ITEM 1.
BUSINESS
General
Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas reserves in the Midland Basin of the greater Permian Basin in West Texas, where we lease approximately 150,000 net acres as of December 31, 2018. We believe our concentrated acreage position and extensive, integrated field infrastructure system provide us an opportunity to achieve cost, operating and recovery efficiencies in the development of our drilling inventory. Our long-term business strategy is to develop resource potential from the Wolfcamp shale oil formation and pursue acquisitions that meet our strategic and financial objectives. See “- Our Business Strategy” below. Additional drilling targets could include the Clearfork, Canyon Sands, Strawn and Ellenburger zones. We sometimes refer to our development project in the Permian Basin as “Project Pangea,” which includes “Pangea West.” Our management and technical team have a proven track record of finding and developing reserves through advanced drilling and completion techniques. As the operator of all of our estimated proved reserves and production, we have a high degree of control over capital expenditures and other operating matters.
At December 31, 2018, our estimated proved reserves were 180.1 million barrels of oil equivalent (“MMBoe”). Substantially all of our proved reserves are located in Crockett and Schleicher Counties, Texas. The following are important characteristics of our proved reserves at December 31, 2018:
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29% oil, 31% NGLs and 40% natural gas;
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37% proved developed;
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100% operated;
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Reserve life of approximately 44 years based on 2018 production of 4.1 MMBoe;
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Standardized measure of discounted future net cash flows (“standardized measure”) of $660 million; and
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PV-10 (non-GAAP) of $761.8 million.
PV-10 is our estimate of the present value of future net revenues from proved oil, NGLs and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates for future income taxes. Estimated future net revenues are discounted at an annual rate of 10% to determine their present value. PV-10 is a financial measure that is not determined in accordance with accounting principles generally accepted in the United States (“GAAP”), and generally differs from the standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the standardized measure, as computed under GAAP. See Item 2. “Properties - Proved Oil and Gas Reserves” for a reconciliation of PV-10 to the standardized measure.
At December 31, 2018, we owned and operated 813 producing oil and gas wells in the Permian Basin. During 2018, we produced 4.1 MMBoe, or 11.2 MBoe/d. Production for 2018 was 26% oil, 36% NGLs and 38% natural gas.
Our History
Approach Resources Inc. was incorporated in September 2002. Our common stock began trading on the NASDAQ Global Market in the United States under the symbol “AREX” on November 8, 2007, and is now listed on the NASDAQ Global Select Market (“NASDAQ”). Our principal executive offices are located at One Ridgmar Centre, 6500 West Freeway, Suite 800, Fort Worth, Texas 76116. Our telephone number is (817) 989-9000.
Our Business Strategy
Our long-term business strategy is to create value by growing reserves and production in a cost efficient manner and at attractive rates of return by pursuing the strategies discussed below. However, the rate of growth of our reserves and production, as well as achievable rates of return, depend on commodity prices and the availability of capital.
In response to deteriorating and volatile commodity prices, we substantially reduced our drilling activity beginning in 2015, which has led to a natural decline in production. Commodity prices have continued to remain volatile and have drastically fallen again in 2018, which has resulted in unanticipated delays in our ability to resume and accelerate our drilling activity over the last several years. In order to address the effect of the sustained commodity price volatility and deterioration on our business strategy and financial metrics, we have pursued, and currently are pursuing or considering, a number of alternatives to strengthen our balance sheet and resume production growth. These factors raise substantial doubt about our ability to continue as a going concern. See Note 1 to our consolidated financial statements in this report for additional information regarding our plans to improve our leverage and our ability to continue to comply with the financial covenants under our revolving credit facility.
In order to improve our leverage position to meet upcoming financial covenants under the revolving credit facility, we have been, and currently are, pursuing or considering a number of deleveraging and strategic actions, which in certain cases may require the consent of current lenders, stockholders or bond holders. On April 12, 2018, our largest shareholder, Wilks Brothers, LLC, and its affiliate SDW Investments, LLC (collectively, “Wilks”), disclosed on Schedule 13D/A that they intended to engage in discussions with the Company regarding their investment in the Company, including the possible acquisition of additional shares of common stock through the exchange of approximately $60 million of 7% Senior Notes due 2021 (the “Senior Notes”) currently held by Wilks (the “Exchange Transaction”). In April 2018, our board of directors formed a committee of independent directors (the “Special Committee”) to evaluate a potential Exchange Transaction as well as other strategic alternatives. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters. The Special Committee engaged in discussions with Wilks regarding an Exchange Transaction in 2018, but in mid-2018 the Wilks and the Committee deferred further discussions regarding a stand-alone Exchange Transaction pending resolution of the Company’s discussions regarding the potential transaction described in the following paragraph.
In addition, management has reviewed numerous cash flow producing properties for potential acquisition over the last several years in order to grow our production base and reduce our leverage ratio to a sustainable level and one that is in compliance with our financial covenants. In early 2018, we retained a financial advisor, separate from the Special Committee’s advisor, and began discussions with a potential seller and multiple financing counterparties for the purchase of a set of substantial cash flow producing properties. Despite a deteriorating commodity price market, discussions with both the seller and financing parties progressed throughout 2018. However, no definitive agreements ultimately were executed, and the negotiations currently are not active.
In March 2019, our board of directors expanded the scope of the Special Committee to explore, in addition to an Exchange Transaction, other financing alternatives and deleveraging transactions, including without limitation (i) amendments or waivers to the covenants or other provisions of our revolving credit facility, (ii) raising new capital in private or public markets and (iii) restructuring our balance sheet either in court or through an out of court agreement with creditors. We are also considering operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives, including: (i) acquiring assets with existing production and cash flows by issuing preferred and common equity to finance such acquisitions; (ii) selling existing producing or midstream assets; (iii) merging with a strategic partner. The Special Committee has re-commenced discussions with the Wilks regarding an Exchange Transaction and intends to continue those discussions as part of its review of financing alternatives and deleveraging transactions. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our credit facility covenants.
We also continue to position ourselves to increase our drilling activity at a measured and disciplined pace, and resume production growth in the event of a continued and sustained commodity price recovery, by focusing on the following strategies:
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Strengthen our balance sheet and financial flexibility. We intend to continue to explore a broad range of deleveraging alternatives as discussed above.
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Acquire strategic and complementary assets. We continually review opportunities to acquire producing properties, undeveloped acreage and drilling prospects. We focus particularly on opportunities where we believe our operational efficiency, reservoir management and geological expertise in unconventional oil and gas properties will enhance value and performance. We remain focused on unconventional resource opportunities, but we will also consider conventional opportunities based on individual project economics.
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Develop our Wolfcamp shale oil resource play. We believe our current acreage position provides us the long-term ability to increase reserves and production at competitive costs and at attractive rates of return when commodity prices improve. During 2018, we drilled six, and completed nine, horizontal Wolfcamp wells, and entered 2019 with an inventory of seven drilled horizontal wells waiting on completion. With our 2019 drilling plan, we expect to continue to develop our core properties in Project Pangea, subject to commodity prices. Focusing on the Wolfcamp shale oil play allows us to use our operating, technical and regional expertise important to interpreting geological and operating trends, enhancing production rates and maximizing well recovery. In addition, our inventory of drilled wells waiting on completion allows us to increase production with lower marginal capital expenditures.
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Operate our properties as a low-cost producer. We believe our concentrated acreage position in the Midland Basin enables us to capture economies of scale and operating efficiencies. Through our investment in extensive integrated field infrastructure, including water transportation and recycling systems, centralized production facilities, gas lift lines and saltwater disposal wells, we have significantly reduced drilling and completion costs, per-unit lease operating expenses and our fresh water use over the last three years. In addition, because we operate 100% of our reserve base, we are able to better manage timing and scope of capital expenditures and control costs.
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Operate our business at or near cash-flow breakeven. In 2019, we have set our expected capital expenditure budget to a range of $30 million to $60 million. We believe that over the long term we will be able to maintain and grow production substantially out of operating cash flow. We have the operational flexibility to adjust our capital spending upward in response to a commodity price recovery. Operating our business at or near operating cash flow allows us to preserve liquidity so that we will be able to accelerate execution of our long-term strategy should commodity prices further recover. Because we operate 100% of our reserve base, we also have the flexibility to adjust our capital budget downward in response to commodity price decreases.
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Mitigate commodity price volatility. We enter into commodity derivative contracts to partially mitigate the risk of commodity price volatility. For 2018, we hedged approximately 57%, 61% and 63% of our natural gas, NGLs and oil production, respectively. For 2019, we currently have 182,500 Bbls of oil hedged at a floor price of $65.00 per Bbl and a ceiling price of $71.00 per Bbl and 239,575 Bbls of NGLs hedged at weighted average prices of $14.12 per Bbl (C2-ethane), $36.54 per Bbl (C3-propane), $38.63 per Bbl (NC4-butane) and $65.21 per Bbl (C5 - Pentane).
Our Competitive Strengths
We have a number of competitive strengths, which we believe will help us to successfully execute our business strategies:
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Lower-risk, liquids-rich asset base. We have assembled a strong asset base within the Midland Basin, where we have a long history of operating. We have drilled more than 800 wells in the area since 2004. Our acreage position of 150,000 net, primarily contiguous acres in the Midland Basin provides us with a multi-year inventory of repeatable, horizontal and vertical drilling locations that we believe create the opportunity for us to deliver long-term reserve, production and cash flow growth. Production for 2018 was 62% liquids (26% oil and 36% NGLs) and 38% natural gas. With a liquids-rich but diverse production base, we are able to capture the upside of improvement in commodity prices in any one of our three production streams.
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Installation of field infrastructure and water handling systems. Our large, mostly contiguous acreage position and our success in the Wolfcamp shale oil play led us to invest over $125 million in building field infrastructure since 2012. We have an extensive network of centralized production facilities, water transportation, handling and recycling systems, gas lift lines and saltwater disposal wells. In addition,
we believe the infrastructure reduces the need for trucks, reduces fresh water usage, improves drilling and completion efficiencies and drives down drilling and completion and operating costs.
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High degree of operational control. We operate 100% of our estimated proved reserves, and we have approximately 98.5% working interest in Project Pangea. This allows us to more effectively manage and control the timing of capital spending on our development activities, as well as maximize benefits from operating cost efficiencies and field infrastructure systems.
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Proactive financial management. In 2018, we executed a disciplined capital expenditure program, spending 22% less than the midpoint of our annual budget. As of December 31, 2018, we had liquidity of approximately $23.2 million. In 2017, we completed a debt-for-equity exchange which reduced the outstanding principal of our long-term debt by $145.1 million, extended the term on our revolving credit facility by one year to May 7, 2020, and completed an acquisition of producing Wolfcamp shale assets adjacent to our Project Pangea acreage. Currently, we are continuing to evaluate a broad range of transactions to reduce our leverage. We also enter into commodity derivative contracts to partially mitigate the risk of commodity price volatility.
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Experienced management team with track record of growth. Our management team has extensive industry experience, including significant technical and exploration expertise. Our management team has specific expertise in the Permian Basin and in successfully executing multi-year development drilling programs.
2018 Activity
Our 2018 activity focused on executing a disciplined capital budget in connection with slowly recovering commodity prices, strengthening our balance sheet and maintaining a competitive operating cost structure. We drilled six, and completed nine, horizontal wells in 2018 in the Wolfcamp shale oil resource play in the Midland Basin. We plan to continue to develop the Wolfcamp shale in Project Pangea in 2019, at a measured pace subject to commodity prices, capital availability and leverage restrictions. Our 2018 activities included:
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Executed a disciplined capital budget and managed production decline. In 2018, we incurred capital expenditures of $46.8 million, spending 22% less than the midpoint of our annual budget, and we deferred well completions scheduled in the fourth quarter due to the sharp decrease in commodity prices. During 2018, we drilled six, and completed nine, horizontal Wolfcamp wells, and entered 2019 with an inventory of seven drilled horizontal wells waiting on completion. Production for 2018 totaled 4.1 MMBoe (11.2 MBoe/d) compared to 4.2 MMBoe (11.6 MBoe/d) in 2017, a decrease of 4%. Production for 2018 was 26% oil, 36% NGLs and 38% natural gas.
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Maintained competitive operating cost structure. Utilizing our infrastructure and field-level expertise, we maintained an industry leading average drilling and completion cost of $4.6 million per horizontal well and lease operating expense per Boe of $5.18. Additionally, in 2018, we reduced general and administrative expenses by $3.4 million, or 14%.
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Delineation of the multi-zone potential of the Wolfcamp shale. The Wolfcamp shale has a gross pay thickness of approximately 1,000 to 1,200 feet, which allows for stacked wellbores targeting three different zones that we call “benches.” We believe effectively developing the Wolfcamp shale may involve up to three lateral wellbores, each targeting a different bench, which we refer to as the Wolfcamp A, B and C. As of December 31, 2018, we had drilled and completed a total of 25 wells targeting the Wolfcamp A bench, 115 wells targeting the Wolfcamp B bench and 56 wells targeting the Wolfcamp C bench. We have successful wells targeting each of the Wolfcamp benches, and we continued development of the Wolfcamp shale in 2018.
