolidated Balance Sheets at December 31, 2019, and are being amortized over the term of the Oasis Credit Facility and the OMP Credit Facility. Amortization of deferred financing costs recorded for the year ended December 31, 2019, 2018 and 2017 was $7.3 million, $7.6 million and $7.0 million, respectively. These costs are included in interest expense on the Company’s Consolidated Statements of Operations. For the year ended December 31, 2019, the Company’s interest expense also included $1.6 million for unamortized deferred financing costs related to the Oasis Credit Facility and the OMP Credit Facility, which were written off in proportion to the decrease in the borrowing base. For the year ended December 31, 2018, the Company’s interest expense also included $0.3 million for unamortized deferred financing costs related to the Oasis Credit Facility, which were written off in proportion to the two lenders leaving the bank group. No deferred financing costs related to the Revolving Credit Facilities were written off during the year ended December 31, 2017. Aforementioned, the gain (loss) on extinguishment of debt in the Company’s Consolidated Statements of Operations included unamortized deferred financing costs write-offs of $0.5 million and $4.0 million related to the repurchased Notes for the years ended December 31, 2019 and 2018, respectively. No deferred financing costs related to the Notes were written off during the year ended December 31, 2017.
14. Asset Retirement Obligations
The following table reflects the changes in the Company’s ARO during the years ended December 31, 2019 and 2018:
| Year Ended December 31, | |||||||||||||||||
| 2019 | 2018 | ||||||||||||||||
| (In thousands) | |||||||||||||||||
| Asset retirement obligation — beginning of period | $ | 52,449 | $ | 48,799 | |||||||||||||
|
Liabilities incurred during period(1)
|
1,519 | 5,854 | |||||||||||||||
|
Liabilities settled during period(2)
|
(770) | (4,944) | |||||||||||||||
|
Accretion expense during period(1)(3)
|
2,939 | 2,657 | |||||||||||||||
| Revisions to estimates | 647 | 83 | |||||||||||||||
| Asset retirement obligation — end of period | $ | 56,784 | $ | 52,449 | |||||||||||||
__________________
(1)Includes costs for wells acquired in the Permian Basin Acquisition (see Note 10—Acquisitions) as of December 31, 2018.
(2)Liabilities settled during the years ended December 31, 2019 and 2018 included ARO related to sold properties (see Note 11—Divestitures).
(3)Included in depreciation, depletion and amortization on the Company’s Consolidated Statements of Operations.
At December 31, 2019 and 2018, the current portion of the total ARO balance was approximately $0.5 million and $0.1 million, respectively, and is included in accrued liabilities on the Company’s Consolidated Balance Sheets.
123
15. Income Taxes
The Company’s income tax benefit consists of the following:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Current: | |||||||||||||||||||||||||||||
| Federal | $ | (43) | $ | (70) | $ | (420) | |||||||||||||||||||||||
| State | 27 | 93 | — | ||||||||||||||||||||||||||
| (16) | 23 | (420) | |||||||||||||||||||||||||||
| Deferred: | |||||||||||||||||||||||||||||
| Federal | (28,148) | (3,553) | (199,370) | ||||||||||||||||||||||||||
| State | (4,551) | (2,313) | (3,514) | ||||||||||||||||||||||||||
| (32,699) | (5,866) | (202,884) | |||||||||||||||||||||||||||
| Total income tax benefit | $ | (32,715) | $ | (5,843) | $ | (203,304) | |||||||||||||||||||||||
The reconciliation of income taxes calculated at the U.S. federal tax statutory rate to the Company’s effective tax rate for the years ended December 31, 2019, 2018 and 2017, is set forth below:
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (%) | (In thousands) | (%) | (In thousands) | (%) | (In thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. federal tax statutory rate | 21.00 | % | $ | (25,906) | 21.00 | % | $ | (5,322) | 35.00 | % | $ | (26,550) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| State income taxes, net of federal income tax benefit | 2.90 | % | (3,573) | 2.08 | % | (527) | 2.59 | % | (1,966) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Effects of non-controlling interest | 6.40 | % | (7,895) | 13.09 | % | (3,317) | 1.68 | % | (1,278) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Non-deductible executive compensation | (1.70) | % | 2,094 | (9.50) | % | 2,408 | 1.05 | % | (792) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation windfall (shortfall) | (1.75) | % | 2,163 | (3.68) | % | 932 | 0.87 | % | (659) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| State deferred tax rate change | — | % | — | 13.73 | % | (3,479) | 0.36 | % | (270) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Change in valuation allowance | — | % | — | (6.74) | % | 1,707 | — | % | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Impact of U.S. tax reform | — | % | — | (7.34) | % | 1,859 | 226.61 | % | (171,900) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | (0.33) | % | 402 | 0.41 | % | (104) | (0.15) | % | 111 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Annual effective tax benefit | 26.52 | % | $ | (32,715) | 23.05 | % | $ | (5,843) | 268.01 | % | $ | (203,304) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
124
Significant components of the Company’s deferred tax assets and liabilities as of December 31, 2019 and 2018, were as follows:
| Year Ended December 31, | |||||||||||||||||
| 2019 | 2018 | ||||||||||||||||
| (In thousands) | |||||||||||||||||
| Deferred tax assets | |||||||||||||||||
| Net operating loss carryforward | $ | 191,022 | $ | 177,745 | |||||||||||||
| Bonus and equity-based compensation | 8,799 | 8,436 | |||||||||||||||
| Derivative instruments | 3,946 | — | |||||||||||||||
| Other tax attribute carryovers | 1,643 | 856 | |||||||||||||||
| Total deferred tax assets | 205,410 | 187,037 | |||||||||||||||
| Less: Valuation allowance | (2,915) | (2,863) | |||||||||||||||
| Total deferred tax assets, net | $ | 202,495 | $ | 184,174 | |||||||||||||
| Deferred tax liabilities | |||||||||||||||||
| Oil and gas properties | $ | 426,130 | $ | 423,270 | |||||||||||||
| Derivative instruments | — | 22,834 | |||||||||||||||
| Investment in partnerships | 38,015 | 22,450 | |||||||||||||||
| Other deferred tax liabilities | 5,707 | 15,675 | |||||||||||||||
| Total deferred tax liabilities | $ | 469,852 | $ | 484,229 | |||||||||||||
| Total deferred tax liabilities, net | $ | 267,357 | $ | 300,055 | |||||||||||||
As of December 31, 2019, the Company had federal net operating loss carryforwards of $800.5 million, which expire between 2030 and 2039, and $642.0 million of state net operating loss carryforwards, which expire between 2020 and 2039. The tax benefits of carryforwards are recorded as an asset to the extent that management assesses the utilization of such carryforwards to be more likely than not, and when the future utilization of some portion of the carryforwards is determined not to be more likely than not a valuation allowance is provided to reduce the recorded tax benefits from such assets. As of December 31, 2019 and 2018, the Company’s valuation allowance balance was $2.9 million for both years, against Montana net operating loss carryforwards and certain other tax attribute carryforwards as the benefit for those attributes is not expected to be realized prior to their expiration due to their short carryover periods, current economic conditions and expectations for the future. No valuation allowances are required for U.S. federal and North Dakota tax net operating loss carryforwards as they are expected to be fully utilized before their expiration.
Due to the adoption of ASU 2016-09, unrealized excess tax benefits of $10.6 million were realized in the cumulative-effect adjustment to retained earnings on the Company’s Condensed Consolidated Balance Sheet in the first quarter of 2017 and increased the deferred tax asset.
Accounting for uncertainty in income taxes prescribes a recognition threshold and measurement methodology for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. As of December 31, 2019 and 2018, the Company had no unrecognized tax benefits. With respect to income taxes, the Company’s policy is to account for interest charges as interest expense and any penalties as tax expense in its Consolidated Statements of Operations. The Company files income tax returns in the U.S. federal jurisdiction and in North Dakota, Montana and Texas. The statute of limitation for the year ended December 31, 2019 will expire in 2023. The Company’s earliest open year in its key jurisdictions is 2016 for both the U.S. federal jurisdiction and various U.S. states, however, net operating losses originating in 2010 and all subsequent periods are subject to examination when utilized.
16. Equity-Based Compensation
The Company has granted equity awards to its officers, employees and directors under the Amended and Restated 2010 Long Term Incentive Plan. The maximum number of shares available for grant under the Amended and Restated 2010 Long Term Incentive Plan is 16,050,000.
Restricted stock awards. The Company has granted restricted stock awards to its employees and directors under its Amended and Restated 2010 Long Term Incentive Plan, the majority of which vest over a three-year period. The fair value of restricted stock grants is based on the closing sales price of the Company’s common stock on the date of grant or, if applicable, the date of modification. Compensation expense is recognized ratably over the requisite service period.
125
The following table summarizes information related to restricted stock held by the Company’s employees and directors for the periods presented:
| Shares |
Weighted Average
Grant Date Fair Value per Share |
||||||||||
| Non-vested shares outstanding December 31, 2018 | 5,136,556 | $ | 10.81 | ||||||||
| Granted | 4,059,225 | 6.61 | |||||||||
| Vested | (2,656,483) | 9.52 | |||||||||
| Forfeited | (803,131) | 8.42 | |||||||||
| Non-vested shares outstanding December 31, 2019 | 5,736,167 | $ | 8.77 | ||||||||
Equity-based compensation expense recorded for restricted stock awards was $24.0 million, $20.1 million and $19.5 million for each of the years ended December 31, 2019, 2018 and 2017, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of awards vested was $14.6 million, $17.3 million and $22.0 million for the years ended December 31, 2019, 2018 and 2017, respectively. The weighted average grant date fair value of restricted stock awards granted was $6.61 per share, $10.20 per share and $15.03 per share for the years ended December 31, 2019, 2018 and 2017, respectively. Unrecognized expense as of December 31, 2019 for all outstanding restricted stock awards was $27.0 million and will be recognized over a weighted average period of 1.7 years.
Performance share units. The Company has granted PSUs to its officers under its Amended and Restated 2010 Long Term Incentive Plan. The PSUs are awards of restricted stock units that may be earned based on the level of achievement with respect to the applicable performance metric, and each PSU that is earned represents the right to receive one share of the Company’s common stock.
The Company accounted for the PSUs as equity awards pursuant to the FASB’s authoritative guidance for share-based payments. The number of PSUs to be earned is subject to a market condition, which is based on a comparison of the total shareholder return (“TSR”) achieved with respect to shares of the Company’s common stock against the TSR achieved by a defined peer group at the end of the performance periods. Depending on the Company’s TSR performance relative to the defined peer group, award recipients will earn between 0% and 200% of the initial PSUs granted. All compensation expense related to the PSUs will be recognized if the requisite performance period is fulfilled, even if the market condition is not achieved.
The following table summarizes information related to PSUs held by the Company’s officers for the periods presented:
| Units |
Weighted Average
Grant Date Fair Value per Unit |
||||||||||
| Non-vested PSUs at December 31, 2018 | 2,032,212 | $ | 10.94 | ||||||||
| Granted | 1,685,090 | 6.80 | |||||||||
| Vested | (423,953) | 7.45 | |||||||||
| Forfeited | (266,125) | 10.97 | |||||||||
| Non-vested PSUs at December 31, 2019 | 3,027,224 | $ | 9.12 | ||||||||
Equity-based compensation expense recorded for PSUs for the years ended December 31, 2019, 2018 and 2017 was $9.0 million, $8.5 million and $6.7 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of PSUs vested was $2.6 million and $5.3 million for the years ended December 31, 2019 and 2018, respectively. No PSUs vested during the year ended December 31, 2017. The weighted average grant date fair value of PSUs granted was $6.80 per share, $12.71 per share and $16.89 per share for the years ended December 31, 2019, 2018 and 2017, respectively. Unrecognized expense as of December 31, 2019 for all outstanding PSUs was $10.9 million and will be recognized over a weighted average period of 2.6 years.
The aggregate grant date fair value of the market-based awards was determined using a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding random projections and must be repeated numerous times to achieve a probabilistic assessment. The key valuation assumptions for the Monte Carlo model are the forecast period, risk-free interest rates, stock price volatility, initial value, stock price on the date of grant and correlation coefficients. The risk-free interest rates are the U.S. Treasury bond rates on the date of grant that corresponds to the each performance period. The initial value is the average of the volume weighted average prices for the 30 trading days prior to the start of the performance cycle for the Company and each of its peers. Volatility is the standard deviation of the average percentage change in stock price over a historical period for the Company and each of its peers. The correlation coefficients are measures of the strength of the linear relationship between and amongst the Company and its peers estimated based on historical stock price data.
126
The following assumptions were used for the Monte Carlo model to determine the grant date fair value and associated equity-based compensation expense of the PSUs granted during the periods presented:
| 2019 | 2018 | 2017 | |||||||||||||||
| Forecast period (years) |
2 - 4
|
2 - 4
|
2 - 4
|
||||||||||||||
| Risk-free interest rates |
2.55% - 2.56%
|
2.08% - 2.31%
|
1.18% - 1.66%
|
||||||||||||||
| Oasis stock price volatility | 71.17 | % | 72.88 | % | 17.16 | % | |||||||||||
| Oasis initial value | $ | 5.85 | $ | 8.82 | $ | 15.64 | |||||||||||
| Oasis stock price on date of grant | $ | 6.63 | $ | 9.27 | $ | 15.21 | |||||||||||
Associated tax benefit. For the years ended December 31, 2019, 2018 and 2017, the Company had an associated tax benefit of $7.8 million, $6.8 million and $6.3 million, respectively, related to all equity-based compensation.
OMP phantom unit awards. The Company has granted OMP Phantom Unit Awards to its employees under its Amended and Restated 2010 Long Term Incentive Plan in 2018 and 2019, and OMP granted OMP Phantom Unit Awards to employees of the Company under the OMP LTIP in 2017.
As of December 31, 2019, the aggregate number of common units that may be issued pursuant to any and all awards under the OMP LTIP is equal to 2,455,408 common units, subject to adjustment due to recapitalization or reorganization, or related to forfeitures or expiration of awards, as provided under the OMP LTIP. On January 1 of each calendar year following the adoption and prior to the expiration of the OMP LTIP, the total number of common units that may be issued pursuant to the OMP LTIP automatically increases by a number of common units equal to one percent of the number of common units outstanding on a fully diluted basis as of the close of business on the immediately preceding December 31 (calculated by adding to the number of common units outstanding, all outstanding securities convertible into common units on such date on an as converted basis). As a result of this adjustment, an additional 337,952 common units were reserved for issuance pursuant to awards under the OMP LTIP on January 1, 2020.
Each OMP Phantom Unit represents the right to receive, upon vesting of the award, a cash payment equal to the fair market value of one OMP common unit on the day prior to the date it vests (the “Vesting Date”). Award recipients are also entitled to Distribution Equivalent Rights (“DER”) with respect to each OMP Phantom Unit received. Each DER represents the right to receive, upon vesting of the award, a cash payment equal to the value of the distributions paid on one OMP common unit between the Grant Date and the applicable Vesting Date. The OMP Phantom Unit Awards generally vest in equal installments each year over a three-year period from the date of grant, and compensation expense will be recognized over the requisite service period and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations.
The OMP Phantom Unit Awards are accounted for as liability-classified awards since the awards will settle in cash, and equity-based compensation expense is accounted for under the fair value method in accordance with GAAP. Under the fair value method for liability-classified awards, compensation expense is remeasured each reporting period at fair value based upon the closing price of a publicly traded common unit. The Company will directly pay, or will reimburse OMP, for the cash settlement amount of these awards.
The following table summarizes information related to OMP Phantom Unit Awards held by certain employees of Oasis for the periods presented:
| Phantom Units | Weighted Average Grant Date Fair Value per Unit | ||||||||||
| Non-vested units outstanding December 31, 2018 | 143,089 | $ | 20.85 | ||||||||
| Granted | 341,290 | 18.57 | |||||||||
| Vested | (46,334) | 20.33 | |||||||||
| Forfeited | (76,043) | 19.30 | |||||||||
| Non-vested units outstanding December 31, 2019 | 362,002 | $ | 19.09 | ||||||||
Equity-based compensation expense recorded for the OMP Phantom Unit Awards for the years ended December 31, 2019, 2018 and 2017 was $2.5 million, $0.5 million and $0.1 million, respectively. The fair value of OMP Phantom Unit Awards vested was $0.8 million and $0.6 million for the years ended December 31, 2019 and 2018, respectively. No OMP Phantom Unit Awards vested during the year ended December 31, 2017. For the years ended December 31, 2019, 2018 and 2017, the weighted average grant date fair value of OMP Phantom Unit Awards granted was $18.57 per unit, $23.91 per unit and $16.40 per unit, respectively. As of December 31, 2019, unrecognized compensation cost for all outstanding OMP Phantom Unit Awards was $4.3 million, which is expected to be recognized over a weighted average period of 2.0 years.
127
OMP restricted unit awards. OMP has granted to independent directors of the general partner restricted unit awards under the OMP LTIP, which vest over a one-year period from the date of grant. These awards are accounted for as equity-classified awards since the awards will settle in common units upon vesting. Equity-based compensation expense is accounted for under the fair value method in accordance with GAAP. Under the fair value method for equity-classified awards, equity-based compensation expense is measured at the grant date based on the fair value of the award and is recognized over the vesting period.
The following table summarizes information related to restricted units held by certain directors of OMP for the periods presented:
| Restricted Units | Weighted Average Grant Date Fair Value per Unit | ||||||||||
| Non-vested units outstanding December 31, 2018 | 17,260 | $ | 17.55 | ||||||||
| Granted | 16,170 | 18.57 | |||||||||
| Vested | (17,260) | 17.55 | |||||||||
| Forfeited | — | — | |||||||||
| Non-vested units outstanding December 31, 2019 | 16,170 | $ | 18.57 | ||||||||
Equity-based compensation expense recorded for OMP restricted unit awards the years ended December 31, 2019, 2018 and 2017 was $0.4 million, $0.4 million and $0.1 million, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations. The fair value of OMP restricted unit awards vested was $0.3 million for the years ended December 31, 2019 and 2018, respectively. No OMP restricted unit awards vested during the year ended December 31, 2017. The weighted average grant date fair value of OMP restricted stock awards granted was $18.57 per unit, $17.55 per unit and $17.00 per unit for the years ended December 31, 2019, 2018 and 2017, respectively. Unrecognized expense as of December 31, 2019 for all outstanding OMP restricted unit awards was $0.01 million, and will be recognized over a weighted average period of 0.1 years.
Class B units in OMP GP. In May 2017, OMP GP granted restricted Class B Units to certain employees, including OMP’s executive officers, as consideration for services to Oasis, which vest over a ten-year period. The restricted Class B Units represent 9% of the outstanding units of OMP GP as of December 31, 2019. Compensation expense is recognized ratably over the requisite service period. Equity-based compensation expense recorded for the Class B Units was $0.2 million, $0.3 million and $0.2 million for the years ended December 31, 2019, 2018 and 2017, respectively, and is included in general and administrative expenses on the Company’s Consolidated Statements of Operations.
17. Common Stock
Dividends. The Company has not paid any cash dividends since its inception. Covenants contained in the Revolving Credit Facilities and the indentures governing the Company’s Senior Notes restrict the payment of cash dividends on its common stock. The Company currently intends to retain all future earnings for the development of its business, and the Company does not anticipate declaring or paying any cash dividends to holders of its common stock in the foreseeable future.
18. Earnings (Loss) Per Share
Basic earnings (loss) per share is computed by dividing the earnings (loss) attributable to Oasis common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings (loss) per share includes the potential dilutive impact of unvested restricted stock awards, contingently issuable shares related to PSUs and senior convertible notes during the periods presented, unless their effect is anti-dilutive. There are no adjustments made to income (loss) attributable to Oasis available to common stockholders in the calculation of diluted earnings (loss) per share.
The following is a calculation of the basic and diluted weighted average shares outstanding for the periods presented:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Basic weighted average common shares outstanding | 315,002 | 307,480 | 234,986 | ||||||||||||||||||||||||||
|
Dilutive effect of restricted stock awards and PSUs(1)
|
— | — | 2,889 | ||||||||||||||||||||||||||
| Diluted weighted average common shares outstanding | 315,002 | 307,480 | 237,875 | ||||||||||||||||||||||||||
__________________
(1)No unvested stock awards were included in computing loss per share for the years ended December 31, 2019 and 2018 because the effect was anti-dilutive.
128
During the years ended December 31, 2019 and 2018, the Company incurred a net loss, and therefore the diluted loss per share calculation for those periods excludes the anti-dilutive effect of unvested stock awards. In addition, the diluted earnings per share calculation for the year ended December 31, 2017 excludes the dilutive effect of unvested stock awards that were anti-dilutive under the treasury stock method. The following is a calculation of weighted average common shares excluded from diluted earnings (loss) per share due to the anti-dilutive effect:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Restricted stock awards and PSUs | 9,242 | 6,980 | 2,881 | ||||||||||||||||||||||||||
The Company issued its Senior Convertible Notes in September 2016 (see Note 13—Long-Term Debt). The Company has the option to settle conversions of its Senior Convertible Notes with cash, shares of common stock or a combination of cash and common stock at its election. The Company’s intent is to settle the principal amount of the Senior Convertible Notes in cash upon conversion. As a result, only the amount by which the conversion value exceeds the aggregate principal amount of the notes (conversion spread) is considered in the diluted earnings per share computation under the treasury stock method. As of December 31, 2019, 2018 and 2017, the conversion value did not exceed the principal amount of the notes, and accordingly, there was no impact to diluted earnings per share for years ended December 31, 2019, 2018 and 2017.
19. Business Segment Information
As of December 31, 2019, the Company had three reportable segments: exploration and production, midstream and well services. The Company’s exploration and production segment is engaged in the acquisition and development of oil and gas properties. Revenues for the exploration and production segment are derived from the sale of crude oil and natural gas production. The Company’s midstream segment performs produced and flowback water gathering and disposal services, fresh water services, natural gas gathering and processing and crude oil gathering and transportation and other midstream services for crude oil and natural gas wells operated by the Company as well as third-party operated wells. The Company’s well services segment generates revenue from well completion services, product sales and equipment rentals for the Company’s crude oil and natural gas wells. In conjunction with its planned Well Services Exit in the first quarter of 2020, the Company expects to eliminate its well services segment and report the remaining equipment rentals activity within its exploration and production segment. The revenues and expenses related to work performed by OMP, OMS and OWS for the Company’s ownership interests are eliminated in consolidation, and only the revenues and expenses related to non-affiliated owners are included in the Company’s Consolidated Statements of Operations. The Company’s corporate activities have been allocated to the supported business segments accordingly. Management evaluates the performance of the Company’s business segments based on operating income, which is defined as segment operating revenues less operating expenses, including depreciation, depletion and amortization (“DD&A”).