Plans for 2019
For 2019, we have set our capital expenditure budget to a range of $30 million to $60 million, compared to $46.8 million of capital expenditures in 2018. We plan to operate one rig on an intermittent basis during the year in Project Pangea. Our 2019 capital budget excludes acquisitions and lease extensions and renewals and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the
availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms. The eventual results of our strategic and deleveraging efforts may have a substantial impact on the Company’s capital expenditure budget. Although the impact of changes in these collective factors in the current commodity price environment is difficult to estimate, we currently expect to execute our development plan based on current conditions. To the extent there is a significant increase or decrease in commodity prices in the future or a change to our capital structure, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan.
Markets and Customers
The revenues generated by our operations are highly dependent upon the prices of oil, NGLs and natural gas. Oil, NGLs and natural gas are commodities, and therefore, we receive market-based pricing. The price we receive for our oil, NGLs and natural gas production depends on numerous factors beyond our control, including supply and demand for oil, NGLs and gas, seasonality, the condition of the domestic and global economies, particularly in the manufacturing sectors, political conditions in other oil and gas producing countries, the extent of domestic production and imports of oil, NGLs and gas, the proximity and capacity of gas pipelines and other transportation facilities, the marketing of competitive fuels and the effects of federal, state and local regulation. The oil and gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
For the year ended December 31, 2018, sales to American Midstream, LP (“AMID”) and DCP Midstream, LP (“DCP”) accounted for approximately 56% and 41%, respectively, of our total sales. As of December 31, 2018, we had dedicated the majority of our oil production from northern Project Pangea and Pangea West through September 2022 to AMID. In addition, as of December 31, 2018, we had dedicated the majority of our NGLs and natural gas production from Project Pangea to DCP through August 2023.
Commodity Derivative Activity
We enter into commodity swap and collar contracts to mitigate portions of the risk of market price fluctuations related to future oil, NGLs and gas production. Our derivative contracts are recorded as derivative assets and liabilities at fair value on our balance sheet, and the change in a derivative contract’s fair value is recognized as current income or expense on our consolidated statements of operations.
In 2018, we recognized a commodity derivative loss of $0.3 million, and the estimated fair value of our derivatives contracts at December 31, 2018, was a net asset of $5.9 million. For 2019, we currently have 182,500 Bbls of oil hedged at a floor price of $65.00 per Bbl and a ceiling price of $71.00 per Bbl and 239,575 Bbls of NGLs hedged at weighted average prices of $14.12 per Bbl (C2-ethane), $36.54 per Bbl (C3-propane), $38.63 per Bbl (NC4-butane) and $65.21 per Bbl (C5 - Pentane).
Title to Properties
Our properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens, including other mineral encumbrances and restrictions. We do not believe that any of these burdens materially interfere with our use of the properties in the operation of our business.
We believe that we generally have satisfactory title to or rights in all of our producing properties. As is customary in the oil and gas industry, we make a general investigation of title at the time we acquire undeveloped properties. We receive title opinions of counsel before we commence drilling operations. We believe that we have satisfactory title to all of our other assets. Although title to our properties is subject to encumbrances in certain cases, we believe that none of these burdens will materially detract from the value of our properties or from our interest therein or will materially interfere with our use of the properties in the operation of our business.
Oil and Gas Leases
The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil, NGLs and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 20% to 25%, resulting in a net revenue interest to us generally ranging from 80% to 75%.
Seasonality
Demand for NGLs and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. In addition, certain natural gas users utilize storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations. These seasonal anomalies can increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.
Competition
The oil and gas industry is highly competitive, and we compete for personnel, prospective properties, producing properties and services with a substantial number of other companies that have greater resources. Many of these companies explore for, produce and market oil and gas, carry on refining operations and market the end products on a worldwide basis. We also face competition from alternative fuel sources, including coal, heating oil, imported LNG, nuclear and other nonrenewable fuel sources, and renewable fuel sources such as wind, solar, geothermal, hydropower and biomass. Competitive conditions may also be substantially affected by various forms of energy legislation and/or regulation considered from time-to-time by the United States government. It is not possible to predict whether such legislation or regulation may ultimately be adopted or its precise effects upon our future operations. Such laws and regulations may, however, substantially increase the costs of exploring for, developing or producing oil, NGLs and gas and may prevent or delay the commencement or continuation of our operations.
Hydraulic Fracturing
Hydraulic fracturing is an important process in oil and gas production and has been commonly used in the completion of unconventional oil and gas wells in shale and tight sand formations since the 1950s. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into rock formations to stimulate oil and gas production. It is important to us because it provides access to oil and gas reserves that previously were uneconomical to produce.
We have used hydraulic fracturing to complete both horizontal and vertical wells in the Permian Basin. We engage third parties to provide hydraulic fracturing services to us for completion of these wells. While hydraulic fracturing is not required to maintain our leasehold acreage that is currently held by production from existing wells, it will be required in the future to develop the proved undeveloped reserves associated with this acreage. All of our proved undeveloped reserves associated with future drilling will require hydraulic fracturing.
We believe we have followed, and intend to continue to follow, applicable industry standard practices and legal requirements for groundwater protection in our operations. These protective measures include setting surface casing at a depth sufficient to protect fresh water zones as determined by applicable state regulatory agencies and cementing the well to create a permanent isolating barrier between the casing pipe and surrounding geological formations. This aspect of well design is intended to prevent contact between the fracturing fluid and any aquifers during the hydraulic fracturing operations. For recompletions of existing wells, the production casing is pressure-tested before perforating the new completion interval.
Injection rates and pressures are monitored at the surface during our hydraulic fracturing operations. Pressure is monitored on both the injection string and the immediate annulus to the injection string. We believe we have adequate procedures in place to address abrupt changes to the injection pressure or annular pressure.
Texas regulations currently require disclosure of the components in the solutions used in hydraulic fracturing operations. More than 99% (by mass) of the ingredients we use in hydraulic fracturing are water and sand. The remainder of the ingredients are chemical additives that are managed and used in accordance with applicable requirements in Texas.
Hydraulic fracturing requires the use of a significant amount of water. Currently our primary sources of water in Project Pangea are the nonpotable Santa Rosa and potable Edwards-Trinity (Plateau) aquifers. We use water from on-lease water wells that we have drilled, and we purchase water from off-lease water wells. We have historically reused and recycled flowback and produced water and intend to do so in the future. Any flowback water that is not recycled in a way that we believe minimizes the impact to nearby surface water is disposed into approved disposal facilities or injection wells.
For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, please read “Business - Regulation - Environmental Laws and Regulation.” For related risks to our stockholders, please read “Risk Factors - Federal and state legislation and regulatory initiatives and private litigation relating to hydraulic fracturing could stop or delay our development project and result in materially increased costs and additional operating restrictions;” “- Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner”; “- Climate change legislation or regulations regulating emissions of greenhouse gases (“GHGs”) and volatile organic compounds (“VOCs”) could result in increased operating costs and reduced demand for the oil and gas we produce”; and “-Environmental laws and regulations may expose us to significant costs and liabilities.”
Regulation
The oil and gas industry in the United States is subject to extensive regulation by federal, state and local authorities. At the federal level, various federal rules, regulations and procedures apply, including those issued by the U.S. Department of Interior, the U.S. Department of Transportation (the “DOT”) (Office of Pipeline Safety), the Occupational Safety and Health Administration (“OSHA”) and the U.S. Environmental Protection Agency (the “EPA”). At the state and local level, various agencies and commissions regulate drilling, production and midstream activities. These federal, state and local authorities have various permitting, licensing and bonding requirements. Various remedies are available for enforcement of these federal, state and local rules, regulations and procedures, including fines, penalties, revocation of permits and licenses, actions affecting the value of leases, wells or other assets, suspension of production, and, in certain cases, criminal prosecution. As a result, there can be no assurance that we will not incur liability for fines, penalties or other remedies that are available to these federal, state and local authorities. However, we believe that we are currently in substantial compliance with federal, state and local rules and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations.
Transportation and Sale of Oil
Sales of crude oil and condensate are not currently regulated and are made at negotiated prices. Our sales of crude oil are affected by the availability, terms and cost of transportation. Interstate transportation of oil by pipeline is regulated by the Federal Energy Regulation Commission (“FERC”) pursuant to the Interstate Commerce Act (“ICA”), Energy Policy Act of 1992 (“EPAct 1992”), and the rules and regulations promulgated under those laws. The ICA and its regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products, be just and reasonable and non-discriminatory and that such rates, terms and conditions of service be filed with FERC.
Intrastate oil pipeline transportation rates are also subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. As effective interstate and intrastate rates apply equally to all comparable shippers, we believe that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.
The transportation of oil by truck is also subject to federal, state and local rules and regulations, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the DOT.
Transportation and Sale of Natural Gas and NGLs
FERC regulates interstate gas pipeline transportation rates and service conditions under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. FERC also regulates interstate NGLs pipelines under various federal laws and regulations. Although FERC does not regulate oil and gas producers such as Approach, FERC’s actions are intended to facilitate increased competition within all phases of the oil and gas industry and its regulation of third-party pipelines and facilities could indirectly affect our ability to transport or market our production. To date, FERC’s policies have not materially affected our business or operations.
Regulation of Production
Oil, NGLs and gas production is regulated under a wide range of federal and state statutes, rules, orders and regulations, as well as under requirements of local governmental authorities. State and federal statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The state in which we operate, Texas, has regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells. Also, Texas imposes a severance tax on production and sales of oil, NGLs and gas within its jurisdiction. In addition to state and federal laws and regulations, local land use restrictions could restrict or prohibit the location and/or performance of well drilling. The failure to comply with these rules and regulations can result in substantial penalties, delays in operations, and increased costs of operations. Our competitors in the oil and gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Environmental Laws and Regulations
In the United States, the exploration for and development of oil and gas and the drilling and operation of wells, fields and gathering systems are subject to extensive federal, state and local laws and regulations governing environmental protection and the release of materials into the environment. These laws and regulations may, among other things:
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require the acquisition of various permits or authorizations before drilling and production begin;
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require the installation of expensive pollution controls or emissions monitoring equipment;
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restrict or require the reporting of the types, quantities and concentration of various substances that can be released into the environment or are managed in connection with oil and gas drilling, completion, production, storage, transportation and processing activities;
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suspend, limit or prohibit construction, drilling and other activities in certain lands lying within municipalities, wilderness, wetlands, endangered species habitat and other protected areas;
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require remedial measures to mitigate and remediate pollution from historical and ongoing operations, such as the closure of waste pits and plugging of abandoned wells; and
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impose safety and health standards for worker protection.
These laws, rules and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability.
Governmental authorities have the power to enforce compliance with environmental laws, regulations and permits, and violations are subject to injunction, as well as administrative, civil and criminal penalties. The effects of existing and future laws and regulations could have a material adverse impact on our business, financial condition and results of operations. The historical trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment. Any changes in environmental laws and regulations or re-interpretations of enforcement policies that result in more stringent and costly permitting, reporting, or waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition or results of operations. Moreover, accidental releases or spills and ground water or surface water contamination may occur in the course of our operations, and we may incur significant costs and liabilities as a result of such releases, spills or contamination, including any third-party claims for damage to property, natural resources or persons. We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks. While we believe that we are in substantial compliance with existing environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this will continue in the future.
The following is a summary of some of the existing environmental laws, rules and regulations that apply to our business operations. The outcome of the Trump administration’s actions related to the rollback or modification of some of these laws, rules and regulations remains unclear due to ongoing litigation and rulemaking.
Hazardous Substance Release
The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as the Superfund law, and comparable state statutes impose strict liability, and under certain circumstances, joint and several liability, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site, regardless of whether the disposal of hazardous substances was lawful at the time of the disposal. Under CERCLA, such persons may be subject to strict, joint and several liabilities for the costs of investigating releases of hazardous substances, cleaning up the hazardous substances that have been released into the environment, damages to natural resources and certain health studies. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment as a result of oil and gas operations. Crude oil and fractions of crude oil are excluded from regulation under CERCLA (often referred to as the “petroleum exclusion”). Nevertheless, many chemicals commonly used at oil and gas production facilities fall outside of CERCLA’s petroleum exclusion. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be responsible for cleanup costs under CERCLA.
Waste Handling
The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the authorization and oversight of the EPA, individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. The EPA also retains enforcement authority in any state-administered RCRA programs. Drilling fluids, produced water and many other wastes associated with the exploration, development and production of oil or gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and gas exploration and production wastes now regulated as non-hazardous could be regulated under RCRA as hazardous wastes in the future. Any such change could increase our operating expenses, which could have a material adverse effect on our business, financial condition and results of operations.
We currently own or lease properties that for many years have been used for oil and gas exploration, production and development activities. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes may have been disposed of or released on, under or from the properties owned or leased by us or on, under or from other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and wastes was not under our control. These properties and the materials
disposed or released on, at, under or from them may be subject to CERCLA, RCRA and analogous state laws or other laws that regulate releases or waste from oil and gas operations. Under such laws, we could be required to remove or remediate previously disposed wastes or contamination, or to perform remedial activities to prevent future contamination.