129
The following table summarizes financial information for the Company’s three business segments for the periods presented:
|
Exploration and
Production
|
Midstream | Well Services | Eliminations | Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenues from external customers | $ | 1,817,532 | $ | 212,238 | $ | 41,974 | $ | — | $ | 2,071,744 | |||||||||||||||||||||||||||||||||||||||||||
| Inter-segment revenues | — | 276,189 | 79,686 | (355,875) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total revenues | 1,817,532 | 488,427 | 121,660 | (355,875) | 2,071,744 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss) | (71,191) | 241,161 | (2,024) | (13,523) | 154,423 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense), net | (260,878) | (17,065) | 158 | — | (277,785) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes including non-controlling interests | $ | (332,069) | $ | 224,096 | $ | (1,866) | $ | (13,523) | $ | (123,362) | |||||||||||||||||||||||||||||||||||||||||||
|
Total assets(1)
|
$ | 6,567,735 | $ | 1,101,401 | $ | 25,866 | $ | (195,749) | $ | 7,499,253 | |||||||||||||||||||||||||||||||||||||||||||
| Property, plant and equipment, net | 6,127,952 | 1,078,903 | 1,670 | (230,749) | 6,977,776 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Capital expenditures(2)
|
644,798 | 212,381 | 282 | (14,093) | 843,368 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 766,959 | 37,152 | 13,631 | (30,550) | 787,192 | ||||||||||||||||||||||||||||||||||||||||||||||||
| General and administrative | 118,701 | 31,737 | 26,233 | (33,165) | 143,506 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 32,251 | 1,744 | 1,397 | (1,785) | 33,607 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment | 5,856 | — | 4,401 | — | 10,257 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenues from external customers | $ | 2,136,735 | $ | 124,137 | $ | 61,075 | $ | — | $ | 2,321,947 | |||||||||||||||||||||||||||||||||||||||||||
| Inter-segment revenues | — | 162,505 | 144,544 | (307,049) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total revenues | 2,136,735 | 286,642 | 205,619 | (307,049) | 2,321,947 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss) | (25,027) | 143,126 | 30,988 | (30,075) | 119,012 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense), net | (142,265) | (2,125) | 35 | — | (144,355) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes including non-controlling interests | $ | (167,292) | $ | 141,001 | $ | 31,023 | $ | (30,075) | $ | (25,343) | |||||||||||||||||||||||||||||||||||||||||||
|
Total assets(1)
|
$ | 6,838,987 | $ | 920,619 | $ | 48,150 | $ | (181,614) | $ | 7,626,142 | |||||||||||||||||||||||||||||||||||||||||||
| Property, plant and equipment, net | 6,311,566 | 893,285 | 38,871 | (216,613) | 7,027,109 | ||||||||||||||||||||||||||||||||||||||||||||||||
|
Capital expenditures(2)
|
1,948,076 | 277,626 | 7,831 | (30,080) | 2,203,453 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 618,402 | 29,282 | 15,698 | (27,086) | 636,296 | ||||||||||||||||||||||||||||||||||||||||||||||||
| General and administrative | 102,482 | 24,700 | 23,282 | (29,118) | 121,346 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation | 27,910 | 1,547 | 1,588 | (1,772) | 29,273 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment | 384,228 | — | — | — | 384,228 | ||||||||||||||||||||||||||||||||||||||||||||||||
130
| Year Ended December 31, 2017 | |||||||||||||||||||||||||||||
| Revenues from external customers | $ | 1,168,176 | $ | 72,752 | $ | 52,791 | $ | — | $ | 1,293,719 | |||||||||||||||||||
| Inter-segment revenues | — | 113,047 | 95,345 | (208,392) | — | ||||||||||||||||||||||||
| Total revenues | 1,168,176 | 185,799 | 148,136 | (208,392) | 1,293,719 | ||||||||||||||||||||||||
| Operating income | 40,694 | 102,377 | 15,057 | (14,160) | 143,968 | ||||||||||||||||||||||||
| Other income (expense) | (219,823) | (37) | 34 | — | (219,826) | ||||||||||||||||||||||||
| Income (loss) before income taxes including non-controlling interests | $ | (179,129) | $ | 102,340 | $ | 15,091 | $ | (14,160) | $ | (75,858) | |||||||||||||||||||
|
Total assets(1)
|
$ | 6,058,054 | $ | 663,614 | $ | 52,800 | $ | (151,539) | $ | 6,622,929 | |||||||||||||||||||
| Property, plant and equipment, net | 5,663,323 | 649,923 | 46,779 | (186,539) | 6,173,486 | ||||||||||||||||||||||||
|
Capital expenditures(2)
|
602,734 | 235,090 | 12,537 | (14,157) | 836,204 | ||||||||||||||||||||||||
| Depreciation, depletion and amortization | 519,853 | 15,999 | 12,939 | (17,989) | 530,802 | ||||||||||||||||||||||||
| General and administrative | 77,560 | 19,583 | 24,359 | (29,705) | 91,797 | ||||||||||||||||||||||||
| Equity-based compensation | 25,436 | 1,461 | 1,264 | (1,627) | 26,534 | ||||||||||||||||||||||||
| Impairment | 6,887 | — | — | — | 6,887 | ||||||||||||||||||||||||
__________________
(1)Intercompany receivables (payables) for all segments were reclassified to capital contributions from (distributions to) parent and not included in total assets.
(2)Capital expenditures reflected in the table above differ from the amounts for capital expenditures and acquisitions of oil and gas properties shown in the Company’s Consolidated Statements of Cash Flows because amounts reflected in the table include changes in accrued liabilities from the previous reporting period for capital expenditures, while the amounts presented in the Consolidated Statements of Cash Flows are presented on a cash basis. Acquisitions totaled $21.0 million, $951.9 million and $54.0 million for the years ended December 31, 2019, 2018 and 2017, respectively, in the exploration and production segment. Additionally, capital expenditures reflected in the table includes consideration paid through the issuance of common stock in connection with the Permian Basin Acquisition for the year ended December 31, 2018.
20. Leases
As discussed in Note 2 — Summary of Significant Accounting Policies, the Company adopted ASC 842 as of January 1, 2019 using the modified retrospective method, which resulted in the Company recognizing operating lease ROU assets and lease liabilities of $31.1 million and $37.1 million, respectively. In addition, the Company recognized offsetting finance lease ROU assets and lease liabilities of $6.0 million. There was no impact to the opening equity balance as a result of adoption as the difference between the asset and liability balance is attributable to reclassifications of pre-existing balances, such as deferred rent, into the lease asset balance. Prior period amounts are not adjusted and continue to be reported in accordance with the previous guidance, Accounting Standards Codification 840 (“ASC 840”).
In accordance with the adoption of ASC 842, management determines whether an arrangement is a lease at its inception. The Company’s operating and finance leases consist primarily of office space, drilling rigs, vehicles and other property and equipment used in its operations. The operating lease ROU asset also includes any lease incentives received in the recognition of the present value of future lease payments. The Company considers renewal and termination options in determining the lease term used to establish its ROU assets and lease liabilities to the extent the Company is reasonably certain to exercise the renewal or termination. The Company’s lease agreements do not contain any material residual value guarantees or material restrictive covenants.
As most of the Company’s leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of future lease payments. The Company has determined their respective incremental borrowing rates based upon the rate of interest that would have been paid on a collateralized basis over similar tenors to that of the leases.
131
The Company’s components of lease costs were as follows:
| Year Ended December 31, 2019 | |||||||||||||||||
| (In thousands) | |||||||||||||||||
| Operating lease costs | $ | 26,341 | |||||||||||||||
|
Variable lease costs(1)
|
9,189 | ||||||||||||||||
| Short-term lease costs | 4,657 | ||||||||||||||||
| Finance lease costs: | |||||||||||||||||
| Amortization of ROU assets | 2,543 | ||||||||||||||||
| Interest on lease liabilities | 260 | ||||||||||||||||
| Total lease costs | $ | 42,990 | |||||||||||||||
___________________
(1)Based on payments made by the Company to lessors for the right to use an underlying asset that vary because of changes in circumstances occurring after the commencement date, other than the passage of time, such as property taxes, operating and maintenance costs, which do not depend on an index or rate.
The amounts disclosed herein include costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners.
The Company’s share of operating, variable and short-term lease costs are either capitalized and included in property, plant and equipment on the Company’s Consolidated Balance Sheets or are recognized in the Company’s Consolidated Statements of Operations in lease operating expenses, midstream expenses and general and administrative expenses, as applicable. The finance lease costs for the amortization of ROU assets and the interest on lease liabilities disclosed above are included in depreciation, depletion and amortization and interest expense, net of capitalized interest, respectively, on the Company’s Consolidated Statements of Operations.
For the years ended December 31, 2018 and December 31, 2017, the Company had operating leases for office space and other property and equipment used in its operations, which it accounted for as operating leases in accordance with GAAP under ASC 840. For the years ended December 31, 2018 and December 31, 2017, the Company incurred operating rental expenses of $10.6 million and $6.9 million, respectively, which were included in general and administrative expenses on its Consolidated Statements of Operations.
As of December 31, 2019, maturities of the Company’s lease liabilities were as follows:
| Operating Leases | Finance Leases | ||||||||||||||||
| (In thousands) | |||||||||||||||||
| 2020 | $ | 7,001 | $ | 2,585 | |||||||||||||
| 2021 | 2,704 | 2,038 | |||||||||||||||
| 2022 | 3,073 | 1,367 | |||||||||||||||
| 2023 | 2,365 | 274 | |||||||||||||||
| 2024 | 2,362 | 45 | |||||||||||||||
| Thereafter | 10,440 | 639 | |||||||||||||||
| Total future lease payments | 27,945 | 6,948 | |||||||||||||||
| Less: Imputed interest | 3,848 | 578 | |||||||||||||||
| Present value of future lease payments | $ | 24,097 | $ | 6,370 | |||||||||||||
132
As of December 31, 2018, future minimum annual rental commitments under non-cancelable leases under ASC 840 were as follows:
| (In thousands) | |||||
| 2019 | $ | 8,723 | |||
| 2020 | 7,009 | ||||
| 2021 | 6,005 | ||||
| 2022 | 5,130 | ||||
| 2023 | 4,361 | ||||
| Thereafter | 13,134 | ||||
| Total future minimum lease payments | $ | 44,362 | |||
Supplemental balance sheet information related to the Company’s leases were as follows:
| Balance Sheet Location | December 31, 2019 | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Assets | ||||||||||||||||||||
| Operating lease assets | Operating right-of-use assets | $ | 18,497 | |||||||||||||||||
|
Finance lease assets(1)
|
Other assets | 6,303 | ||||||||||||||||||
| Total lease assets | $ | 24,800 | ||||||||||||||||||
| Liabilities | ||||||||||||||||||||
| Current | ||||||||||||||||||||
| Operating lease liabilities | Current operating lease liabilities | $ | 6,182 | |||||||||||||||||
| Finance lease liabilities | Other current liabilities | 2,413 | ||||||||||||||||||
| Long-term | ||||||||||||||||||||
| Operating lease liabilities | Operating lease liabilities | 17,915 | ||||||||||||||||||
| Finance lease liabilities | Other liabilities | 3,958 | ||||||||||||||||||
| Total lease liabilities | $ | 30,468 | ||||||||||||||||||
___________________
(1)Finance lease ROU assets are recorded net of accumulated amortization of $2.3 million as of December 31, 2019.
Supplemental cash flow information and non-cash transactions related to the Company’s leases were as follows:
| December 31, 2019 | |||||||||||
| (In thousands) | |||||||||||
| Cash paid for amounts included in the measurement of lease liabilities | |||||||||||
| Operating cash flows from operating leases | $ | 30,316 | |||||||||
| Operating cash flows from finance leases | 260 | ||||||||||
| Financing cash flows from finance leases | 2,382 | ||||||||||
| ROU assets obtained in exchange for lease obligations | |||||||||||
| Operating leases | $ | 12,746 | |||||||||
| Finance leases | 3,433 | ||||||||||
Weighted-average remaining lease terms and discount rates for the Company’s leases were as follows:
| As of December 31, 2019 | |||||||||||
| Operating Leases | |||||||||||
| Weighted average remaining lease term | 7.1 years | ||||||||||
| Weighted average discount rate | 4.1 | % | |||||||||
| Finance Leases | |||||||||||
| Weighted average remaining lease term | 4.1 years | ||||||||||
| Weighted average discount rate | 3.9 | % | |||||||||
133
21. Significant Concentrations
Major customers. For the year ended December 31, 2019, sales to Phillips 66 Company accounted for approximately 14% of the Company’s total sales. For the year ended December 31, 2018, no purchaser accounted for more than 10% of the Company’s total sales. For the year ended December 31, 2017, sales to Shell Trading (US) Company accounted for approximately 16% of the Company’s total sales. No other purchasers accounted for more than 10% of the Company’s total sales for the years ended December 31, 2019 and 2017. Total sales include revenues from the Company’s exploration and production segment only, as OMS and OWS provide services to OPNA.
Substantially all of the Company’s accounts receivable result from sales of crude oil, natural gas and NGLs as well as joint interest billings (“JIB”) to third-party companies who have working interest payment obligations in projects completed by the Company. This concentration of customers and joint interest owners may impact the Company’s overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions, including the current downturn in crude oil prices. Management believes that the loss of any of these purchasers would not have a material adverse effect on the Company’s operations, as there are a number of alternative crude oil, natural gas and NGL purchasers in the Company’s producing regions.
22. Commitments and Contingencies
Included below is a discussion of various future commitments of the Company as of December 31, 2019. The commitments under these arrangements are not recorded in the accompanying Consolidated Balance Sheets. The amounts disclosed represent undiscounted cash flows on a gross basis and no inflation elements have been applied.
Volume commitment agreements. As of December 31, 2019, the Company had certain agreements with an aggregate requirement to deliver, transport or purchase a minimum quantity of approximately 34.9 MMBbl of crude oil, 35.0 MMBbl of NGLs, 827.6 Bcf of natural gas and 14.9 MMBbl of water, prior to any applicable volume credits, within specified timeframes, all of which are 25 years or less. These amounts are recognized as marketing, transportation and gathering expense in the Company’s Consolidated Statements of Operations. The future commitments under certain agreements cannot be estimated as they are based on fixed differentials relative to a commodity index price under the agreements as compared to the differential relative to a commodity index price for the production month.
The estimable future commitments under these volume commitment agreements as of December 31, 2019 are as follows:
| (In thousands) | |||||
| 2020 | $ | 82,515 | |||
| 2021 | 95,074 | ||||
| 2022 | 107,004 | ||||
| 2023 | 91,649 | ||||
| 2024 | 78,013 | ||||
| Thereafter | 140,282 | ||||
| $ | 594,537 | ||||
Subsequent to December 31, 2019, the Company entered into a new agreement to deliver additional volumes of water within a specified timeframe, which is ten years or less. The estimable future total commitment under this volume commitment agreement was approximately $3.8 million.
The Company enters into long-term contracts to provide production flow assurance in over-supplied basins and/or areas with limited infrastructure. This strategic tactic provides for optimization of transportation and processing costs. As properties are undergoing development activities, the Company may experience temporary delivery or transportation shortfalls until production volumes grow to meet or exceed the minimum volume commitments. The Company recognizes any monthly deficiency payments in the period in which the underdelivery takes place and the related liability has been incurred. The table above does not include any such deficiency payments that may be incurred under the Company’s physical delivery contracts, since it cannot be predicted with accuracy the amount and timing of any such penalties incurred.
Lease commitments. The Company has various operating and finance lease commitments that consists primarily of offices, drilling rigs, vehicles and other property and equipment used in its operations. See Note 20—Leases for additional information.
Litigation. The Company is party to various legal and/or regulatory proceedings from time to time arising in the ordinary course of business. When the Company determines that a loss is probable of occurring and is reasonably estimable, the Company accrues an undiscounted liability for such contingencies based on its best estimate using information available at the time. The Company discloses contingencies where an adverse outcome may be material, or in the judgment of management, the matter should otherwise be disclosed.
134
During the year ended December 31, 2019, a loss accrual was recorded in the amount of $20 million, which the Company believes is the estimable amount of loss that could potentially be incurred from its pending legal proceedings based upon currently available information. This amount was recognized in accrued liabilities in the Company’s Consolidated Balance Sheet and general and administrative expenses in the Company’s Consolidated Statements of Operations.
Mirada litigation. On March 23, 2017, Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively, “Mirada”) filed a lawsuit against Oasis, OPNA and OMS, seeking monetary damages in excess of $100 million, declaratory relief, attorneys’ fees and costs (Mirada Energy, LLC, et al. v. Oasis Petroleum North America LLC, et al.; in the 334th Judicial District Court of Harris County, Texas; Case Number 2017-19911). Mirada asserts that it is a working interest owner in certain acreage owned and operated by the Company in Wild Basin. Specifically, Mirada asserts that the Company has breached certain agreements by: (1) failing to allow Mirada to participate in the Company’s midstream operations in Wild Basin; (2) refusing to provide Mirada with information that Mirada contends is required under certain agreements and failing to provide information in a timely fashion; (3) failing to consult with Mirada and failing to obtain Mirada’s consent prior to drilling more than one well at a time in Wild Basin; and (4) overstating the estimated costs of proposed well operations in Wild Basin. Mirada seeks a declaratory judgment that the Company be removed as operator in Wild Basin at Mirada’s election and that Mirada be allowed to elect a new operator; certain agreements apply to the Company and Mirada and Wild Basin with respect to this dispute; the Company be required to provide all information within its possession regarding proposed or ongoing operations in Wild Basin; and the Company not be permitted to drill, or propose to drill, more than one well at a time in Wild Basin without obtaining Mirada’s consent. Mirada also seeks a declaratory judgment with respect to the Company’s current midstream operations in Wild Basin. Specifically, Mirada seeks a declaratory judgment that Mirada has a right to participate in the Company’s Wild Basin midstream operations, consisting of produced water disposal, crude oil gathering and natural gas gathering and processing; that, upon Mirada’s election to participate, Mirada is obligated to pay its proportionate costs of the Company’s midstream operations in Wild Basin; and that Mirada would then be entitled to receive a share of revenues from the midstream operations and would not be charged any amount for its use of these facilities for production from the “Contract Area.”
On June 30, 2017, Mirada amended its original petition to add a claim that the Company has breached certain agreements by charging Mirada for midstream services provided by its affiliates and to seek a declaratory judgment that Mirada is entitled to be paid its share of total proceeds from the sale of hydrocarbons received by OPNA or any affiliate of OPNA without deductions for midstream services provided by OPNA or its affiliates.
On February 2, 2018 and February 16, 2018, Mirada filed a second and third amended petition, respectively. In these filings, Mirada alleged new legal theories for being entitled to enforce the underlying contracts and added Bighorn DevCo, Bobcat DevCo and Beartooth DevCo as defendants, asserting that these entities were created in bad faith in an effort to avoid contractual obligations owed to Mirada.
On March 2, 2018, Mirada filed a fourth amended petition that described Mirada’s alleged ownership and assignment of interests in assets purportedly governed by agreements at issue in the lawsuit. On August 31, 2018, Mirada filed a fifth amended petition that added OMP as a defendant, asserting that it was created in bad faith in an effort to avoid contractual obligations owed to Mirada.
On July 2, 2019, Oasis, OPNA, OMS, OMP, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo LLC (collectively “Oasis Entities”) counterclaimed against Mirada for a judgment declaring that Oasis Entities are not obligated to purchase, manage, gather, transport, compress, process, market, sell or otherwise handle Mirada’s proportionate share of oil and gas produced from OPNA-operated wells. The counterclaim also seeks attorney’s fees, costs and expenses.
On November 1, 2019, Mirada filed a sixth amended petition that stated that Mirada seeks in excess of $200 million in damages and asserted that OMS is an agent of OPNA and OPNA, OMS, OMP, Bighorn DevCo, Bobcat DevCo and Beartooth DevCo LLC are agents of Oasis. Mirada also changed its allegation that it may elect a new operator for the subject wells to instead allege that Mirada may remove Oasis as operator.
On November 1, 2019, the Oasis Entities amended their counterclaim against Mirada for a judgment declaring that a provision in one of the agreements does not incorporate by reference any provisions in a certain participation agreement and joint operating agreement. The additional counterclaim also seeks attorney’s fees, costs and expenses. On the same day, the Oasis Entities filed an amended answer asserting additional defenses against Mirada’s claims.
The Company believes that Mirada’s claims are without merit, that the Company has complied with its obligations under the applicable agreements and that some of Mirada’s claims are grounded in agreements that do not apply to the Company. The Company filed answers denying all of Mirada’s claims and intends and continues to vigorously defend against Mirada’s claims.
Discovery is ongoing, and each of the parties has made a number of procedural filings and motions, and additional filings and motions can be expected over the course of the claim. Trial is scheduled for May 2020. The Company cannot predict or guarantee the ultimate outcome or resolution of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have
135
a material adverse effect on the Company’s business, financial condition, results of operations or cash flows. Such an adverse determination could materially impact the Company’s ability to operate its properties in Wild Basin or develop its identified drilling locations in Wild Basin on its current development schedule. A determination that Mirada has a right to participate in the Company’s midstream operations could materially reduce the interests of the Company in their current assets and future midstream opportunities and related revenues in Wild Basin. In addition, the Company has agreed to indemnify OMP for any losses resulting from this litigation under the omnibus agreement it entered into with OMP at the time of OMP’s initial public offering.
Solomon litigation. On or about August 28, 2019, Oasis Petroleum LLC, a wholly-owned subsidiary of the Company (“OP LLC”), was named as a defendant in the lawsuit styled Andrew Solomon, on behalf of himself and those similarly situated vs. Oasis Petroleum, LLC, pending in the United States District Court for the District of North Dakota. The lawsuit alleged violations of the federal Fair Labor Standards Act (the “FLSA”) and Title 29 of the North Dakota Century Code (“Title 29”) as the result of OP LLC’s alleged practice of paying the plaintiff and similarly situated current and former employees overtime at rates less than required by applicable law, or failing to pay for certain overtime hours worked. The lawsuit requested that: (i) its federal claims be advanced as a collective action, with a class of all operators, technicians and all other employees in substantially similar positions employed by OP LLC who were paid hourly for at least one week during the three year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or eight or more hours on at least one workday; and (ii) its state claims be advanced as a class action, with a class of all Operators, Technicians, and all other employees in substantially similar positions employed by OP LLC in North Dakota during the two year period prior to the commencement of the lawsuit, who worked 40 or more hours in at least one workweek and/or worked eight or more hours in a day on at least one workday. No motion has been filed for class certification, and the Company cannot predict whether such a motion will be filed or a class certified.
The Company believes that Mr. Solomon’s claims are without merit and that OP LLC has complied with its obligations under the FLSA and Title 29. OP LLC has filed an answer denying all of Mr. Solomon’s claims and intends to vigorously defend against the claims. The Company cannot predict or guarantee the ultimate outcome or resolutions of such matter. If such matter were to be determined adversely to the Company’s interests, or if the Company were forced to settle such matter for a significant amount, such resolution or settlement could have a material adverse effect on the Company’s business, financial condition, results of operations or cash flows.
23. Subsequent Events
The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements, other than as previously disclosed.
24. Condensed Consolidating Financial Information
The Notes (see Note 13—Long-Term Debt) are guaranteed on a senior unsecured basis by the Guarantors, which are 100% owned by the Company. These guarantees are full and unconditional and joint and several among the Guarantors. Certain of the Company’s operating units, including OMP (see Note 3—Oasis Midstream Partners), which is accounted for on a consolidated basis, do not guarantee the Notes (“Non-Guarantor Subsidiaries”).
The following financial information reflects consolidating financial information of the parent company, Oasis Petroleum Inc. (“Issuer”), its Guarantors on a combined basis (the “Combined Guarantor Subsidiaries”) and the Non-Guarantor Subsidiaries on a combined basis (the “Combined Non-Guarantor Subsidiaries”), prepared on the equity basis of accounting. The information is presented in accordance with the requirements of Rule 3-10 under the SEC’s Regulation S-X. The financial information may not necessarily be indicative of results of operations, cash flows or financial position had the Guarantors operated as independent entities. The Company has not presented separate financial and narrative information for each of the Guarantors because it believes such financial and narrative information would not provide any additional information that would be material in evaluating the sufficiency of the Guarantors. The assignment of the Delaware Midstream Assets to Panther DevCo in November 2019 represents the transfer of a business from a Guarantor Subsidiary to a Non-Guarantor Subsidiary, and is retrospectively reflected in the Combined Non-Guarantor Subsidiaries financial information and removed from the Combined Guarantors Subsidiaries financial information for all periods presented.