Air Emissions
The federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions, permitting programs and other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions at specified sources. For example, under the EPA’s New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) regulations, since January 1, 2015, owners and operators of hydraulically fractured natural gas wells (wells drilled principally for the production of natural gas) have been required to use so-called “green completion” technology to recover natural gas that formerly would have been flared or vented. In 2016, the EPA issued additional rules known as NSPS Subpart OOOOa for the oil and gas industry to reduce emissions of methane, VOCs and other compounds. These rules apply to certain sources of air emissions that were constructed, reconstructed, or modified after September 18, 2015. Among other things, the new rules impose green completion requirements on new hydraulically fractured or re-fractured oil wells and leak detection and repair requirements at well sites, although in October 2018, the EPA released proposed revisions to some of those NSPS Subpart OOOOa requirements, including reducing the required frequency of fugitive emissions monitoring at well sites and compressor stations, creating uncertainty as to the future and scope of these rules. Regardless, we do not expect that the currently applicable NSPS or NESHAP requirements will have a material adverse effect on our business, financial condition or results of operations. However, any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permitting requirements or use specific equipment or technologies to control emissions. Our failure to comply with existing or new requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.
Greenhouse Gas Emissions
While Congress has, from time-to-time, considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of such federal legislation, a number of states have taken legal measures to reduce emissions of GHGs through the planned development of GHG emission inventories and/or regional GHG cap-and-trade programs or other mechanisms. Most cap-and-trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels such as refineries and gas processing plants, to acquire and surrender emission allowances corresponding with their annual emissions of GHGs. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. Many states have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, the EPA has adopted regulations under existing provisions of the federal CAA. The EPA has adopted two sets of rules regarding possible future regulation of GHG emissions under the CAA, one of which purports to regulate emissions of GHGs from motor vehicles and the other of which would regulate emissions of GHGs from large stationary sources of emissions, such as power plants or industrial facilities. The motor vehicle rule was finalized in 2010 and became effective in 2011, but it did not require immediate reductions in GHG emissions. In 2015, the EPA issued a final rule to limit carbon emissions from new power plants and simultaneously released a final rule to limit carbon emissions from existing power plants (the latter rule is also known as the “Clean Power Plan”). The Clean Power Plan has been heavily litigated since its promulgation, and the decision by the District of Columbia Circuit Court of Appeals in December 2018 to continue to hold a number of consolidated Clean Power Plan cases in abeyance without yet ruling on the merits of the Clean Power Plan has contributed to the current uncertainty as to the Clean Power Plan’s future. Further, the EPA under the Trump
administration proposed in October 2017 to repeal the Clean Power Plan and in August 2018 to replace it with the Affordable Clean Energy (“ACE”) Rule. The regulatory procedures required to complete the repeal of the Clean Power Plan and/or to finalize the ACE Rule may take years, however. If the Clean Power Plan regulations ultimately are upheld or replaced, it could have a significant impact on the electrical generation industry and may favor the use of natural gas over other fossil fuels such as coal in new plants. In the past, the EPA has also indicated that it will propose new GHG emissions standards for refineries, but we do not know when the agency will issue specific regulations.
In 2010, the EPA enacted final rules on mandatory reporting of GHGs. The EPA has also subsequently issued amendments to the rules containing technical and clarifying changes to certain GHG reporting requirements. Under the GHG reporting rules, certain onshore oil and natural gas production, processing, transmission, storage and distribution facilities are required to report their GHG emissions on an annual basis. Our operations in the Permian Basin are subject to the EPA’s mandatory GHG reporting rules, and we believe that we are in substantial compliance with such rules. We do not expect that the EPA’s mandatory GHG reporting requirements, as currently promulgated, will have a material adverse effect on our business, financial condition or results of operations.
The adoption of additional legislation or regulatory programs to monitor, permit, or reduce GHG emissions could require us to incur increased operating costs to comply with those requirements, such as costs to purchase and operate emissions control systems, acquire emissions allowances or obtain permits. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our future business, financial condition and results of operations.
Water Discharges
The Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) and analogous state laws, impose restrictions and strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other substances, into regulated waters, including wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, an analogous state agency, or, in the case of fill material, the United States Army Corps of Engineers. Spill prevention, control, and countermeasure regulations promulgated under the CWA impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, must develop, implement, and maintain Spill Prevention, Control, and Countermeasure (“SPCC”) Plans. Where applicable to our operations, we prepare and implement SPCC Plans to prevent releases of oil from our facilities or, if a release occurs, to mitigate the consequences of such release. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
In 2016, the EPA issued a final rule banning the disposal of wastewater from unconventional oil and gas wells to public wastewater and sewage treatment plants. Produced and other flowback water from our current operations in the Permian Basin is typically not discharged to wastewater treatment plants but is either re-injected into underground formations that do not contain potable water or recycled for reuse in our hydraulic fracturing operations.
The Safe Drinking Water Act, Groundwater Protection and the Underground Injection Control Program
Fluids associated with oil and gas production result from operations on the Company’s properties and may be disposed by injection in underground disposal wells. The federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control program (the “UIC program”) promulgated under the SDWA and state programs regulate the drilling and operation of saltwater disposal wells. The EPA has delegated administration of the UIC program for Class II injection wells (including saltwater disposal wells) in Texas to the Railroad Commission of Texas (“RRC”). Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater. Contamination of groundwater by oil and gas drilling, production and related operations may result in fines, penalties and remediation
costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third-party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages and bodily injury.
In addition, several cases have recently spotlighted the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. Those petitions are currently pending. The EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. To date, no further action has been taken by the EPA with respect to the issue, but should CWA permitting be required for saltwater injections wells, the costs of permitting and compliance for our operations could increase.
Currently, the Company believes that disposal well operations on its properties substantially comply with all applicable requirements under the SDWA and RRC rules. However, a change in the regulations or in how courts or governmental agencies interpret existing laws or the inability to obtain permits for new disposal wells in the future may affect the Company’s ability to dispose of produced waters and ultimately increase the cost of the Company’s operations. For example, there exists a growing concern that the injection of saltwater and other fluids into underground disposal wells triggers seismic activity in certain areas, including in some parts of Texas. In response to these concerns, in 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These recent seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and are likely to result in added costs to comply or perhaps may require alternative methods of disposing of saltwater and other fluids, which could delay production schedules and also result in increased costs.
Hydraulic Fracturing
Hydraulic fracturing is the subject of significant focus among some environmentalists, regulators and the general public. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment have been raised at all levels, including federal, state and local, as well as internationally. There have been claims that hydraulic fracturing may contaminate groundwater, reduce air quality or cause earthquakes. Hydraulic fracturing requires the use and disposal of water, and public concern has been growing over the adequacy of the water supply.
The Energy Policy Act of 2005, which exempts hydraulic fracturing from regulation under the SDWA, prohibits the use of diesel fuel in the fracturing process without a UIC permit. In the past, legislation has been introduced in, but not passed by, Congress that would amend the SDWA to repeal this exemption. For example, the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in each chamber of Congress since 2009 and the Fracking Disclosure and Safety Act was introduced in the current term of Congress, which commenced in January 2019, to accomplish this purposes. If legislation repealing the exemption were enacted, it could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements beyond those currently required by state regulatory agencies.
In 2010, the EPA asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the UIC program by posting a requirement on its website that requires facilities to obtain permits to use diesel fuel in hydraulic fracturing operations. Following a legal challenge by industry groups and a subsequent settlement, in 2014, the EPA issued revised guidance on the use of diesel in hydraulic fracturing operations. Under the guidance, EPA broadly defined “diesel” to include fuels such as kerosene that have not traditionally been considered diesel. The EPA’s continued assertion of its regulatory authority under the SDWA could result in extensive requirements that could cause additional costs and delays in the hydraulic fracturing process.
In addition to the above actions of the EPA, certain members of Congress have, in the past, called upon government agencies to investigate various aspects of hydraulic fracturing. Federal agencies that have been involved in hydraulic fracturing research include the White House Council on Environmental Quality, the Department of Energy, the Department of Interior and the Energy Information Administration. The EPA has also studied the potential environmental impacts of hydraulic fracturing on water resources, publishing a final report in 2016. These and future investigations and studies, depending on their degree of pursuit and any meaningful results obtained, could facilitate initiatives to further regulate hydraulic fracturing.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances or otherwise require the public disclosure of chemicals used in hydraulic fracturing. For example, pursuant to legislation adopted by the State of Texas in 2011, the RRC enacted a rule requiring disclosure to the RRC and the public of certain information regarding additives, chemical ingredients, concentrations and water volumes used in hydraulic fracturing. In 2015, the Texas Legislature enacted House Bill 40, which prohibits local governments from prohibiting hydraulic fracturing but allows for commercially reasonable regulations of certain activities associated with oil and gas development. If future laws or regulations that significantly restrict hydraulic fracturing or that allow greater local government regulation of hydraulic fracturing are adopted, it could become more difficult or costly for us to drill and produce oil and gas from shale and tight sands formations and become easier for third parties opposing hydraulic fracturing to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to delays, additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and higher costs. These new laws or regulations could cause us to incur substantial delays or suspensions of operations and increased compliance costs and could have a material adverse effect on our business, financial condition and results of operations.
Threatened and Endangered Species, Migratory Birds and Natural Resources
Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds and their habitat, wetlands and other natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the CWA and CERCLA. The United States Fish and Wildlife Service (“USFWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to, species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in some cases, criminal penalties.
OSHA and Other Laws and Regulations
We are subject to the requirements of the federal OSHA and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the CAA, and similar state statutes require that we organize and/or disclose information about hazardous materials used, produced or otherwise managed in our operations. These laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.
Compliance
We believe that we are in substantial compliance with all existing environmental laws and regulations that apply to our current operations and that our ongoing compliance with existing requirements will not have a material adverse effect on our business, financial condition or results of operations. We did not incur any material expenditures for remediation or pollution control activities for the year ended December 31, 2018. In addition, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital or operating expenditures during 2019. However, the passage of additional or more stringent laws or regulations in the future could have a negative effect on our business, financial condition and results of operations, including our ability to develop our undeveloped acreage.
Employees
As of February 19, 2019, we had 99 full-time employees, 61 of whom are field personnel. We regularly use independent contractors and consultants to perform various field and other services. None of our employees are represented by a labor union or covered by any collective bargaining agreement. We believe that our relations with our employees are excellent.
Insurance Matters
As is common in the oil and gas industry, we will not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. A loss not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Available Information
We maintain an internet website under the name www.approachresources.com. The information on our website is not a part of this report. We make available, free of charge, on our website, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports, as soon as reasonably practical after providing such reports to the SEC. Also, the charters of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee, our Lead Independent Director Charter, our Governance Guidelines and our Code of Conduct are available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at One Ridgmar Centre, 6500 West Freeway, Suite 800, Fort Worth, Texas 76116.
We file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, proxy statements and other documents with the SEC under the Exchange Act. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers, including Approach, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov. Information contained on or connected to our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.
ITEM 1A.
ITEM 1A.
RISK FACTORS
You should carefully consider the risk factors set forth below as well as the other information contained in this report before investing in our common stock. Any of the following risks could materially and adversely affect our business, financial condition and results of operations. In such a case, you may lose all or part of your investment. The risks described below are not the only ones we face. Additional risks and uncertainties not currently known to us, or those we currently view as immaterial, may also materially adversely affect our business, financial condition and results of operations.
Failure to comply with any of the financial covenants contained in our revolving credit facility could cause an event of default and have a material adverse effect on our business.
Following the fourth amendment to our revolving credit facility, executed in December 2017, our revolving credit facility includes three principal financial covenants: (i) an interest coverage ratio, (ii) a modified current ratio and (iii) a leverage ratio covenant that will first be measured as of March 31, 2019. Failure to comply with these covenants could cause an event of default under our revolving credit facility and have a material adverse effect on our business.
See Note 3 to our consolidated financial statements in this report for a more detailed description of these financial covenants. As of December 31, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments. As of December 31, 2018, our leverage ratio was 6.6 to 1.0, which, if not lowered, would be in excess of our required leverage covenant of 5.0 to 1.0 as of March 31, 2019. Without further deleveraging actions, we do not currently expect to be in compliance with the leverage covenant ratio on March 31, 2019. A failure to comply with the covenants, ratios or tests in our revolving credit facility, or any future indebtedness, could result in an event of default. If an event of default occurs and is not cured or waived, our lenders, (i) would not be required to lend any additional amounts to us, (ii) could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees to be due and payable, (iii) could require us to apply all of our available cash to repay these borrowings and (iv) could prevent us from making debt service payments under our other agreements. A potential event of default and subsequent acceleration of indebtedness would have a material adverse effect on our business, financial condition and results of operations, and raises substantial doubt about our ability to continue as a going concern.
Our ability to continue as a “going concern” contemplates the realization of assets and satisfaction of liabilities in the normal course of business, including the effective implementation and success of management’s plans to mitigate the conditions that raise substantial doubt about our ability to continue as a going concern.
Our consolidated financial statements included in Part IV, Item 15 of this Annual Report have been presented on the basis that we would continue as a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business. Our liquidity and ability to comply with debt covenants under our revolving credit facility have been negatively impacted by the recent decrease in commodity prices. Based on our current operating and commodity price forecast and our current capital structure, and in the absence of one or more deleveraging transaction discussed below, we do not anticipate compliance with the total leverage ratio covenant in our credit facility, beginning with the measurement date of March 31, 2019. The uncertainty related to our continued compliance with the financial covenants under our revolving credit facility raises substantial doubt regarding our ability to continue as a going concern. The consolidated financial statements do not reflect any adjustments that might result if we are unable to continue as a going concern.