During 2019, the Company identified errors primarily relating to the presentation of non-controlling interests and equity in earnings of subsidiaries in the financial information of the Combined Guarantor Subsidiaries and the related intercompany eliminations.
•Condensed Consolidating Balance Sheet. As of December 31, 2018, it was determined that (1) in the Issuer’s financial information, investment in and advances to subsidiaries and Oasis share of stockholders’ equity were both overstated by $9.6 million, (2) in the Combined Guarantor Subsidiaries financial information, investment in and advances to subsidiaries and non-controlling interests were overstated by $11.1 million and $184.3 million, respectively, and Oasis share of stockholders’ equity was understated by $173.2 million and (3) in the
136
intercompany eliminations financial information, investments in and advances to subsidiaries and non-controlling interests were understated by $20.7 million and $184.3 million, respectively, and Oasis share of stockholders’ equity was overstated by $163.6 million.
•Condensed Consolidated Statements of Operations. For the year ended December 31, 2018, it was determined that equity in earnings of subsidiaries and net income attributable to non-controlling interests were overstated by $24.9 million and $15.8 million, respectively, in the Combined Guarantor Subsidiaries financial information and understated by $24.9 million and $15.8 million, respectively, in the intercompany eliminations financial information. For the year ended December 31, 2017, it was determined that equity in earnings of subsidiaries and net income attributable to non-controlling interests were overstated by $5.6 million and $3.7 million, respectively, in the Combined Guarantor Subsidiaries financial information and understated by $5.6 million and $3.7 million, respectively, in the intercompany eliminations financial information.
•Condensed Consolidated Statement of Cash Flows. For the year ended December 31, 2018, it was determined that cash paid for distributions to non-controlling interests was understated by $114.8 million in the Combined Guarantor Subsidiaries financial information and overstated by $114.8 million in the intercompany eliminations financial information, with the offsetting impacts in investment in subsidiaries / capital contributions from parent.
These errors in the condensed consolidated financial statements, which the Company has determined are not material to this disclosure, were all eliminated in consolidation and therefore have no impact on the Company’s consolidated financial position, results of operations or cash flows. The Company has revised the consolidating financial statements as of December 31, 2018 and 2017 to reflect the correction of these errors.
137
Condensed Consolidating Balance Sheet
| December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Parent/
Issuer |
Combined
Guarantor Subsidiaries |
Combined Non-Guarantor Subsidiaries |
Intercompany
Eliminations |
Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| ASSETS | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current assets | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 146 | $ | 15,705 | $ | 4,168 | $ | — | $ | 20,019 | |||||||||||||||||||||||||||||||||||||||||||
| Accounts receivable, net | — | 365,212 | 5,969 | — | 371,181 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Accounts receivable - affiliates | 499,209 | 76,179 | 77,571 | (652,959) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Inventory | — | 35,259 | — | — | 35,259 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Prepaid expenses | 550 | 7,538 | 1,923 | — | 10,011 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 535 | — | — | 535 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other current assets | — | 208 | 138 | — | 346 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total current assets | 499,905 | 500,636 | 89,769 | (652,959) | 437,351 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Property, plant and equipment | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil and gas properties (successful efforts method) | — | 9,485,504 | — | (22,466) | 9,463,038 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other property and equipment | — | 124,150 | 1,155,503 | — | 1,279,653 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Less: accumulated depreciation, depletion, amortization and impairment | — | (3,665,933) | (98,982) | — | (3,764,915) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total property, plant and equipment, net | — | 5,943,721 | 1,056,521 | (22,466) | 6,977,776 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Assets held for sale, net | — | 21,628 | — | — | 21,628 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Investments in and advances to subsidiaries | 4,888,257 | 382,795 | — | (5,271,052) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 639 | — | — | 639 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred income taxes | 249,646 | — | — | (249,646) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term inventory | — | 13,924 | — | — | 13,924 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating right-of-use assets | — | 13,290 | 5,207 | — | 18,497 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other assets | — | 26,266 | 3,172 | — | 29,438 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 5,637,808 | $ | 6,902,899 | $ | 1,154,669 | $ | (6,196,123) | $ | 7,499,253 | |||||||||||||||||||||||||||||||||||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current liabilities | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Accounts payable | $ | — | $ | 16,911 | $ | 1,037 | $ | — | $ | 17,948 | |||||||||||||||||||||||||||||||||||||||||||
| Accounts payable - affiliates | 49,040 | 576,780 | 27,139 | (652,959) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Revenues and production taxes payable | — | 231,649 | 1,441 | — | 233,090 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Accrued liabilities | 50 | 230,819 | 50,210 | — | 281,079 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Accrued interest payable | 36,507 | 373 | 508 | — | 37,388 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 19,695 | — | — | 19,695 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Advances from joint interest partners | — | 4,598 | — | — | 4,598 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Current operating lease liabilities | — | 3,177 | 3,005 | — | 6,182 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other current liabilities | — | 2,430 | 594 | (121) | 2,903 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total current liabilities | 85,597 | 1,086,432 | 83,934 | (653,080) | 602,883 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term debt | 1,916,073 | 337,000 | 458,500 | — | 2,711,573 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred income taxes | — | 517,003 | — | (249,646) | 267,357 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Asset retirement obligations | — | 54,558 | 1,747 | — | 56,305 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 120 | — | — | 120 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating lease liabilities | — | 15,699 | 2,216 | — | 17,915 | ||||||||||||||||||||||||||||||||||||||||||||||||
138
| Other liabilities | — | 3,830 | 3,644 | (1,455) | 6,019 | ||||||||||||||||||||||||
| Total liabilities | 2,001,670 | 2,014,642 | 550,041 | (904,181) | 3,662,172 | ||||||||||||||||||||||||
| Stockholders’ equity | |||||||||||||||||||||||||||||
| Oasis share of stockholders’ equity | 3,636,138 | 4,888,257 | 292,370 | (5,180,627) | 3,636,138 | ||||||||||||||||||||||||
| Non-controlling interests | — | — | 312,258 | (111,315) | 200,943 | ||||||||||||||||||||||||
| Total stockholders’ equity | 3,636,138 | 4,888,257 | 604,628 | (5,291,942) | 3,837,081 | ||||||||||||||||||||||||
| Total liabilities and stockholders’ equity | $ | 5,637,808 | $ | 6,902,899 | $ | 1,154,669 | $ | (6,196,123) | $ | 7,499,253 | |||||||||||||||||||
139
Condensed Consolidating Balance Sheet
| December 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Parent/
Issuer |
Combined
Guarantor Subsidiaries |
Combined Non-Guarantor Subsidiaries |
Intercompany
Eliminations |
Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| ASSETS | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current assets | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 179 | $ | 15,362 | $ | 6,649 | $ | — | $ | 22,190 | |||||||||||||||||||||||||||||||||||||||||||
| Accounts receivable, net | — | 385,121 | 2,481 | — | 387,602 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Accounts receivable - affiliates | 643,382 | 76,127 | 81,022 | (800,531) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Inventory | — | 33,106 | 22 | — | 33,128 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Prepaid expenses | 373 | 9,206 | 1,418 | — | 10,997 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 99,930 | — | — | 99,930 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Intangible assets, net | — | 125 | — | — | 125 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other current assets | — | 183 | — | — | 183 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total current assets | 643,934 | 619,160 | 91,592 | (800,531) | 554,155 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Property, plant and equipment | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil and gas properties (successful efforts method) | — | 8,923,291 | — | (11,102) | 8,912,189 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other property and equipment | — | 209,194 | 942,578 | — | 1,151,772 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Less: accumulated depreciation, depletion, amortization and impairment | — | (2,974,122) | (62,730) | — | (3,036,852) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total property, plant and equipment, net | — | 6,158,363 | 879,848 | (11,102) | 7,027,109 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Investments in and advances to subsidiaries | 4,900,528 | 362,266 | — | (5,262,794) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 6,945 | — | — | 6,945 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred income taxes | 219,670 | — | — | (219,670) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term inventory | — | 12,260 | — | — | 12,260 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other assets | — | 23,221 | 2,452 | — | 25,673 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 5,764,132 | $ | 7,182,215 | $ | 973,892 | $ | (6,294,097) | $ | 7,626,142 | |||||||||||||||||||||||||||||||||||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Current liabilities | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Accounts payable | $ | — | $ | 18,567 | $ | 1,599 | $ | — | $ | 20,166 | |||||||||||||||||||||||||||||||||||||||||||
| Accounts payable - affiliates | 43,113 | 724,404 | 33,014 | (800,531) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Revenues and production taxes payable | — | 216,114 | 581 | — | 216,695 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Accrued liabilities | 71 | 270,626 | 60,954 | — | 331,651 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Accrued interest payable | 37,096 | 502 | 442 | — | 38,040 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 84 | — | — | 84 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Advances from joint interest partners | — | 5,140 | — | — | 5,140 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total current liabilities | 80,280 | 1,235,437 | 96,590 | (800,531) | 611,776 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term debt | 1,949,276 | 468,000 | 318,000 | — | 2,735,276 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred income taxes | — | 519,725 | — | (219,670) | 300,055 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Asset retirement obligations | — | 50,754 | 1,630 | — | 52,384 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 20 | — | — | 20 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other liabilities | — | 7,751 | — | — | 7,751 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total liabilities | 2,029,556 | 2,281,687 | 416,220 | (1,020,201) | 3,707,262 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Stockholders’ equity | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oasis share of stockholders’ equity | 3,734,576 | 4,900,528 | 244,857 | (5,145,385) | 3,734,576 | ||||||||||||||||||||||||||||||||||||||||||||||||
140
| Non-controlling interests | — | — | 312,815 | (128,511) | 184,304 | ||||||||||||||||||||||||
| Total stockholders’ equity | 3,734,576 | 4,900,528 | 557,672 | (5,273,896) | 3,918,880 | ||||||||||||||||||||||||
| Total liabilities and stockholders’ equity | $ | 5,764,132 | $ | 7,182,215 | $ | 973,892 | $ | (6,294,097) | $ | 7,626,142 | |||||||||||||||||||
141
Condensed Consolidating Statement of Operations
| Year Ended December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Parent/
Issuer |
Combined
Guarantor Subsidiaries |
Combined Non-Guarantor Subsidiaries |
Intercompany
Eliminations |
Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenues | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenues | $ | — | $ | 1,407,809 | $ | — | $ | 962 | $ | 1,408,771 | |||||||||||||||||||||||||||||||||||||||||||
| Purchased oil and gas sales | — | 408,791 | — | — | 408,791 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Midstream revenues | — | 73,558 | 410,191 | (271,541) | 212,208 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Well services revenues | — | 41,974 | — | — | 41,974 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total revenues | — | 1,932,132 | 410,191 | (270,579) | 2,071,744 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Lease operating expenses | — | 287,426 | — | (64,042) | 223,384 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Midstream expenses | — | 66,545 | 110,052 | (114,451) | 62,146 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Well services expenses | — | 28,761 | — | — | 28,761 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Marketing, transportation and gathering expenses | — | 173,254 | — | (44,448) | 128,806 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Purchased oil and gas expenses | — | 409,180 | — | — | 409,180 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Production taxes | — | 112,592 | — | — | 112,592 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | — | 771,836 | 36,358 | (21,002) | 787,192 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Exploration expenses | — | 6,658 | — | — | 6,658 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Rig termination | — | 384 | — | — | 384 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment | — | 10,257 | — | — | 10,257 | ||||||||||||||||||||||||||||||||||||||||||||||||
| General and administrative expenses | 16,637 | 112,709 | 31,009 | (16,849) | 143,506 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total operating expenses | 16,637 | 1,979,602 | 177,419 | (260,792) | 1,912,866 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Loss on sale of properties | — | (4,455) | — | — | (4,455) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss) | (16,637) | (51,925) | 232,772 | (9,787) | 154,423 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity in earnings (loss) of subsidiaries | (13,898) | 167,848 | — | (153,950) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net loss on derivative instruments | — | (106,314) | — | — | (106,314) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (132,000) | (26,685) | (17,538) | — | (176,223) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Gain on extinguishment of debt | 4,312 | — | — | — | 4,312 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense) | 3 | 440 | (3) | — | 440 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total other income (expense), net | (141,583) | 35,289 | (17,541) | (153,950) | (277,785) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | (158,220) | (16,636) | 215,231 | (163,737) | (123,362) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Income tax benefit | 29,977 | 2,738 | — | — | 32,715 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | (128,243) | (13,898) | 215,231 | (163,737) | (90,647) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Less: Net income attributable to non-controlling interests | — | — | 93,111 | (55,515) | 37,596 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to Oasis | $ | (128,243) | $ | (13,898) | $ | 122,120 | $ | (108,222) | $ | (128,243) | |||||||||||||||||||||||||||||||||||||||||||
142
Condensed Consolidating Statement of Operations
| Year Ended December 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Parent/
Issuer |
Combined
Guarantor Subsidiaries |
Combined Non-Guarantor Subsidiaries |
Intercompany
Eliminations |
Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenues | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenues | $ | — | $ | 1,590,024 | $ | — | $ | — | $ | 1,590,024 | |||||||||||||||||||||||||||||||||||||||||||
| Purchased oil and gas sales | — | 550,344 | — | — | 550,344 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Midstream revenues | — | 4,620 | 273,770 | (157,886) | 120,504 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Well services revenues | — | 61,075 | — | — | 61,075 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total revenues | — | 2,206,063 | 273,770 | (157,886) | 2,321,947 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Lease operating expenses | — | 248,257 | — | (54,345) | 193,912 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Midstream expenses | — | 3,482 | 71,118 | (41,842) | 32,758 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Well services expenses | — | 41,200 | — | — | 41,200 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Marketing, transportation and gathering expenses | — | 131,340 | — | (24,147) | 107,193 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Purchased oil and gas expenses | — | 553,521 | — | (60) | 553,461 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Production taxes | — | 133,696 | — | — | 133,696 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | — | 623,349 | 28,409 | (15,462) | 636,296 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Exploration expenses | — | 27,432 | — | — | 27,432 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment | — | 384,228 | — | — | 384,228 | ||||||||||||||||||||||||||||||||||||||||||||||||
| General and administrative expenses | 30,003 | 79,742 | 23,897 | (12,296) | 121,346 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total operating expenses | 30,003 | 2,226,247 | 123,424 | (148,152) | 2,231,522 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Gain on sale of properties | — | 28,587 | — | — | 28,587 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss) | (30,003) | 8,403 | 150,346 | (9,734) | 119,012 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity in earnings of subsidiaries | 103,586 | 122,222 | — | (225,808) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net gain on derivative instruments | — | 28,457 | — | — | 28,457 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (131,134) | (25,371) | (2,580) | — | (159,085) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Loss on extinguishment of debt | (13,848) | — | — | — | (13,848) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense) | 1 | 134 | (14) | — | 121 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total other income (expense), net | (41,395) | 125,442 | (2,594) | (225,808) | (144,355) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | (71,398) | 133,845 | 147,752 | (235,542) | (25,343) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | 36,102 | (30,259) | — | — | 5,843 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | (35,296) | 103,586 | 147,752 | (235,542) | (19,500) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Less: Net income attributable to non-controlling interests | — | — | 96,354 | (80,558) | 15,796 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to Oasis | $ | (35,296) | $ | 103,586 | $ | 51,398 | $ | (154,984) | $ | (35,296) | |||||||||||||||||||||||||||||||||||||||||||
143
Condensed Consolidating Statement of Operations
| Year Ended December 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Parent/
Issuer |
Combined
Guarantor Subsidiaries |
Combined Non-Guarantor Subsidiaries |
Intercompany
Eliminations |
Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Revenues | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Oil and gas revenues | $ | — | $ | 1,034,634 | $ | — | $ | — | $ | 1,034,634 | |||||||||||||||||||||||||||||||||||||||||||
| Purchased oil and gas sales | — | 133,542 | — | — | 133,542 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Midstream revenues | — | 46,649 | 59,821 | (33,718) | 72,752 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Well services revenues | — | 52,791 | — | — | 52,791 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total revenues | — | 1,267,616 | 59,821 | (33,718) | 1,293,719 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Lease operating expenses | — | 189,548 | — | (12,414) | 177,134 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Midstream expenses | — | 11,117 | 15,098 | (8,626) | 17,589 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Well services expenses | — | 37,228 | — | — | 37,228 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Marketing, transportation and gathering expenses | — | 61,571 | — | (5,831) | 55,740 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Purchased oil and gas expenses | — | 134,615 | — | — | 134,615 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Production taxes | — | 88,133 | — | — | 88,133 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | — | 528,615 | 4,626 | (2,439) | 530,802 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Exploration expenses | — | 11,600 | — | — | 11,600 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment | — | 6,887 | — | — | 6,887 | ||||||||||||||||||||||||||||||||||||||||||||||||
| General and administrative expenses | 27,616 | 61,513 | 5,110 | (2,442) | 91,797 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total operating expenses | 27,616 | 1,130,827 | 24,834 | (31,752) | 1,151,525 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Gain on sale of properties | — | 1,774 | — | — | 1,774 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Operating income (loss) | (27,616) | 138,563 | 34,987 | (1,966) | 143,968 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity in earnings of subsidiaries | 323,953 | 29,352 | — | (353,305) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net loss on derivative instruments | — | (71,657) | — | — | (71,657) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense, net of capitalized interest | (131,329) | (15,489) | (19) | — | (146,837) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other income (expense) | 1 | (1,333) | — | — | (1,332) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Total other income (expense), net | 192,625 | (59,127) | (19) | (353,305) | (219,826) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | 165,009 | 79,436 | 34,968 | (355,271) | (75,858) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | (41,213) | 244,517 | — | — | 203,304 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income including non-controlling interests | 123,796 | 323,953 | 34,968 | (355,271) | 127,446 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Less: Net income attributable to non-controlling interests | — | — | 23,329 | (19,679) | 3,650 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income attributable to Oasis | $ | 123,796 | $ | 323,953 | $ | 11,639 | $ | (335,592) | $ | 123,796 | |||||||||||||||||||||||||||||||||||||||||||
144
Condensed Consolidating Statement of Cash Flows
| Year Ended December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Parent/
Issuer |
Combined
Guarantor Subsidiaries |
Combined Non-Guarantor Subsidiaries |
Intercompany
Eliminations |
Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | $ | (128,243) | $ | (13,898) | $ | 215,231 | $ | (163,737) | $ | (90,647) | |||||||||||||||||||||||||||||||||||||||||||
| Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by operating activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity in (earnings) loss of subsidiaries | 13,898 | (167,848) | — | 153,950 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | — | 771,836 | 36,358 | (21,002) | 787,192 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Gain on extinguishment of debt | (4,312) | — | — | — | (4,312) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Loss on sale of properties | — | 4,455 | — | — | 4,455 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment | — | 10,257 | — | — | 10,257 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred income taxes | (29,977) | (2,722) | — | — | (32,699) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 106,314 | — | — | 106,314 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation expenses | 13,933 | 19,296 | 378 | — | 33,607 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred financing costs amortization and other | 16,898 | 9,419 | 946 | — | 27,263 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Working capital and other changes: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Change in accounts receivable, net | 144,174 | 17,164 | (37) | (147,572) | 13,729 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in inventory | — | (5,893) | — | — | (5,893) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in prepaid expenses | (177) | 1,007 | (505) | — | 325 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in accounts payable, interest payable and accrued liabilities | 5,316 | (96,526) | (3,311) | 147,572 | 53,051 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in other assets and liabilities, net | — | (11,692) | 3,479 | (1,576) | (9,789) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net cash provided by operating activities | 31,510 | 641,169 | 252,539 | (32,365) | 892,853 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Capital expenditures | — | (618,450) | (225,832) | (24,939) | (869,221) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Acquisitions | — | (21,009) | (24,939) | 24,939 | (21,009) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from sale of properties | — | 42,376 | — | — | 42,376 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative settlements | — | 19,098 | — | — | 19,098 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net cash used in investing activities | — | (577,985) | (250,771) | — | (828,756) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from Revolving Credit Facilities | — | 1,829,000 | 153,000 | — | 1,982,000 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Principal payments on Revolving Credit Facilities | — | (1,960,000) | (12,500) | — | (1,972,500) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Repurchase of senior unsecured notes | (45,789) | (1) | — | — | (45,790) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred financing costs | — | (79) | (973) | — | (1,052) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Purchases of treasury stock | (4,856) | — | — | — | (4,856) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to non-controlling interests | — | — | (95,771) | 74,501 | (21,270) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Investment in subsidiaries / capital contributions from parent | 19,102 | 70,563 | (47,529) | (42,136) | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Payments on finance lease liabilities | — | (2,323) | (59) | — | (2,382) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | (1) | (417) | — | (418) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net cash used in financing activities | (31,543) | (62,841) | (4,249) | 32,365 | (66,268) | ||||||||||||||||||||||||||||||||||||||||||||||||
145
| Increase (decrease) in cash and cash equivalents | (33) | 343 | (2,481) | — | (2,171) | ||||||||||||||||||||||||
| Cash and cash equivalents at beginning of period | 179 | 15,362 | 6,649 | — | 22,190 | ||||||||||||||||||||||||
| Cash and cash equivalents at end of period | $ | 146 | $ | 15,705 | $ | 4,168 | $ | — | $ | 20,019 | |||||||||||||||||||
146
Condensed Consolidating Statement of Cash Flows
| Year Ended December 31, 2018 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Parent/
Issuer |
Combined
Guarantor Subsidiaries |
Combined Non-Guarantor Subsidiaries |
Intercompany
Eliminations |
Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | $ | (35,296) | $ | 103,586 | $ | 147,752 | $ | (235,542) | $ | (19,500) | |||||||||||||||||||||||||||||||||||||||||||