In March 2019, our board of directors expanded the scope of the Special Committee to explore, in addition to an Exchange Transaction, other financing alternatives and deleveraging transactions, including without limitation (i) amendments or waivers to the covenants or other provisions of our revolving credit facility, (ii) raising new capital in private or public markets and (iii) restructuring our balance sheet either in court or through an out of court agreement with creditors. We are also considering operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives, including: (i) acquiring assets with existing production and cash flows by issuing preferred and common equity to finance such acquisitions; (ii) selling existing producing or midstream assets; (iii) merging with a strategic partner. The Special Committee has also re-commenced discussions with the Wilks regarding an Exchange Transaction and intends to continue those discussions as part of its review of financing alternatives and deleveraging transactions. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our credit facility covenants.
If an agreement is reached with our creditors and we pursue a restructuring, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in order to implement the agreement through the confirmation and consummation of a plan of reorganization approved by the bankruptcy court in the bankruptcy proceedings. We also may conclude that it is necessary to initiate Chapter 11 proceedings to implement a restructuring of our obligations even if we are unable to reach an agreement with our creditors and other relevant parties regarding the terms of such a restructuring. In either case, such a proceeding could be
commenced in the near term. If a plan of reorganization is implemented in a bankruptcy proceeding, it is possible that holders of claims and interests with respect to, or rights to acquire, our equity securities would be entitled to little or no recovery, and those claims and interests may be canceled for little or no consideration. If that were to occur, we anticipate that all or substantially all of the value of all investments in our equity securities would be lost and that our equity holders would lose all or substantially all of their investment. It is also possible that our other stakeholders, including our secured and unsecured creditors, will receive substantially less than the amount of their claims.
Our potential for restructuring transactions may impact our business, financial condition and operations.
Due to the potential for a restructuring of our balance sheet, there is risk that, among other things
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third parties lose confidence in our ability to continue to operate in the ordinary course, which could impact our ability to execute on our business strategy;
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it may become more difficult to attract, retain or replace key employees;
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employees could be distracted from performance of their duties;
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we could lose some or a significant portion of our liquidity, either due to stricter credit terms from vendors, or, in the event we undertake a Chapter 11 proceeding and conclude that we need to procure debtor-in-possession financing, an inability to obtain any needed debtor-in-possession financing or to provide adequate protection to certain secured lenders to permit us to access some or all of our cash; and
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our vendors, hedge counterparties, and service providers could seek to renegotiate the terms of our arrangements, terminate their relationship with us or require financial assurances from us.
Our lenders can limit our borrowing capabilities, which may materially impact our operations.
At December 31, 2018, we had $301.5 million in borrowings outstanding under our revolving credit facility, and our borrowing base was $325 million. The borrowing base under our revolving credit facility is redetermined semi-annually based upon a number of factors, including commodity prices and reserve levels. In addition to such semi-annual redeterminations, our lenders may request one additional redetermination during any 12-month period. Upon such redetermination, our borrowing base could be reduced, and if the amount outstanding under our revolving credit facility at any time exceeds the borrowing base at such time, we may be required to repay a portion of our outstanding borrowings. A downward redetermination would materially decrease our available liquidity, and if it causes our borrowings to exceed our borrowing base, we may not have sufficient liquidity to repay those amounts, which would result in an event of default under our revolving credit facility.
In the current commodity price environment, our borrowing base may be reduced following the upcoming semi-annual redetermination. We use cash flow from operations and bank borrowings to fund our exploration, development and acquisition activities. A reduction in our borrowing base could limit those activities. In addition, we may significantly change our capital structure to cover our working capital needs, make future acquisitions or develop our properties. Changes in capital structure may significantly increase our debt. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are beyond our control.
Our revolving credit facility borrowing base is subject to semi-annual redetermination, and current Office of the Comptroller of the Currency (“OCC”) guidelines may incentivize lenders to limit our borrowing capabilities.
In 2016, the OCC issued revised guidelines for exploration and production companies that specify target leverage metrics that we currently exceed. The lower a loan’s credit rating, the more reserves a bank must set aside. This makes it more expensive for the bank to keep a negatively-rated, or classified, loan on its books. We continue to operate with leverage in excess of OCC guidelines, which increases our risk of a negative semi-annual borrowing base redetermination, which could in turn materially decrease our liquidity or cause our borrowings to exceed our borrowing base and cause us to be in default under our credit agreement.
Our business requires significant capital expenditures, and we may not be able to obtain needed capital or financing on satisfactory terms or at all.
Our exploration, development and acquisition activities require substantial capital expenditures. For example, according to our year-end 2018 reserve report, the estimated future capital required to develop our current proved oil and gas reserves is approximately $1,034 million. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings under our revolving credit facility and public equity and debt financings. In 2018, we funded our capital expenditures primarily through cash flows from operations. Future cash flows are subject to a number of variables, including the production from existing wells, prices of oil, NGLs and gas and our success in developing and producing new reserves. If commodity prices fail to recover or further decrease from current levels, our cash flow from operations will not be sufficient to cover our current or future capital expenditure budgets, and we may have limited ability to obtain the additional capital necessary to fully develop our proved reserves. In addition, we may not be able to obtain debt or equity financing on favorable terms or at all. The failure to obtain additional financing could cause us to scale back our exploration and development operations, which in turn would lead to a decline in our oil and gas production and reserves, and in some areas a loss of properties.
Drilling, exploring for and producing oil and gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.
Our future financial condition and results of operations will depend on commodity prices and the success of our drilling, exploration and production activities. These factors are subject to numerous risks beyond our control, including the risk that drilling will not result in economic oil and gas production or increases in reserves. Many factors may curtail, delay or cancel our scheduled development projects, including:
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declines in oil, NGLs and gas prices;
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inadequate capital resources or liquidity to maintain current production levels or further develop our assets;
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compliance with governmental regulations, which may include limitations on hydraulic fracturing, access to water or the discharge of GHGs;
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limited transportation services and infrastructure to deliver the oil, NGLs and natural gas we produce to market;
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inability to attract and retain qualified personnel;
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unavailability or high cost of drilling and completion equipment, services or materials;
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unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents;
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lack of acceptable prospective acreage;
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adverse weather conditions;
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surface access restrictions;
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title problems;
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mechanical difficulties;
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natural disasters; and
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civil unrest or protest activities.
Oil, NGLs and gas prices are volatile and have fluctuated significantly in recent years. Sustained declines in oil, NGLs or gas prices would adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure requirements and financial commitments.
Our revenues, profitability and cash flow depend on the prices and demand for oil, NGLs and gas. The markets for these commodities are volatile, and even relatively modest drops in prices can affect significantly our financial results and impede our growth. Prices for oil, NGLs and gas fluctuate widely in response to changes in the
supply and demand for these commodities, market uncertainty and a variety of additional factors beyond our control, such as:
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domestic and foreign supply of oil, NGLs and gas;
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domestic and foreign consumer demand for oil, NGLs and gas;
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overall United States and global economic conditions impacting the global supply of and demand for oil, NGLs and gas;
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actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;
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commodity processing, gathering and transportation availability, the availability of refining capacity and other factors that result in differentials to benchmark prices;
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price and availability of alternative fuels;
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price and quantity of foreign imports;
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domestic and foreign governmental regulations;
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political conditions in or affecting other oil and natural gas producing countries;
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weather conditions, including unseasonably warm winter weather and tropical storms; and
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technological advances affecting oil, NGLs and gas consumption.
Advanced drilling and completion technologies, such as horizontal drilling and hydraulic fracturing, have resulted in increased investment by oil and gas producers in developing U.S. shale oil and gas projects and, therefore, has resulted in increased production from these projects. The results of higher investment in the exploration for and production of U.S. shale oil and gas, maintenance of production levels of oil from the Middle East, and other factors, such as global economic and financial conditions, have caused the price of oil and gas to be volatile. For example, prices for NYMEX-WTI ranged from a high of $76.41 per Bbl to a low of $42.53 per Bbl in 2018. NYMEX-Henry Hub natural gas prices ranged from a high of $4.84 per MMBtu to a low of $2.55 per MMBtu in 2018. Declines in oil and natural gas prices from current levels may further reduce our level of exploration, drilling and production activity and cash flows.
The Company’s financial position, results of operations, access to capital and the amount of oil and gas that may be economically produced would be negatively impacted if oil and gas prices fail to recover or further decrease from current levels for an extended period of time.
The ways that a continued depression in oil and gas prices could affect us include the following:
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Cash flows would be reduced, decreasing funds available for capital expenditures needed to maintain or increase production and replace reserves;
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We may breach covenants in our revolving credit facility;
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Future net cash flows from our properties would decrease, which could result in significant impairment expenses;
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Some reserves would no longer be economic to produce, leading to lower proved reserves, production and cash flows;
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Access to capital, such as equity or long-term debt markets and current reserve-based lending levels, would be severely limited or unavailable; and
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The borrowing base under our revolving credit facility could be reduced as further discussed below, and if the amount outstanding under our revolving credit facility exceeds the borrowing base, we may be required to repay a portion of our outstanding borrowings.
If commodity prices fail to recover or further decrease from current levels, our future cash flows will not be sufficient to fund the capital expenditure levels necessary to maintain current production and reserve levels over the long term and our results of operations will be adversely affected.
Low oil and gas prices not only cause our revenues and cash flows to decrease but also reduce the amount of oil and gas that we can produce economically. Decreases in oil and gas prices will render uneconomic some or all of our drilling locations. This may result in our having to impair our oil and gas properties further and could have a material adverse effect on our business, financial condition and results of operations. In addition, if oil, NGLs or gas prices further decline or fail to recover from their current levels for an extended period of time, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future debt or obtain additional capital on attractive terms, all of which can affect the value of our common stock. The amount available for borrowing under our revolving credit facility is subject to a borrowing base, which is determined by our lenders taking into account our estimated proved reserves and is subject to semi-annual redeterminations based on pricing models determined by the lenders at such time. The decline in oil and gas prices has adversely impacted the value of our estimated proved reserves and, in turn, the market values used by our lenders to determine our borrowing base.
If we cannot significantly reduce our leverage, or we cannot increase our liquidity, we may seek alternative refinancing transactions.
We have been actively engaged in the process of analyzing various options to address our leverage and liquidity as well as assessing our overall capital structure. In 2017, we successfully closed two debt-for-equity exchange transactions, which reduced the outstanding principal of our debt by $145.1 million. If we cannot continue to reduce our leverage with cash flow or through acquisitions, and if we cannot increase our liquidity, we may determine to evaluate additional transactions designed to reduce leverage and increase liquidity and operating cash flow. These transactions may not be advantageous to the existing holders of our common stock. Some of these alternatives may include additional debt buybacks, debt-for-debt or debt-for-equity exchanges or refinancings, strategic investments and joint ventures, sales of assets or working interests, private or public equity raises or rights offerings, restructuring our balance sheet either in court or through an out of court agreement with creditors, or transactions which may have a dilutive effect on our existing stockholders.
Wilks and its affiliates own a substantial portion of our outstanding common stock, and is entitled to appoint three of our directors, and thus it could exert certain significant influence over us, and their acquisition of additional common stock may cause a change in control.
As of January 31, 2019, Wilks beneficially owned 45,239,713 shares of our common stock, representing approximately 48% of our outstanding common stock. In addition, pursuant to our stockholders agreement with Wilks, Wilks is entitled to appoint three of the seven members of our board of directors. As a result, Wilks could exert certain significant influence over us. Wilks may have interests that do not align with our interests and with the interests of our stockholders, which could have an adverse impact on our results of operations. In addition, Wilks’ level of control may make any potential takeover bids more costly or difficult in the future. Further, although Wilks is currently subject to a stockholders agreement that, among other things, caps their share ownership at 48.61% of our outstanding common stock, Wilks’ acquisition of more than 50% of our outstanding common stock would trigger change in control provisions in Company agreements, potentially causing severance payments to become due or the vesting of shares of common stock awards to be accelerated, and could cause a default under our revolving credit facility if the consent of certain lenders is not obtained, which could adversely affect the Company.
We may not be able to generate enough cash flow to meet our debt obligations.
We expect our earnings and cash flow to vary significantly from year to year due to the nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. Additionally, our future cash flow may be insufficient to meet our debt obligations and other commitments, including our obligations under our $85.2 million principal amount of 7% Senior Notes due 2021 and $301.5 million in outstanding borrowings under our revolving credit facility. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy and initiatives of our competitors, are beyond our control. If we do not
generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
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selling assets;
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reducing or delaying capital investments;
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seeking to raise additional capital, potentially in a manner dilutive to our existing stockholders; or
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refinancing or restructuring our remaining debt.
If, for any reason, we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors at that time to declare all outstanding indebtedness to be due and payable, which could in turn trigger cross-acceleration or cross-default rights between the relevant agreements. In addition, our lenders could compel us to apply all of our available cash to repay our borrowings, or they could prevent us from making payments on the Senior Notes. If amounts outstanding under our revolving credit facility or the Senior Notes were to be accelerated, we cannot be certain that our assets would be sufficient to repay in full the money owed to the lenders or to our other debt holders.
Our revolving credit facility contains operating and financial restrictions and covenants that may restrict our business and financing activities or that economic conditions and commodity prices may cause us to breach.