| Adjustments to reconcile net income (loss) including non-controlling interests to net cash provided by (used in) operating activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity in earnings of subsidiaries | (103,586) | (122,222) | — | 225,808 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | — | 623,349 | 28,409 | (15,462) | 636,296 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Loss on extinguishment of debt | 13,848 | — | — | — | 13,848 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Gain on sale of properties | — | (28,587) | — | — | (28,587) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment | — | 384,228 | — | — | 384,228 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred income taxes | (36,102) | 30,236 | — | — | (5,866) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | (28,457) | — | — | (28,457) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation expenses | 27,456 | 1,461 | 356 | — | 29,273 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred financing costs amortization and other | 16,069 | 13,507 | (519) | — | 29,057 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Working capital and other changes: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Change in accounts receivable, net | (217,714) | (52,013) | 3,194 | 243,025 | (23,508) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in inventory | — | (14,324) | (22) | — | (14,346) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in prepaid expenses | (106) | (1,608) | (640) | — | (2,354) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in accounts payable, interest payable and accrued liabilities | 6,886 | 234,441 | 27,814 | (243,025) | 26,116 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in other assets and liabilities, net | — | 221 | — | — | 221 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net cash provided by (used in) operating activities | (328,545) | 1,143,818 | 206,344 | (25,196) | 996,421 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Capital expenditures | — | (865,935) | (283,026) | — | (1,148,961) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Acquisitions | — | (581,650) | — | — | (581,650) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from sale of properties | — | 333,229 | — | — | 333,229 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Costs related to sale of properties | — | (2,850) | — | — | (2,850) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative settlements | — | (213,528) | — | — | (213,528) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | 224 | — | — | 224 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net cash used in investing activities | — | (1,330,510) | (283,026) | — | (1,613,536) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from Revolving Credit Facilities | — | 2,949,000 | 275,000 | — | 3,224,000 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Principal payments on Revolving Credit Facilities | — | (2,551,000) | (35,000) | — | (2,586,000) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Repurchase of senior unsecured notes | (423,340) | — | — | — | (423,340) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from issuance of senior unsecured convertible notes | 400,000 | — | — | — | 400,000 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred financing costs | (6,908) | (5,988) | (966) | — | (13,862) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from issuance of Oasis Midstream common units, net of offering costs | — | — | 44,503 | — | 44,503 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Purchases of treasury stock | (6,846) | — | — | — | (6,846) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions to non-controlling interests | — | — | (128,903) | 114,789 | (14,114) | ||||||||||||||||||||||||||||||||||||||||||||||||
147
| Investment in subsidiaries / capital contributions from parent | 365,602 | (203,823) | (72,186) | (89,593) | — | ||||||||||||||||||||||||
| Other | 38 | (1,794) | — | — | (1,756) | ||||||||||||||||||||||||
| Net cash provided by financing activities | 328,546 | 186,395 | 82,448 | 25,196 | 622,585 | ||||||||||||||||||||||||
| Increase (decrease) in cash and cash equivalents | 1 | (297) | 5,766 | — | 5,470 | ||||||||||||||||||||||||
| Cash and cash equivalents at beginning of period | 178 | 15,659 | 883 | — | 16,720 | ||||||||||||||||||||||||
| Cash and cash equivalents at end of period | $ | 179 | $ | 15,362 | $ | 6,649 | $ | — | $ | 22,190 | |||||||||||||||||||
148
Condensed Consolidating Statement of Cash Flows
| Year Ended December 31, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
|
Parent/
Issuer |
Combined
Guarantor Subsidiaries |
Combined Non-Guarantor Subsidiaries |
Intercompany
Eliminations |
Consolidated | |||||||||||||||||||||||||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net income including non-controlling interests | $ | 123,796 | $ | 323,953 | $ | 34,968 | $ | (355,271) | $ | 127,446 | |||||||||||||||||||||||||||||||||||||||||||
| Adjustments to reconcile net income including non-controlling interests to net cash provided by (used in) operating activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Equity in earnings of subsidiaries | (323,953) | (29,352) | — | 353,305 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, depletion and amortization | — | 528,615 | 4,626 | (2,439) | 530,802 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Gain on sale of properties | — | (1,774) | — | — | (1,774) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Impairment | — | 6,887 | — | — | 6,887 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred income taxes | 41,213 | (244,097) | — | — | (202,884) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative instruments | — | 71,657 | — | — | 71,657 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Equity-based compensation expenses | 25,436 | 1,045 | 53 | — | 26,534 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred financing costs amortization and other | 15,392 | 2,794 | 125 | — | 18,311 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Working capital and other changes: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Change in accounts receivable, net | (173,668) | (216,982) | (53,623) | 277,887 | (166,386) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in inventory | — | (2,501) | — | — | (2,501) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in prepaid expenses | 9 | (98) | (749) | — | (838) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in accounts payable, interest payable and accrued liabilities | 7,074 | 337,319 | 56,601 | (277,887) | 123,107 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Change in other assets and liabilities, net | — | (22,485) | — | — | (22,485) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net cash provided by (used in) operating activities | (284,701) | 754,981 | 42,001 | (4,405) | 507,876 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Capital expenditures | — | (594,945) | (52,404) | — | (647,349) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Acquisitions | — | (61,874) | (66,679) | 66,679 | (61,874) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from sale of properties | — | 72,453 | — | (66,679) | 5,774 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Costs related to sale of properties | — | (366) | — | — | (366) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Derivative settlements | — | (8,264) | — | — | (8,264) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other | — | (2,681) | — | — | (2,681) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net cash used in investing activities | — | (595,677) | (119,083) | — | (714,760) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from Revolving Credit Facilities | — | 1,084,000 | 78,000 | — | 1,162,000 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Principal payments on Revolving Credit Facilities | — | (1,377,000) | — | — | (1,377,000) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Deferred financing costs | — | (577) | (2,137) | — | (2,714) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from sale of common stock, net of offering costs | 302,191 | — | — | — | 302,191 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Proceeds from issuance of Oasis Midstream common units, net of offering costs | — | — | 134,185 | — | 134,185 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Purchases of treasury stock | (6,229) | — | — | — | (6,229) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Investment in subsidiaries / capital contributions from parent | (11,194) | 138,872 | (132,083) | 4,405 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other | (55) | — | — | — | (55) | ||||||||||||||||||||||||||||||||||||||||||||||||
149
| Net cash provided by (used in) financing activities | 284,713 | (154,705) | 77,965 | 4,405 | 212,378 | ||||||||||||||||||||||||
| Increase in cash and cash equivalents | 12 | 4,599 | 883 | — | 5,494 | ||||||||||||||||||||||||
| Cash and cash equivalents at beginning of period | 166 | 11,060 | — | — | 11,226 | ||||||||||||||||||||||||
| Cash and cash equivalents at end of period | $ | 178 | $ | 15,659 | $ | 883 | $ | — | $ | 16,720 | |||||||||||||||||||
150
25. Supplemental Oil and Gas Disclosures — Unaudited
The supplemental data presented below reflects information for all of the Company’s crude oil and natural gas producing activities.
Capitalized Costs
The following table sets forth the capitalized costs related to the Company’s crude oil and natural gas producing activities:
| At December 31, | |||||||||||||||||
| 2019 | 2018 | ||||||||||||||||
| (In thousands) | |||||||||||||||||
|
Proved oil and gas properties(1)
|
$ | 8,724,376 | $ | 7,878,104 | |||||||||||||
| Less: Accumulated depreciation, depletion, amortization and impairment | (3,601,019) | (2,853,353) | |||||||||||||||
| Proved oil and gas properties, net | 5,123,357 | 5,024,751 | |||||||||||||||
| Unproved oil and gas properties | 738,662 | 1,034,085 | |||||||||||||||
| Total oil and gas properties, net | $ | 5,862,019 | $ | 6,058,836 | |||||||||||||
__________________
(1)Included in the Company’s proved oil and gas properties are estimates of future asset retirement costs of $42.3 million and $40.5 million at December 31, 2019 and 2018, respectively.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
The following table sets forth costs incurred related to the Company’s crude oil and natural gas activities for the periods presented:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Acquisition costs: | |||||||||||||||||||||||||||||
| Proved oil and gas properties | $ | — | $ | 260,034 | $ | 61,874 | |||||||||||||||||||||||
| Unproved oil and gas properties | 23,058 | 696,293 | 5,424 | ||||||||||||||||||||||||||
| Exploration costs | 67,470 | 53,928 | 11,600 | ||||||||||||||||||||||||||
| Development costs | 542,133 | 923,562 | 511,905 | ||||||||||||||||||||||||||
| Asset retirement costs | 2,083 | 5,804 | (2,965) | ||||||||||||||||||||||||||
| Total costs incurred | $ | 634,744 | $ | 1,939,621 | $ | 587,838 | |||||||||||||||||||||||
Results of Operations for Crude Oil and Natural Gas Producing Activities
The following table sets forth the results of operations for crude oil and natural gas producing activities, which exclude straight-line depreciation, general and administrative expenses and interest expense, for the periods presented:
| Year Ended December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Revenues | $ | 1,408,771 | $ | 1,590,024 | $ | 1,034,634 | |||||||||||||||||||||||
| Production costs | 464,782 | 434,801 | 321,007 | ||||||||||||||||||||||||||
| Depreciation, depletion and amortization | 759,900 | 613,928 | 515,600 | ||||||||||||||||||||||||||
| Exploration costs | 6,658 | 27,432 | 11,600 | ||||||||||||||||||||||||||
| Rig termination | 384 | — | — | ||||||||||||||||||||||||||
| Impairment | 5,389 | 384,228 | 6,887 | ||||||||||||||||||||||||||
| Income tax expense | 40,745 | 30,770 | 67,148 | ||||||||||||||||||||||||||
| Results of operations for crude oil and natural gas producing activities | $ | 130,913 | $ | 98,865 | $ | 112,392 | |||||||||||||||||||||||
151
26. Supplemental Oil and Gas Reserve Information — Unaudited
The reserve estimates at December 31, 2019, 2018 and 2017 presented in the table below are based on reports prepared by DeGolyer and MacNaughton, the Company’s independent reserve engineers, in accordance with the FASB’s authoritative guidance on crude oil and natural gas reserve estimation and disclosures. At December 31, 2019, 2018 and 2017, all of the Company’s crude oil and natural gas producing activities were conducted within the continental United States.
The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries and undeveloped locations are more imprecise than estimates of established proved producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available.
Proved oil and gas reserves are the estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions (i.e., prices and costs) existing at the time the estimate is made. Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells and equipment in place and under operating methods being utilized at the time the estimates were made.
152
Estimated Quantities of Proved Crude Oil and Natural Gas Reserves — Unaudited
The following table sets forth the Company’s estimated net proved, proved developed and proved undeveloped reserves at December 31, 2019, 2018 and 2017:
|
Crude Oil
(MBbl) |
Natural Gas
(MMcf) |
MBoe(1)
|
|||||||||||||||
| 2017 | |||||||||||||||||
| Proved reserves | |||||||||||||||||
| Beginning balance | 236,593 | 411,104 | 305,110 | ||||||||||||||
| Revisions of previous estimates | (28,323) | 54,726 | (19,200) | ||||||||||||||
| Extensions, discoveries and other additions | 36,238 | 89,489 | 51,153 | ||||||||||||||
| Sales of reserves in place | (1,196) | (1,147) | (1,387) | ||||||||||||||
| Purchases of reserves in place | 466 | 1,230 | 671 | ||||||||||||||
| Production | (18,818) | (31,946) | (24,143) | ||||||||||||||
| Net proved reserves at December 31, 2017 | 224,960 | 523,456 | 312,204 | ||||||||||||||
| Proved developed reserves, December 31, 2017 | 150,628 | 301,101 | 200,812 | ||||||||||||||
| Proved undeveloped reserves, December 31, 2017 | 74,332 | 222,355 | 111,392 | ||||||||||||||
| 2018 | |||||||||||||||||
| Proved reserves | |||||||||||||||||
| Beginning balance | 224,960 | 523,456 | 312,204 | ||||||||||||||
| Revisions of previous estimates | (17,352) | 3,019 | (16,850) | ||||||||||||||
| Extensions, discoveries and other additions | 30,640 | 46,309 | 38,358 | ||||||||||||||
| Sales of reserves in place | (12,470) | (20,735) | (15,926) | ||||||||||||||
| Purchases of reserves in place | 25,688 | 43,107 | 32,873 | ||||||||||||||
| Production | (23,050) | (42,430) | (30,122) | ||||||||||||||
| Net proved reserves at December 31, 2018 | 228,416 | 552,726 | 320,537 | ||||||||||||||
| Proved developed reserves, December 31, 2018 | 144,533 | 339,444 | 201,107 | ||||||||||||||
| Proved undeveloped reserves, December 31, 2018 | 83,883 | 213,282 | 119,430 | ||||||||||||||
| 2019 | |||||||||||||||||
| Proved reserves | |||||||||||||||||
| Beginning balance | 228,416 | 552,726 | 320,537 | ||||||||||||||
| Revisions of previous estimates | (51,965) | (68,301) | (63,349) | ||||||||||||||
| Extensions, discoveries and other additions | 49,297 | 87,382 | 63,861 | ||||||||||||||
| Sales of reserves in place | (2,136) | (2,368) | (2,531) | ||||||||||||||
| Production | (22,825) | (55,906) | (32,142) | ||||||||||||||
| Net proved reserves at December 31, 2019 | 200,787 | 513,533 | 286,376 | ||||||||||||||
| Proved developed reserves, December 31, 2019 | 113,418 | 314,000 | 165,751 | ||||||||||||||
| Proved undeveloped reserves, December 31, 2019 | 87,369 | 199,533 | 120,625 | ||||||||||||||
__________________
(1)Natural gas is converted to barrel equivalents at the rate of six thousand cubic feet of natural gas to one barrel of oil.