Our revolving credit facility contains, and any future indebtedness we incur may contain, a number of restrictive covenants that will impose significant operating and financial restrictions on us, including restrictions on our ability to, among other things:
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sell assets, including equity interests in our subsidiaries;
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consolidate, merge or transfer all or substantially all of our assets;
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incur or guarantee additional indebtedness or issue preferred stock;
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redeem or prepay other debt;
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pay distributions on, redeem or repurchase our common stock or redeem or repurchase our subordinated debt;
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create or incur certain liens;
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make certain acquisitions and investments;
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enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
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engage in transactions with affiliates;
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create unrestricted subsidiaries;
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enter into financing transactions; and
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engage in certain business activities.
As a result of these covenants, we will be limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs.
Our revolving credit facility also contains financial covenants. Our ability to comply with some of the covenants and restrictions contained in our revolving credit facility may be affected by events beyond our control. If commodity prices fail to recover or further decrease from current levels, or if we are unable to reduce our leverage, our ability to comply with these covenants may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility, or any future indebtedness could result in an event of default, which, if not cured or waived, would have a material adverse effect on our business, financial condition and results of operations. If an event of default under our revolving credit facility occurs and remains uncured, the lenders:
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would not be required to lend any additional amounts to us;
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could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;
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may have the ability to require us to apply all of our available cash to repay these borrowings; or
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may prevent us from making debt service payments under our other agreements.
If our stock price trades below $1.00 for 30 consecutive business days, our common stock may be subject to delisting from the NASDAQ Global Select Market.
If at any time the bid price of our common stock closes at below $1.00 per share for more than 30 consecutive trading days, we may be subject to delisting from the NASDAQ Global Select Market. If we receive a delisting notice, we would have 180 calendar days to regain compliance, which would mean having a bid price above the minimum of $1.00 for at least 10 consecutive days in the 180-day period. During this 180-day period, we would anticipate reviewing our options to regain compliance with the minimum bid requirements, including conducting a reverse stock split. To the extent that we are unable to resolve the listing deficiency, there is a risk that our common stock may be delisted from NASDAQ, which would adversely impact liquidity of our common stock and potentially result in even lower bid prices for our common stock. As of March 13, 2019, our stock had traded at a 52 week low of $0.83 per share, and a 52 week high of $3.26 per share. Our closing share price on March 13, 2019, was $1.06.
Increases in interest rates could adversely affect our business, results of operations, cash flows from operations and financial condition.
Since all of the indebtedness outstanding under our revolving credit facility is at variable interest rates, we have significant exposure to increases in interest rates. As a result, our business, results of operations and cash flows may be adversely affected by significant increases in interest rates.
If commodity prices decline to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to write down the carrying values of our properties. Additionally, current SEC rules also could require us to write down our proved undeveloped reserves in the future.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down is a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. The risk that we will be required to write down the carrying value of our properties increases when oil and gas prices are low or volatile.
In addition, current SEC rules require that proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years, unless specific circumstances justify a longer time. This rule may limit our potential to book additional proved undeveloped reserves as we pursue our development projects. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill those wells within the required timeframe or if commodity prices cause us to change our development plan to decrease the number of wells to be drilled over the five-year period. For example, for the year ended December 31, 2018, we reclassified
33.1 MMBoe of proved reserves to unproved reserves attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules.
The estimated volumes, standardized measure and present value of future net revenues (“PV-10”) from our proved reserves as of December 31, 2018, should not be considered as the current market value of the estimated oil and gas reserves attributable to our properties.
Standardized measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. On December 31, 2018, our standardized measure of discounted cash flows was $660 million. Standardized measure requires the use of specific pricing as required by the SEC as well as operating and development costs prevailing as of the date of computation. The non-GAAP financial measure, PV-10, is based on the average of the closing price on the first day of the month for the 12-month period prior to fiscal year end, while actual future prices and costs may be materially higher or lower.
Our estimated proved reserves as of December 31, 2018, and related standardized measure and PV-10, were calculated under the SEC rules using 12-month trailing average benchmark prices of $65.68 per Bbl of oil, $24.12 per Bbl of NGLs and $3.17 per MMBtu of gas. If oil, NGLs and gas prices decline by 10% from $65.68 per Bbl of oil, $24.12 per Bbl of NGLs and $3.17 per MMBtu of gas, to $59.11 per Bbl of oil, $21.71 per Bbl of NGLs and $2.85 per MMBtu of gas, then our PV-10 as of December 31, 2018, would decrease from $761.8 million to approximately $566.3 million. Actual future net revenues also will be affected by factors such as the amount and timing of actual production, prevailing operating and development costs, supply and demand for oil and gas, increases or decreases in consumption and changes in governmental regulations or taxation. For a reconciliation of PV-10, a measure not calculated in accordance with GAAP, to our standardized measure of discounted future cash flows and related disclosures, see “Reconciliation of PV-10 to Standardized Measure.”
Consequently, these measures may not reflect the prices ordinarily received or that will be received for oil and gas production because of varying market conditions, nor may they reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates of future net cash flow may be materially different from the future net cash flows that are ultimately received. Therefore, the standardized measure of our estimated reserves and PV-10 included in this report should not be construed as accurate estimates of the current fair value of our proved reserves. In addition, the 10% discount factor we use when calculating PV-10 may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
The issuance of shares in the future could reduce the market price of our common stock.
In the future, we may issue common stock or other securities to raise cash for further debt and leverage reduction, working capital, acquisitions or hiring and retaining employees. We also may acquire interests in other companies by using a combination of cash and our common stock or just our common stock. We also may issue securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share and have an adverse impact on the price of our common stock. In addition, sales or issuances of a substantial amount of our common stock, or the perception that these sales or issuances may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities.
Our stock price has been and could remain volatile, which further could adversely affect the market price of our stock and our ability to raise additional capital and cause us to be subject to securities class action litigation.
The market price of our common stock has experienced and may continue to experience significant volatility. In 2018, the price of our common stock fluctuated from a high of $4.21 per share to a low of $0.83 per share. In addition, in recent years, the stock market has experienced significant price and volume fluctuations. This volatility has affected the market prices of securities issued by many companies in the energy sector, and particularly in the upstream sector. Such market price volatility could adversely affect our ability to raise additional capital. In addition, we may be subject to securities class action litigation as a result of the decline in the price of our common
stock, which could result in substantial costs and diversion of management’s attention and resources and could harm our stock price, business, prospects, results of operations and financial condition.
We may experience differentials to benchmark prices in the future, which may be material.
Substantially all of our production is sold to purchasers at prices that reflect a discount to other relevant benchmark prices, such as NYMEX-WTI or NYMEX-Henry Hub. The price we receive for the majority of our natural gas is based on the price received by our third party midstream purchaser. Our third party midstream purchaser sells most of our natural gas at the WAHA hub in West Texas. The difference between a benchmark price and the price we reference in our sales contracts is called a basis differential. Basis differentials result from variances in regional prices compared to benchmark prices as a result of regional supply and demand factors. For example, the WAHA index price in December 2018 was $3.76 per MMBtu lower than the NYMEX-Henry Hub price. We may experience differentials to benchmark prices in the future, which may have a material adverse effect on our business and financial condition.
We engage in commodity derivative transactions which involve risks that can harm our business.
To manage our exposure to price risks in the marketing of our production, we enter into commodity derivative agreements. While intended to reduce the effects of volatile commodity prices, such transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the commodity derivative. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which our production is lower than expected. We are also exposed to the risk of non-performance by the counterparties to the commodity derivative agreements.
Due to the enactment of the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”), the derivative transactions we execute are undertaken in a highly regulated market. While many of the rules implementing the Dodd-Frank statute are in place at this time, some significant components of the Dodd-Frank regulatory regime remain subject to rulemaking by the Commodity Futures Trading Commission and other regulators.
Although we have hedged a portion of our estimated 2019 production, our hedging program may be inadequate to protect us against continuing and prolonged declines in the price of oil and natural gas.
Currently, we have commodity price derivative agreements for 2019 production on approximately (i) 182,500 Bbls of oil with collars at a weighted average floor price of $65.00 per Bbl and a weighted average ceiling price of $71.00 per Bbl, and (ii) 239,575 BBls of NGLs at weighted average prices of $14.12 per Bbl (C2-ethane), $36.54 per Bbl (C3-propane), $38.63 per Bbl (NC4-butane) and $65.21 per Bbl (C5-Pentane). These derivative contracts will not protect us from a continuing and prolonged decline in the price of oil and natural gas for the unhedged portion of our production in 2019 or our production after 2019. To the extent that the prices for oil and gas decline, we will not be able to hedge future production at the same level as our current hedges, and our results of operations and financial condition would be negatively impacted.
We are subject to complex governmental laws and regulations that may adversely affect the cost, manner and feasibility of doing business.
Our oil and gas drilling, production and gathering operations are subject to complex and stringent laws and regulations. To operate in compliance with these laws and regulations, we must obtain and maintain numerous permits and approvals from various federal, state and local governmental authorities. We may incur substantial costs to comply with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations apply to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations. Failure to comply with laws and regulations applicable to our operations, including any evolving interpretation and enforcement by government authorities, could have a material adverse effect on our business, financial condition and results of operations. See “Business - Regulation” for a further description of the laws and regulations that affect us.
Federal and state legislation and regulatory initiatives and private litigation relating to hydraulic fracturing could stop or delay our development project and result in materially increased costs and additional operating restrictions.
All of our proved undeveloped reserves associated with future drilling and completion projects will require hydraulic fracturing. See Item 1. “Business - Hydraulic Fracturing” for a discussion of the importance of hydraulic fracturing to our business, and Item 1. “Business - Regulation -Hydraulic Fracturing” for a discussion of regulatory developments regarding hydraulic fracturing. If these or any other new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to drill and produce from our proved reserves, as well as make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings. In addition, if hydraulic fracturing is regulated at the federal level, fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also permitting delays and increases in costs. The EPA and other federal agencies, including the United States Bureau of Land Management (“BLM”), have in recent years made proposals that would subject hydraulic fracturing to further regulation and could restrict the practice of hydraulic fracturing. For example, the EPA has issued final regulations under the federal CAA establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing, and, in 2016, the EPA finalized regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Several of the EPA’s and the BLM’s recently promulgated rules concerning regulation of hydraulic fracturing are in various stages of suspension, implementation delay, rescission and court challenges; therefore, the future of these rules is uncertain. The EPA also released a study in December 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. However, several states have adopted, and more states are considering adopting, laws and/or regulations that require disclosure of chemicals used in hydraulic fracturing and impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations. In addition, some states and municipalities have significantly limited drilling activities and/or hydraulic fracturing, or are considering doing so. Although it is not possible at this time to predict the final outcome of these proposals or court challenges to existing rules or proposed rules, any new federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could cause us to incur substantial compliance costs, and compliance or the consequences of our failure to comply could have a material adverse effect on our financial condition and results of operations. In addition, if we are unable to use hydraulic fracturing in completing our wells or hydraulic fracturing becomes prohibited or significantly regulated or restricted, we could lose the ability to drill and complete the projects for our proved reserves and maintain our current leasehold acreage, which would have a material adverse effect on our future business, financial condition and results of operations.
The unavailability or high cost of drilling rigs, equipment, materials, personnel and oilfield services could adversely affect our ability to execute our drilling and development plans on a timely basis and within our budget.
Our industry is cyclical, and, from time-to-time, during periods of improving and high commodity prices, there is a shortage of drilling rigs, hydraulic fracturing services, equipment, supplies or qualified service personnel. During these periods, the costs and delivery times of equipment, oilfield services and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling and completion crews rise as the number of active rigs in service increases. Increasing levels of exploration and production will increase the demand for oilfield services, and the costs of these services may increase, while the quality of these services may suffer. If the availability of equipment, crews, materials and services in the Permian Basin is particularly severe, our business, results of operations and financial condition could be materially and adversely affected because our operations and properties are concentrated in the Permian Basin.
Our operations substantially depend on the availability of water. Restrictions on our ability to obtain, dispose of or recycle water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner.
Water is an essential component of our drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local landowners and other sources for use in our operations. From 2011 through 2014, West Texas experienced extreme drought conditions. As a result of the severe drought, governmental authorities restricted the use of water subject to their jurisdiction for drilling and hydraulic fracturing to protect the local water supply. Although such restrictions have been lifted, if West Texas experiences further drought conditions, the restrictions may return. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil, NGLs and gas, which could have an adverse effect on our business, financial condition and results of operations.
Moreover, new environmental initiatives and regulations could include restrictions on disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas. For example, in 2014, the RRC published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. In 2016, the United States Geological Survey identified several states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Furthermore, ongoing lawsuits allege that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by the Company or by commercial disposal well vendors whom the Company may use from time to time to dispose of produced water. Compliance with water right laws, environmental regulations and permit requirements for the disposal, withdrawal, storage and use of surface water or ground water necessary for hydraulic fracturing may increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition and results of operations.
Conservation measures and technological advances could reduce demand for oil and gas.
Fuel conservation measures, alternative fuel requirements, increasing interest in alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and gas. The impact of the changing demand for oil and gas may have a material adverse effect on our business, financial condition and results of operations.
Climate change legislation or regulations regulating emissions of GHGs and VOCs could result in increased operating costs and reduced demand for the oil and gas we produce.
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, the EPA adopted regulations that restrict emissions of GHGs under existing provisions of the federal CAA. The EPA also issued final regulations under the NSPS and NESHAP designed to reduce VOCs, including methane. See Item 1. “Business - Regulation - Environmental Laws and Regulations - Greenhouse Gas Emissions” and “ - Air Emissions” for a discussion of regulatory developments regarding GHG and VOC emissions.
While Congress has from time-to-time considered legislation to reduce emissions of GHGs, and as recently as February 2019 a resolution referred to as the Green New Deal was introduced in the U.S. House of Representatives, no significant legislation has been adopted to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of GHG cap-and-trade programs. Most of these cap-and-trade programs require either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances are expected to escalate significantly in cost over time.
In 2016, the EPA issued a final Information Collection Request seeking information about methane emissions from facilities and operators in the oil and gas industry. The EPA indicated that it intended to use the information from this request to develop Existing Source Performance Standards for the oil and gas industry or to develop standards for certain kinds of new and modified equipment and facilities not currently covered under the NSPS. Although the EPA rescinded the Information Collection Request in March 2017, the EPA could take additional actions to collect such information from individual operators or from the industry as a whole and rely upon such information as the basis for regulation of GHG emission from the oil and gas industry.
The adoption of legislation or regulatory programs to reduce GHG or VOC emissions or to incentivize the generation of power from renewable energy sources could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements, and may reduce demand for oil and gas we produce. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG or VOC emissions could have a material adverse effect on our business, financial condition and results of operations.
Environmental laws and regulations may expose us to significant costs and liabilities.
There is inherent risk of incurring significant environmental costs and liabilities in our oil and gas operations due to the handling of petroleum hydrocarbons and generated wastes, the occurrence of air emissions and water discharges from work-related activities and the legacy of pollution from historical industry operations and waste disposal practices. We may incur joint and several or strict liability under these environmental laws and regulations in connection with spills, leaks or releases of petroleum hydrocarbons and wastes on, under or from our properties and facilities, some of which have been used for exploration, production or development activities for many years and by third parties not under our control. In particular, the number of private, civil lawsuits involving hydraulic fracturing has risen in recent years. Since 2009, multiple private lawsuits alleging ground water contamination have been filed in the U.S. against oil and gas companies, primarily by landowners who leased oil and gas rights to defendants, or by landowners who live close to areas where hydraulic fracturing has taken place. In addition, changes in environmental laws and regulations occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition and results of operations. We may not be able to recover some or any of these costs from insurance.
Our ability to use our federal net operating loss carryforwards (“NOLs”) to offset future taxable income may be subject to certain limitations.
Under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), a corporation that undergoes an “ownership change” is subject to limitations on its ability to use its pre-change NOLs to offset future taxable income. As a result of the completed debt-for-equity exchange transactions, we underwent an ownership change under Section 382 as of March 22, 2017, which resulted in an annual limitation on our ability to use our pre-change NOLs to offset future taxable income recognized after such date. Accordingly, we reduced our NOL deferred tax assets by $139.1 million.
U.S. federal income tax reform could adversely affect us.
On December 22, 2017, President Trump signed into law the Tax Cuts and Jobs Act (the “TCJA”) that significantly reforms the Code. The TCJA, among other things, includes changes to U.S. federal tax rates and allows for the expensing of capital expenditures. While past legislative proposals have included changes to certain key U.S. federal income tax provisions currently available to oil and gas companies including (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, and (iii) an extension of the amortization period for certain geological and geophysical expenditures, these specific changes are not included in the TCJA. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. However, the TCJA (i) eliminates the deduction for certain domestic production activities, (ii) imposes new limitations on the use of NOLs, (iii) limits the deductibility of performance based compensation to executive officers and (iv) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and significant additional limitations on the deductibility of interest, which may impact the taxation of oil and gas companies. This legislation or any future changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations, and cash flows.
We do not expect tax reform to have a material impact to our projection of cash taxes or to our NOLs. Our net deferred tax assets and liabilities have been revalued at the newly enacted U.S. corporate rate, and the impact was recognized in our tax expense in the year of enactment. We continue to examine the impact this tax reform legislation may have on our business. The impact of this tax reform on holders of our common stock is uncertain and could be adverse.
Our future reserve and production growth depends on the success of our horizontal Wolfcamp oil shale resource play, which has a limited operational history and is subject to change.
We began drilling horizontal wells in the Wolfcamp play in late 2010. The wells that have been drilled or recompleted in these areas represent a small sample of our large acreage position, and we cannot assure you that our new wells will be successful. We continue to gather data about our prospects in the Wolfcamp play, and it is possible that additional information may cause us to change our drilling schedule or determine that prospects in some portion of our acreage position should not be developed at all.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve using some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include, but are not limited to:
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landing our wellbore in the desired drilling zone;
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staying in the desired drilling zone while drilling horizontally through the formation;
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running our casing the entire length of the wellbore; and
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being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that we face while completing our wells include, but are not limited to:
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the ability to fracture stimulate the planned number of stages;
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the ability to run tools the entire length of the wellbore during completion operations; and
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the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
The results of our drilling in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling
results in these areas. If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as we anticipated and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
Failure to effectively execute and manage our single major development project, Project Pangea, could result in significant delays, cost overruns, limitation of our growth, damage to our reputation and a material adverse effect on our business, financial condition and results of operations.
We believe we have an extensive inventory of identified drilling locations in our development project (Project Pangea) in the Wolfcamp shale oil resource play; however, Project Pangea is our core asset and our only development project. As we achieve more results in Project Pangea, we have expanded our horizontal development project there. This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal operating and financial controls. Our ability to successfully develop and manage this project will depend on, among other things:
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our ability to finance development of the project;
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the extent of our success in drilling and completing horizontal Wolfcamp wells;
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our ability to control costs and manage drilling and completion risks;
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our ability to attract, retain and train qualified personnel with the skills required to develop the project in a timely and cost-effective manner; and
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our ability to implement and maintain effective operating and financial controls and reporting systems necessary to develop and operate the project.
We may not be able to compensate for, or fully mitigate, these risks.
Currently, substantially all of our producing properties are located in two counties in Texas, making us vulnerable to risks associated with operating in one primary area.
Substantially all of our producing properties and estimated proved reserves are concentrated in Crockett and Schleicher Counties, Texas. As a result of this concentration, we are disproportionately exposed to the natural decline of production from these fields as well as the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailments of production, service delays, natural disasters or other events that impact this area.
Because of our geographic concentration, our purchaser base is limited, and the loss of one of our key purchasers or their inability to take our oil, NGLs or gas could adversely affect our financial results.
In 2018, AMID and DCP collectively accounted for 97% of our total oil, NGLs and gas sales, excluding realized commodity derivative settlements. As of December 31, 2018, we had dedicated the majority of our oil production from northern Project Pangea and Pangea West through September 2022 to AMID. In addition, as of December 31, 2018, we had dedicated the majority of our NGLs and natural gas production from Project Pangea to DCP through August 2023. To the extent that any of our major purchasers reduces their purchases of oil, NGLs or gas, is unable to take our oil, NGLs or gas due to infrastructure or capacity limitations or defaults on their obligations to us, we would be adversely affected unless we were able to make comparably favorable arrangements with other purchasers. These purchasers’ default or non-performance could be caused by factors beyond our control. A default could occur as a result of circumstances relating directly to one or more of these customers or due to circumstances related to other market participants with which the customer has a direct or indirect relationship.
We depend on our management team and other key personnel. The loss of these individuals without adequate replacement, or the inability to attract, train and retain additional qualified personnel, could adversely affect our business, financial condition and the results of operations and future growth.
Our success largely depends on the skills, experience and efforts of our management team and other key personnel and the ability to attract, train and retain additional qualified personnel. The loss of the services of one or more members of our senior management team or of our other employees with critical skills needed to operate our business could have a negative effect on our business, financial condition, results of operations and future growth. We maintain employment agreements with J. Ross Craft, P.E., our Chairman and Chief Executive Officer, Sergei Krylov, our Executive Vice President and Chief Financial Officer, Qingming Yang, our President and Chief Operating Officer, and J. Curtis Henderson, our Chief Administrative Officer. We are currently engaged in discussions with our Chief Executive Officer regarding his departure from the Company. We also expect to engage in discussions with our President and Chief Administrative Officer regarding their employment with the Company, which may include discussions regarding potential departures. If any of these officers or other key personnel depart and are not adequately replaced, our business operations could be materially adversely affected. In addition, our ability to manage our growth, if any, will require us to effectively train, motivate and manage our existing employees and to attract, motivate and retain additional qualified personnel Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.
Market conditions or transportation and infrastructure impediments may hinder our access to oil, NGLs and gas markets or delay our production or sales.
Market conditions or the unavailability of satisfactory oil, NGLs and gas processing and transportation services and infrastructure may hinder our access to oil, NGLs and gas markets or delay our production or sales. Although currently we control the gathering systems for our operations in the Permian Basin, we do not have such control over the regional or downstream pipelines in and out of the Permian Basin. The availability of a ready market for our oil, NGLs and gas production depends on a number of factors, including market demand and the proximity of our reserves to pipelines or trucking and rail terminal facilities.
In addition, the amount of oil, NGLs and gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to maintenance, excessive line pressure, excessive vapor pressure, ability of downstream processing facilities to accept unprocessed gas or NGLs, physical damage or operational interruptions to the gathering or transportation system or downstream processing and fractionation facilities or lack of contracted capacity on such systems or facilities.
The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we are provided with limited, if any, notice as to when these circumstances will arise and their duration. As a result, we may not be able to sell, or may have to transport by more expensive means, the oil, NGLs and gas that we produce, or we may be required to shut in oil or gas wells or delay initial production until the necessary gathering and transportation systems are available. Any significant curtailment in gathering systems, transportation, pipeline capacity or significant delay in construction of necessary gathering and transportation facilities, could adversely affect our business, financial condition and results of operations.
Loss of our information and computer systems could adversely affect our business, financial condition and results of operations.
We heavily depend on our information systems and computer-based programs, including drilling, completion and production data, seismic data, electronic data processing and accounting data. If any of these programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil, NGLs and gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. In addition, the U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. A cyber incident involving our information systems and related infrastructure could disrupt our business plans and result in information theft, unauthorized access to confidential or otherwise sensitive information, data corruption, operational disruption and/or financial loss. Any such consequence could have a material adverse effect on our business, financial condition and results of operations. In addition, the Company's implementation of various procedures and controls to monitor and mitigate security threats and to increase security for the Company's information, facilities and infrastructure may result in increased capital and operating costs. Costs for insurance may also increase as a result of security threats, and some insurance coverage may become more difficult to obtain, if available at all. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring.
Competition in the oil and gas industry is intense, and many of our competitors have resources that are greater than ours.
We operate in a highly competitive environment for acquiring prospects and productive properties, marketing oil and gas and securing equipment and skilled personnel. Many of our competitors are major and large independent oil and gas companies that have financial, technical and personnel resources substantially greater than ours. Those companies may be able to develop and acquire more prospects and productive properties than our financial or personnel resources permit. Our ability to develop and operate our current project, acquire additional prospects and discover reserves in the future will depend on our ability to hire and retain qualified personnel, evaluate and select suitable properties and consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and gas industry. Larger competitors may be better able to withstand sustained periods of low commodity prices and unsuccessful drilling and absorb the burden of changes in laws and regulations more easily than we can, which would adversely affect our competitive position. We may not be able to compete successfully in the future in attracting and retaining qualified personnel, acquiring prospective reserves, developing reserves, marketing oil, NGLs and gas and raising additional capital.
Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. In certain instances, this could prevent drilling and production before the expiration date of leases for such locations.
Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil, NGLs and gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system, marketing and transportation constraints, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or gas from these or any other identified drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are obtained, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
The use of geoscientific, petrophysical and engineering analyses and other technical or operating data to evaluate drilling prospects is uncertain and does not guarantee drilling success or recovery of economically producible reserves.
Our decisions to explore, develop and acquire prospects or properties targeting Wolfcamp and other zones in the Permian Basin and other areas depend on data obtained through geoscientific, petrophysical and engineering analyses, the results of which can be uncertain. Even when properly used and interpreted, data from whole cores, regional well log analyses, 3-D seismic and micro-seismic only assist our technical team in identifying hydrocarbon indicators and subsurface structures and estimating hydrocarbons in place. They do not allow us to know conclusively the amount of hydrocarbons in place and if those hydrocarbons are producible economically. In addition, the use of advanced drilling and completion technologies for our Wolfcamp development, such as horizontal drilling and multi-stage fracture stimulations, requires greater expenditures than our traditional development drilling strategies. Our ability to commercially recover and produce the hydrocarbons that we believe are in place and attributable to the Wolfcamp and other zones will depend on the effective use of advanced drilling and completion techniques, the scope of our development project (which will be directly affected by the availability of capital), drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, regulatory approval and geological and mechanical factors affecting recovery rates. Our estimates of unproved reserves, estimated ultimate recoveries per well, hydrocarbons in place and resource potential may change significantly as development of our oil and gas assets provides additional data.
Unless we replace our oil and gas reserves, our reserves and production will decline.
Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues and cash flows will be adversely affected. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Our total proved reserves will decline as reserves are produced, unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves.
We have leases for undeveloped acreage that may expire in the near future.