Revisions of Previous Estimates
In 2019, the Company had net negative revisions of 63.3 MMBoe, or 20% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 51.2 MMBoe due to well performance, 11.2 MMBoe due to lower realized prices and 7.6 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 6.7 MMBoe due to lower operating expenses. Proved developed revisions were primarily due to negative revisions of 30.2 MMBoe for performance largely related to higher than anticipated decline rates in recently developed spacing units and 9.6 MMBoe due to lower realized prices, partially offset by positive revisions of 5.1 MMBoe due to lower operating expenses. The proved undeveloped revisions were primarily due to negative revisions of 21.1 MMBoe for performance largely related to reductions in the anticipated hydrocarbon recoveries of proved areas during full field development due to changes in anticipated well densities and well performance and 7.0 MMBoe associated with alignment to the anticipated five-year development plan, offset by positive revisions of 1.7 MMBoe due to lower operating expenses.
153
In 2018, the Company had net negative revisions of 16.9 MMBoe, or 5% of the beginning of the year estimated net proved reserves balance. These net negative revisions were attributable to negative revisions of 42.3 MMBoe due to well performance and 9.4 MMBoe associated with alignment to the five-year development plan, offset by positive revisions of 14.7 MMBoe for the addition of proved undeveloped reserves (“PUDs”) that were previously removed from the five-year development plan, 14.4 MMBoe due to higher realized prices and 5.4 MMBoe for ownership adjustments. The proved developed net negative revisions of 20.2 MMBoe were primarily due to negative revisions of 33.0 MMBoe for performance revisions largely related to higher than anticipated decline rates in recently developed spacing units, partially offset by positive revisions of 12.2 MMBoe due to higher realized prices. The proved undeveloped revisions were primarily due to positive revisions of 14.7 MMBoe for the addition of PUDs that were previously removed from the five-year development plan, 5.6 MMBoe for ownership adjustments and 2.2 MMBoe due to higher realized prices, offset by negative revisions of 9.4 MMBoe associated with alignment to the anticipated five-year development plan and 9.3 MMBoe for performance largely related to the associated impact of higher than anticipated decline rates in recently developed spacing units.
In 2017, the Company had net negative revisions of 19.2 MMBoe, or 6% of the beginning of the year estimated net proved reserves balance.These net negative revisions were attributable to negative revisions of 39.1 MMBoe associated with well performance and 2.1 MMBoe for alignment to the anticipated five-year development plan, offset by positive revisions of 16.1 MMBoe due to higher realized prices and 2.5 MMBoe for ownership adjustments. The proved developed negative revisions of 14.2 MMBoe were primarily due to negative revisions of 29.7 MMBoe for performance revisions largely related to higher than anticipated decline rates in recently developed spacing units, offset by positive revisions of 14.1 MMBoe from increased realized prices. The proved undeveloped negative revisions of 5.0 MMBoe were primarily due to negative revisions of 9.4 MMBoe for performance revisions largely related to the associated impact of higher than anticipated decline rates in recently developed spacing units and negative 1.8 MMBoe revisions associated with alignment to the five-year development plan, offset by positive revisions of 2.6 MMBoe for ownership adjustments and 2.0 MMBoe from increased realized prices.
Extensions, Discoveries and Other Additions
In 2019, the Company had a total of 63.9 MMBoe of additions due to extensions and discoveries. An estimated 10.3 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2019, with 60% of these reserves from wells producing in the Bakken or Three Forks formations and 40% of reserves from wells producing in the Delaware Basin, respectively. An additional 53.6 MMBoe of proved undeveloped reserves were added in the Williston and Delaware Basins associated with the Company’s anticipated five-year development plan, with 63% of these proved undeveloped reserves in the Bakken or Three Forks formations in the Williston Basin and 37% of proved undeveloped reserves in the Delaware Basin.
In 2018, the Company had a total of 38.4 MMBoe of additions due to extensions and discoveries. An estimated 9.0 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2018, with 77% of these reserves from wells producing in the Bakken or Three Forks formations and 23% of reserves from wells producing in the Delaware Basin, respectively. An additional 29.4 MMBoe of proved undeveloped reserves were added in the Williston and Delaware Basins associated with the Company’s anticipated five-year development plan, with 76% of these proved undeveloped reserves in the Bakken or Three Forks formations and 24% of proved undeveloped reserves in the Delaware Basin.
In 2017, the Company had a total of 51.2 MMBoe of additions due to extensions and discoveries. An estimated 17.9 MMBoe of these extensions and discoveries were associated with new producing wells at December 31, 2017, with 100% of these reserves from wells producing in the Bakken or Three Forks formations. An additional 33.3 MMBoe of proved undeveloped reserves were added in the Williston Basin associated with the Company’s 2017 operated and non-operated drilling program and anticipated five-year drilling plan, with 100% of these proved undeveloped reserves in the Bakken or Three Forks formations.
Sales of Reserves in Place
In 2019 and 2018, the Company divested 2.5 MMBoe and 15.9 MMBoe, respectively, of reserves associated with reservoirs in the Bakken or Three Forks formations (see Note 11—Divestitures). In 2017, the Company divested 1.4 MMBoe of reserves associated with reservoirs other than the Bakken or Three Forks formations.
Purchases of Reserves in Place
In 2019, there were no purchased estimated net proved reserves from acquisitions. In 2018, the Company purchased estimated net proved reserves of 32.9 MMBoe from acquisitions in the Delaware Basin (see Note 10—Acquisitions). In 2017, the Company purchased estimated net proved reserves of 0.7 MMBoe from acquisitions of additional working interests in its existing properties in the Williston Basin.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves — Unaudited
The Standardized Measure represents the present value of estimated future net cash flows from estimated net proved oil and natural gas reserves, less future development, production, plugging and abandonment costs and income tax expenses,
154
discounted at 10% per annum to reflect timing of future cash flows. Production costs do not include DD&A of capitalized acquisition, exploration and development costs.
The Company’s estimated net proved reserves and related future net revenues and Standardized Measure were determined using index prices for crude oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior twelve months were $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas, $65.66 per Bbl for crude oil and $3.16 per MMBtu for natural gas and $51.34 per Bbl for crude oil and $2.99 per MMBtu for natural gas for the years ended December 31, 2019, 2018 and 2017, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. Future operating costs, production taxes and capital costs were based on current costs as of each year-end.
The following table sets forth the Standardized Measure of discounted future net cash flows from projected production of the Company’s estimated net proved reserves at December 31, 2019, 2018 and 2017:
| At December 31, | |||||||||||||||||||||||||||||
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| Future cash inflows | $ | 12,385,040 | $ | 16,652,405 | $ | 11,636,126 | |||||||||||||||||||||||
| Future production costs | (5,509,127) | (6,609,097) | (4,458,418) | ||||||||||||||||||||||||||
| Future development costs | (1,490,521) | (1,701,672) | (992,271) | ||||||||||||||||||||||||||
| Future income tax expense | (188,823) | (968,466) | (580,481) | ||||||||||||||||||||||||||
| Future net cash flows | 5,196,569 | 7,373,170 | 5,604,956 | ||||||||||||||||||||||||||
| 10% annual discount for estimated timing of cash flows | (2,352,200) | (3,322,864) | (2,304,261) | ||||||||||||||||||||||||||
| Standardized measure of discounted future net cash flows | $ | 2,844,369 | $ | 4,050,306 | $ | 3,300,695 | |||||||||||||||||||||||
The following table sets forth the changes in the Standardized Measure of discounted future net cash flows applicable to estimated net proved reserves for the periods presented:
| 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| (In thousands) | |||||||||||||||||||||||||||||
| January 1 | $ | 4,050,306 | $ | 3,300,695 | $ | 2,483,065 | |||||||||||||||||||||||
| Net changes in prices and production costs | (1,070,192) | 1,003,008 | 881,742 | ||||||||||||||||||||||||||
| Net changes in future development costs | 131,003 | (89,304) | (60,929) | ||||||||||||||||||||||||||
| Sales of crude oil and natural gas, net | (943,989) | (1,155,223) | (769,367) | ||||||||||||||||||||||||||
| Extensions | 437,700 | 461,196 | 661,467 | ||||||||||||||||||||||||||
| Purchases of reserves in place | — | 385,763 | 6,518 | ||||||||||||||||||||||||||
| Sales of reserves in place | (36,907) | (197,867) | (9,024) | ||||||||||||||||||||||||||
| Revisions of previous quantity estimates | (732,253) | (115,015) | (78,942) | ||||||||||||||||||||||||||
| Previously estimated development costs incurred | 246,311 | 303,364 | 157,386 | ||||||||||||||||||||||||||
| Accretion of discount | 467,426 | 368,374 | 262,776 | ||||||||||||||||||||||||||
| Net change in income taxes | 533,872 | (240,908) | (238,354) | ||||||||||||||||||||||||||
| Changes in timing and other | (238,908) | 26,223 | 4,357 | ||||||||||||||||||||||||||
| December 31 | $ | 2,844,369 | $ | 4,050,306 | $ | 3,300,695 | |||||||||||||||||||||||
155
27. Quarterly Financial Data — Unaudited
The following tables set forth the Company’s results of operations by quarter for the years ended December 31, 2019 and 2018:
| For the Year Ended December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||||||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 575,732 | $ | 529,405 | $ | 482,743 | $ | 483,864 | |||||||||||||||||||||||||||||||||
| Operating income | 50,444 | 71,572 | 8,441 | 23,966 | |||||||||||||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | (107,978) | 51,174 | 30,311 | (64,154) | |||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to Oasis | (114,882) | 42,757 | 20,288 | (76,406) | |||||||||||||||||||||||||||||||||||||
| Earnings (loss) attributable to Oasis per share: | |||||||||||||||||||||||||||||||||||||||||
| Basic | $ | (0.37) | $ | 0.14 | $ | 0.06 | $ | (0.24) | |||||||||||||||||||||||||||||||||
| Diluted | $ | (0.37) | $ | 0.14 | $ | 0.06 | $ | (0.24) | |||||||||||||||||||||||||||||||||
| For the Year Ended December 31, 2018 | |||||||||||||||||||||||||||||||||||||||||
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||||||||||||||||||||||||||||
| (In thousands, except per share data) | |||||||||||||||||||||||||||||||||||||||||
| Total revenues | $ | 473,812 | $ | 573,751 | $ | 674,629 | $ | 599,755 | |||||||||||||||||||||||||||||||||
| Operating income (loss) | 112,985 | (242,674) | 179,045 | 69,656 | |||||||||||||||||||||||||||||||||||||
| Net income (loss) including non-controlling interests | 3,712 | (316,301) | 66,223 | 226,866 | |||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to Oasis | 590 | (320,204) | 62,341 | 221,977 | |||||||||||||||||||||||||||||||||||||
| Earnings (loss) attributable to Oasis per share: | |||||||||||||||||||||||||||||||||||||||||
| Basic | $ | 0.00 | $ | (1.02) | $ | 0.20 | $ | 0.71 | |||||||||||||||||||||||||||||||||
| Diluted | $ | 0.00 | $ | (1.02) | $ | 0.20 | $ | 0.70 | |||||||||||||||||||||||||||||||||
156