As of December 31, 2018, we held mineral leases in each of our areas of operation that are still within their original lease term and are not currently held by production. Leases not held by production represent 42% of our net acreage, and 1% of our proved undeveloped reserves. Unless we continue to develop and produce on the properties subject to these leases, these leases may expire in 2019. If these leases expire, we will lose our right to develop the related properties, unless we renew such leases. In addition, many of our leases may be terminated if we fail to meet our continuous development obligations thereunder. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. See Item 2. “Properties - Undeveloped Acreage Expirations” for a table summarizing the expiration schedule of our undeveloped acreage expiring based on contractual lease maturities over the next three years.
Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of our proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve reports. These differences may be material.
The proved oil, NGLs and gas reserves data included in this report are estimates. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil, NGLs and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:
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historical production from the area compared with production from other similar producing areas;
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the assumed effects of regulations by governmental agencies;
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assumptions concerning future oil, NGLs and gas prices; and
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assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.
Because all reserves estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:
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the quantities of oil, NGLs and gas that are ultimately recovered;
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the production and operating costs incurred;
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the amount and timing of future development expenditures; and
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future oil, NGLs and gas prices.
As of December 31, 2018, approximately 63% of our proved reserves were proved undeveloped. Estimates of proved undeveloped reserves are even less reliable than estimates of proved developed reserves. Furthermore, different reserve engineers may make different estimates of reserves and future net revenues based on the same available data. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future, we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
Severe weather could have a material adverse impact on our business.
Our business could be materially and adversely affected by severe weather. For example, our production volumes for the three months ended September 30, 2017, were adversely impacted by Hurricane Harvey, as the main purchaser of our NGLs and natural gas had to temporarily shut in or curtail receipt of NGLs and natural gas at multiple processing plants in the Permian Basin. Additional repercussions of severe weather conditions may include:
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curtailment of services, including oil, NGLs and gas pipelines, processing plants and trucking services;
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weather-related damage to drilling rigs, resulting in a temporary suspension of operations;
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weather-related damage to our producing wells or facilities;
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inability to deliver materials to jobsites in accordance with contract schedules; and
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loss of production.
Operating hazards or other interruptions of our operations could result in potential liabilities, which may not be fully covered by our insurance.
The oil and gas business involves certain operating hazards such as well blowouts, cratering, explosions, uncontrollable flows of gas, oil or well fluids, fires, surface and subsurface pollution and contamination, and releases of toxic gas. The occurrence of one of the above may result in injury, loss of life, suspension of operations, environmental damage and remediation and/or governmental investigations and penalties. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution, with broader coverage for sudden and accidental occurrences. Our insurance might be inadequate to cover our liabilities. The insurance market, in general, and the energy insurance market, in particular, have been difficult markets over the past several years. Insurance costs are expected to continue to increase over the next few years, and we may decrease coverage and retain more risk to mitigate future cost increases. If we incur substantial liability and the damages are not covered by insurance or are in excess of policy limits, or if we incur liability at a time when we are not able to obtain liability insurance, then our business, results of operations and financial condition could be materially adversely affected.
Our results are subject to quarterly and seasonal fluctuations.
Our quarterly operating results have fluctuated in the past and could be negatively impacted in the future as a result of a number of factors, including seasonal variations in oil, NGLs and gas prices, variations in levels of production and the completion of development projects.
We have renounced any interest in specified business opportunities, and certain members of our board of directors and certain of our stockholders generally have no obligation to offer us those opportunities.
In accordance with Delaware law, we have renounced any interest or expectancy in any business opportunity, transaction or other matter in which our outside directors and certain of our stockholders, each referred to as a Designated Party, participates or desires to participate in, that involves any aspect of the exploration and production business in the oil and gas industry. If any such business opportunity is presented to a Designated Party who also serves as a member of our board of directors, the Designated Party has no obligation to communicate or offer that opportunity to us, and the Designated Party may pursue the opportunity as he sees fit, unless:
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it was presented to the Designated Party solely in that person’s capacity as a director of our Company and with respect to which, at the time of such presentment, no other Designated Party has independently received notice of, or otherwise identified the business opportunity; or
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the opportunity was identified by the Designated Party solely through the disclosure of information by or on behalf of us.
As a result of this renunciation, our outside directors should not be deemed to have breached any fiduciary duty to us if they or their affiliates or associates pursue opportunities as described above and our future competitive position and growth potential could be adversely affected.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
As of the date of this filing, we have no unresolved comments from the staff of the SEC.
ITEM 2.
ITEM 2.
PROPERTIES
Permian Basin - Project Pangea
Our properties in the Permian Basin are located in Crockett and Schleicher Counties, Texas. We began operations in the Permian Basin through a farm-in agreement for 27,000 net acres in 2004 and have since increased our total acreage position to approximately 165,000 gross (150,000 net) acres as of year-end 2018. At December 31, 2018, we owned interests in approximately 813 gross (801 net) wells, all of which we operate. As of December 31, 2018, we had working and net revenue interests of approximately 98.5% and 76%, respectively, across Project Pangea.
Our acreage position in the Permian Basin is characterized by several commercial hydrocarbon zones, including the Clearfork, Dean, Wolfcamp shale, Canyon Sands, Strawn and Ellenburger zones. When we began drilling our Permian Basin properties in 2004, we targeted the Canyon Sands, Strawn and Ellenburger zones at depths ranging from 7,250 feet to 8,900 feet with vertical wells.
In 2010, we performed a detailed geological and petrophysical evaluation of the Clearfork, Dean and Wolfcamp shale formations above the Canyon Sands, Strawn and Ellenburger, and in 2010, we began drilling horizontal wells targeting the Wolfcamp shale. The Wolfcamp shale is a source rock that we believe has significant potential for hydrocarbons. The Wolfcamp shale is located in the oil-to-wet gas window across our Permian acreage position and is naturally fractured due to its proximity to the Ouachita-Marathon thrust belt and mineralogy, specifically the carbonate and quartz minerals.
The Wolfcamp shale has gross pay thickness of approximately 1,000 to 1,200 feet across our acreage position, which allows for horizontal drilling and stacked horizontal wellbores targeting varied zones that we call “benches.” We believe effectively developing the Wolfcamp shale may involve up to three lateral wellbores, each targeting a different bench, which we refer to as the Wolfcamp A, B and C. Since we began drilling horizontal Wolfcamp wells in 2011 through December 31, 2018, we have drilled and completed a total of 25 wells targeting the Wolfcamp A bench, 115 wells targeting the Wolfcamp B bench and 56 wells targeting the Wolfcamp C bench. As of December 31, 2018, estimated proved reserves attributable to the horizontal Wolfcamp shale oil play accounted for 93% of our total proved reserves.
During 2018, we incurred costs of approximately $39.4 million to drill six, and complete nine, horizontal Wolfcamp wells. At December 31, 2018, we had seven horizontal Wolfcamp wells waiting on completion. We currently have no rigs running in Project Pangea, but in 2019, we plan to operate one rig on an intermittent basis during the year.
East Texas Basin - North Bald Prairie
In 2007, we entered into a joint venture with EnCana Oil & Gas (USA) Inc. (“EnCana”) in Limestone and Robertson Counties, Texas, in the East Texas Cotton Valley trend. We currently have nine gross producing gas wells. We have a 50% working interest and approximately 40% net revenue interest in the approximately 3,000 gross (2,000 net) acre project. In 2012, EnCana assigned its interest in the project to a third party. As of December 31, 2018, we had estimated proved reserves of 825 MMcf in North Bald Prairie. Our primary targets in North Bald Prairie are the Cotton Valley Sands and Cotton Valley Lime. We currently have no rigs running in North Bald Prairie.
Proved Oil and Gas Reserves
The following table sets forth summary information regarding our estimated proved reserves as of December 31, 2018. See Note 10 to our consolidated financial statements in this report for additional information. Our reserve estimates and our calculation of standardized measure and PV-10 are based on the 12-month average of the first-day-of-the-month pricing of $65.68 per Bbl West Texas Intermediate posted oil price, $24.12 per Bbl received for NGLs and $3.17 per MMBtu Henry Hub spot natural gas price during 2018. All prices were adjusted for energy content, quality and basis differentials by area and were held constant through the lives of the properties. Natural gas is converted at a rate of six Mcf of gas to one barrel of oil equivalent (“Boe”). NGLs are converted at a rate of one barrel of NGLs to one Boe. The ratios of six Mcf of gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe of natural gas or NGLs may differ significantly from the price of a barrel of oil. The information in the following table is not intended to represent the current market value of our proved reserves nor does it give any effect to or reflect our commodity derivatives or current commodity prices.
Summary of Oil and Gas Reserves as of Fiscal-Year End
Based on Average Fiscal-Year Prices
(1)
The gas reserves contain 56,172 MMcf of gas that will be produced and used as field fuel (primarily for compressors and artificial lifts) before the gas is delivered to a sales point.
(2)
See “Reconciliation of PV-10 to Standardized Measure” below for a reconciliation of PV-10 to the standardized measure.
Our estimated total proved reserves of oil, NGLs and natural gas as of December 31, 2018, were 180.1 MMBoe, made up of 29% oil, 31% NGLs and 40% natural gas. The proved developed portion of total proved reserves at year-end 2018 was 37%.
Extensions and discoveries for 2018 were 35 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2018, we reclassified 33.1 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 0.2 MMBoe resulting from updated well performance and technical parameters, and an increase of 1.9 MMBoe due to higher commodity prices, partially offset by a decrease of 1.4 MMBoe due to an increase in operating expenses and natural gas price differentials. We produced 4.3 MMBoe during 2018. This production included 1,385 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.
Reconciliation of PV-10 to Standardized Measure
PV-10 is our estimate of the present value of future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. PV-10 is a non-GAAP, financial measure and generally differs from the standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.
We believe PV-10 to be an important measure for evaluating the relative significance of our oil and gas properties and that the presentation of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. We believe that most other companies in the oil and gas industry calculate PV-10 on the same basis.
The following table provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows at December 31, 2018:
Proved Undeveloped Reserves
As of December 31, 2018, we had 113.1 MMBoe of proved undeveloped (“PUD”) reserves, which is a decrease of 2 MMBoe, or 2%, compared with 115.1 MMBoe of PUD reserves at December 31, 2017. All of our PUD reserves at December 31, 2018, were associated with our core development project, Project Pangea.
The following table summarizes the changes in our PUD reserves during 2018.
Extensions and discoveries relating to proved undeveloped reserves for 2018 were 34.9 MMBoe, primarily attributable to our development of Project Pangea in the Wolfcamp shale oil resource play in the Permian Basin. During 2018, we converted 4.1 MMBoe of proved undeveloped reserves to proved developed reserves, and reclassified 33.1 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included the reclassified reserves, with an increase of 0.1 MMBoe resulting from updated well performance and technical parameters and an increase of 0.1 MMBoe due to higher commodity prices.
The following table sets forth our PUD reserves converted to proved developed reserves during 2018, 2017 and 2016 and the net investment required to convert PUD reserves to proved developed reserves during each year.
In July 2015, we suspended our drilling and completion activities due to the sustained low commodity prices. In 2016, we resumed limited drilling and completion activities as commodity prices remained depressed and volatile. The prolonged depression of commodity prices significantly impacted our conversion of PUD reserves to proved developed reserves.
Estimated future development costs relating to the development of PUD reserves are projected to be approximately $56.4 million in 2019, $251 million in 2020 and $228.2 million in 2021. We monitor fluctuations in commodity prices, drilling and completion costs, operating expenses and drilling success to determine adjustments to our drilling and development project.
Preparation of Proved Reserves Estimates
Internal Controls Over Preparation of Proved Reserves Estimates
Our policies regarding internal controls over the recording of reserve estimates require reserve estimates to be in compliance with SEC rules, regulations and guidance and prepared in accordance with “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007)” promulgated by the Society of Petroleum Engineers (“SPE standards”). Our proved reserves are estimated at the property level and compiled for reporting purposes by our corporate reservoir engineering staff, all of whom are independent of our operations team. We maintain our internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interacts with our internal staff of operations engineers and geoscience professionals and with accounting employees to obtain the necessary data for the reserves estimation process. Our
internal professional staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their evaluation of our reserves.
Our Senior Vice President of Engineering, Troy Hoefer, is the individual responsible for overseeing the preparation of our reserve estimates and for internal compliance of our reserve estimates with SEC rules, regulations and SPE standards. Mr. Hoefer has a Bachelor of Science degree in Petroleum Engineering from the Colorado School of Mines and more than 25 years of industry experience. Mr. Hoefer reports to our President and Chief Operating Officer. Our executive management, including our Chief Executive Officer and our President and Chief Operating Officer, reviews and approves our reserves estimates, including future development costs, before these estimates are finalized and disclosed in a public filing or presentation. Our Chief Executive Officer, J. Ross Craft, P.E., is a licensed Professional Engineer with a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University and more than 30 years of industry experience. Our President and Chief Operating Officer, Qingming Yang, earned his B.S. in Petroleum Geology from Chengdu University of Technology in the People’s Republic of China, his M.A. in Geology from George Washington University and his Ph.D. in Structural Geology from the University of Texas at Dallas. Dr. Yang has more than 25 years of industry experience.
For the years ended December 31, 2018, 2017 and 2016, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare independent estimates of the extent and value of the proved reserves associated with certain of our oil and gas properties. In 2018, DeGolyer and MacNaughton reported to the Audit Committee of our Board of Directors and to our Senior Vice President of Engineering. The Audit Committee meets with the independent engineering firm to, among other things, review and consider the processes used by the engineers in the preparation of the report and any matters of importance that arose in the preparation of the report, including whether the independent engineering firm encountered any material problems or difficulties in the preparation of their report. The Audit Committee’s review specifically includes difficulties with the scope or timeliness of the information furnished to them by the Company or any restrictions on access to information placed upon them by any Company personnel, any other difficulties in dealing with any Company personnel in the preparation of the report and any other matters of concern relating to the preparation of the report. The Audit Committee also determines whether the Company or its management or senior engineering personnel had similar or other problems or concerns regarding the independent engineering firm and the preparation of their report. See Third-Party Reports below for further information regarding DeGolyer and MacNaughton’s report.
Technologies Used in Preparation of Proved Reserves Estimates
Estimates of reserves were prepared in compliance with SEC rules, regulations and guidance and SPE standards. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history. For our properties, structure and isopach maps were constructed to delineate each reservoir. Electrical logs, radioactivity logs, seismic data and other available data were used to prepare these maps. Parameters of area, porosity and water saturation were estimated and applied to the isopach maps to obtain estimates of original oil in place or original gas in place. For developed producing wells whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were determined using decline curve analysis. Reserves for producing wells whose performance was not yet established and for undeveloped locations were estimated using type curves. The parameters needed to develop these type curves such as initial decline rate, “b” factor and final decline rate were based on nearby wells producing from the same reservoir and with a similar completion for which more data were available.
Reporting of NGLs
We produce NGLs as part of the processing of our natural gas. The extraction of NGLs in the processing of natural gas reduces the volume of natural gas available for sale. At December 31, 2018, NGLs represented approximately 31% of our total proved reserves on a Boe basis. NGLs are products sold by the gallon. In reporting proved reserves and production of NGLs, we include these volumes and production as Boe. The prices we received for a standard barrel of NGLs in 2018 averaged approximately 62% lower than the average prices for equivalent
volumes of oil. We report all production information related to natural gas net of the effect of any reduction in natural gas volumes resulting from the processing of NGLs.
Third-Party Reports
For the years ended December 31, 2018, 2017 and 2016, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare estimates of the extent and value of the proved reserves of certain of our oil and gas properties, including 100% of our total reported proved reserves. DeGolyer and MacNaughton’s report for 2018 is included as Exhibit 99.1 to this annual report on Form 10-K.
Oil and Gas Production, Production Prices and Production Costs
The following table sets forth summary information regarding oil, NGLs and gas production, average sales prices and average production costs for the last three years. We determined the Boe using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGLs may differ significantly from the price for a barrel of oil.
(1)
Gas production excludes gas produced and used as field fuel (primarily for compressors and artificial lifts) before the gas was delivered to a sales point.
(2)
Production cost per Boe represents lease operating expenses and excludes production and ad valorem taxes.
Drilling Activity - Prior Three Years
The following table sets forth information on our drilling activity for the last three years. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.
In 2018, we drilled six horizontal wells and completed nine horizontal wells. At December 31, 2018, seven wells were waiting on completion. In 2018, we incurred $0.4 million to drill an exploratory monitor well used for gathering geological, geophysical or engineering data concerning one or more potentially productive formations in other wells.
Although a well may be classified as productive upon completion, future changes in oil, NGLs and gas prices, operating costs and production may result in the well becoming uneconomical.
Drilling Activity - Current
As of the date of this report, we had no rigs operating.
Delivery Commitments
We are not committed to provide a fixed and determinable quantity of oil, NGLs or gas under existing agreements. However, as of December 31, 2018, we had dedicated the majority of our oil production from northern Project Pangea and Pangea West through September 2022 to AMID and had dedicated the majority of our NGLs and natural gas production from Project Pangea to DCP through August 2023.
Producing Wells
The following table sets forth the number of producing wells in which we owned a working interest at December 31, 2018. Wells are classified as natural gas or oil according to their predominant production stream.
Acreage
The following table summarizes our developed and undeveloped acreage as of December 31, 2018.
The undeveloped acreage includes 57,169 net acres subject to continuous development obligations, and these leases may be terminated if we fail to meet our continuous development obligations. The net undeveloped acres subject to continuous development obligations includes 35,688 net acres acquired in Pangea West and 16,035 net acres leased from The Board for Lease of University Lands (“University Lands”) under a Drilling and Development Unit Agreement (“D&D agreement”). We are required to drill one well approximately every six months on the undeveloped acreage in Pangea West with the next drilling requirement scheduled for April 2019. Under the D&D agreement, we are required to drill and complete two wells per calendar year, and in September 2019, we will present a development plan to University Lands that will outline a proposed capital budget and drilling schedule for the following year. Upon approval of the plan of development by University Lands (not to be unreasonably withheld), the development plan will become the drilling obligation for the following year.
Undeveloped Acreage Expirations
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2018, which will expire over the next three years by project area, based on contractual lease maturities, unless production is established before lease expiration dates. Net amounts may be greater than gross amounts in a particular year due to timing of expirations.
The expiring acreage set forth in the table above accounts for 3% of our net acreage, and 1% of our PUD reserves. We are generally engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions and renewals to address the expiration of undeveloped acreage that occurs in the normal course of our business.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our business, financial condition and results of operations.
ITEM 4.
ITEM 4.
MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Our common stock is traded on NASDAQ Global Select Market in the United States under the symbol “AREX.” During 2018, trading volume averaged 434,412 shares per day. The following table shows the quarterly high and low sale prices of our common stock as reported on NASDAQ for the past two years.
Holders
As of February 27, 2019, there were 179 record holders of our common stock. A record holder may be a broker or other entity holding shares in street name for one or more customers who beneficially own the shares.
Dividends
We have not paid any cash dividends on our common stock. We do not expect to pay any cash or other dividends in the foreseeable future on our common stock, as we intend to reinvest cash flow generated by operations into our business. Our revolving credit facility currently restricts our ability to pay cash dividends on our common stock, and we may also enter into credit agreements or other borrowing arrangements in the future that restrict or limit our ability to pay cash dividends on our common stock.
Securities Authorized for Issuance under Equity Compensation Plans
The following table sets forth information regarding securities authorized for issuance under equity compensation plans and individual compensation arrangements as of December 31, 2018.
Issuer Repurchases of Equity Securities
Our 2018 Long Term Incentive Plan and our 2007 Stock Incentive Plan (collectively, the “Incentive Plans”) allow us to withhold shares of common stock to pay withholding taxes payable upon vesting of a restricted stock grant. The following table shows the number of shares of common stock withheld to satisfy the income tax withholding obligations arising upon the vesting of restricted shares issued to employees under the Incentive Plans.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The following table sets forth selected financial information for the five years ended December 31, 2018. This information should be read in conjunction with Item 7
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in understanding our results of operations and our financial condition. Our consolidated financial statements and the accompanying notes included elsewhere in this report contain additional information that should be referred to when reviewing this material. Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, which could cause actual results to differ from those expressed. See “Cautionary Statement Regarding Forward-Looking Statements” at the beginning of this report and “Risk Factors” in Item 1A. for additional discussion of some of these factors and risks.
Overview
Approach Resources Inc. is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas reserves in the Midland Basin of the greater Permian Basin in West Texas, where we lease approximately 150,000 net acres as of December 31, 2018. We believe our concentrated acreage position and extensive, integrated field infrastructure system provide us an opportunity to achieve cost, operating and recovery efficiencies in the development of our drilling inventory. Our long-term business strategy is to develop resource potential from the Wolfcamp shale oil formation and pursue acquisitions that meet our strategic and financial objectives. See “Item 1 - Business - Our Business Strategy”. Additional drilling targets could include the Clearfork, Canyon Sands, Strawn and Ellenburger zones. We sometimes refer to our development project in the Permian Basin as “Project Pangea,” which includes “Pangea West.” Our management and technical team have a proven track record of finding and developing reserves through advanced drilling and completion techniques. As the operator of all of our estimated proved reserves and production, we have a high degree of control over capital expenditures and other operating matters.
At December 31, 2018, our estimated proved reserves were 180.1 million barrels of oil equivalent (“MMBoe”). Substantially all of our proved reserves are located in Crockett and Schleicher Counties, Texas. The following are important characteristics of our proved reserves at December 31, 2018:
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29% oil, 31% NGLs and 40% natural gas;
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37% proved developed;
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100% operated;
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Reserve life of approximately 44 years based on 2018 production of 4.1 MMBoe;
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Standardized measure of discounted future net cash flows (“standardized measure”) of $660 million; and
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PV-10 (non-GAAP) of $761.8 million.
PV-10 is our estimate of the present value of future net revenues from proved oil, NGLs and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates for future income taxes. Estimated future net revenues are discounted at an annual rate of 10% to determine their present value. PV-10 is a financial measure that is not determined in accordance with accounting principles generally accepted in the United States (“GAAP”), and generally differs from the standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future cash flows. PV-10 should not be considered as an alternative to the standardized measure, as computed under GAAP. See Item 2. “Properties - Proved Oil and Gas Reserves” for a reconciliation of PV-10 to the standardized measure.
At December 31, 2018, we owned and operated 813 producing oil and gas wells in the Permian Basin. During 2018, we produced 4.1 MMBoe, or 11.2 MBoe/d. Production for 2018 was 26% oil, 36% NGLs and 38% natural gas.
Going Concern Uncertainty
Our liquidity and ability to comply with covenants under our revolving credit facility have been negatively impacted by the recent decrease in commodity prices, and by the severe natural gas price discount in the Permian Basin in 2018. Our revolving credit facility contains three principal financial covenants: (i) a consolidated interest coverage ratio, (ii) a consolidated modified current ratio and (iii) a consolidated total leverage ratio. See Note 3 to our consolidated financial statements in this report for additional information regarding the financial covenants under our revolving credit facility. At December 31, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.
At December 31, 2018, our total leverage ratio was 6.6 to 1.0, which is above the level that will be required as of March 31, 2019, of 5.0 to 1.0. If we are unable to improve our total leverage ratio by March 31, 2019, the obligations of the Company under the revolving credit facility may be accelerated, which would have a material adverse effect on our business. Our total leverage ratio has decreased from 9.7 to 1.0 as of December 31, 2016. However, based on our current operating and commodity price forecast and capital structure, and in the absence of deleveraging transactions as discussed below, we do not believe we will be able to comply with the leverage ratio covenant beginning with the measurement date of March 31, 2019. Failure to comply with the leverage ratio covenant would be an event of default under the credit agreement. If an event of default occurred, our lenders could accelerate the maturity of the outstanding indebtedness, making it immediately due and payable, and we would not have sufficient liquidity to repay those amounts.
In addition, our revolving credit facility is subject to scheduled redeterminations of our borrowing base semi-annually, based on our reserves. Continued low commodity prices may adversely impact the results of the upcoming redetermination, and have a significant negative impact on our liquidity. If our borrowing base is reduced below the amount outstanding under our credit agreement, we may be required to repay a portion of our outstanding borrowings, and we may not have sufficient liquidity to meet this requirement.
These factors raise substantial doubt about our ability to continue as a going concern.
In order to improve our leverage position to meet upcoming financial covenants under the revolving credit facility, we have been, and currently are, pursuing or considering a number of deleveraging and strategic actions, which in certain cases may require the consent of current lenders, stockholders or bond holders.
On April 12, 2018, our largest shareholder, Wilks Brothers, LLC, and its affiliate SDW Investments, LLC (collectively, “Wilks”), disclosed on Schedule 13D/A that they intended to engage in discussions with the Company regarding their investment in the Company, including the possible acquisition of additional shares of common stock through the exchange of approximately $60 million of 7% Senior Notes due 2021 (the “Senior Notes”) currently held by Wilks (the “Exchange Transaction”). In April 2018, our board of directors formed a committee of independent directors (the “Special Committee”) to evaluate a potential Exchange Transaction as well as other strategic alternatives (the “Competing Transactions”). The Special Committee hired financial and legal advisors to advise the Special Committee on these matters. The Special Committee engaged in discussions with Wilks regarding an Exchange Transaction in 2018, but in mid-2018 the Wilks and the Committee deferred further discussions regarding a stand-alone Exchange Transaction pending resolution of the Company’s discussions regarding the potential transaction described in the following paragraph.
In addition, management has reviewed numerous cash flow producing properties for potential acquisition over the last several years in order to grow our production base and reduce our leverage ratio to a sustainable level and one that is in compliance with our financial covenants. In early 2018, we retained a financial advisor, separate from the Special Committee’s advisor, and began discussions with a potential seller and multiple financing counterparties for the purchase of a set of substantial cash flow producing properties. Despite a deteriorating commodity price market, discussions with both the seller and financing parties progressed throughout 2018. However, no definitive agreements ultimately were executed, and the negotiations currently are not active.
In March 2019, our board of directors expanded the scope of the Special Committee to explore, in addition to an Exchange Transaction, other financing alternatives and deleveraging transactions, including without limitation (i) amendments or waivers to the covenants or other provisions of our revolving credit facility, (ii) raising new capital in private or public markets and (iii) restructuring our balance sheet either in court or through an out of court agreement with creditors. We are also considering operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives, including: (i) acquiring assets with existing production and cash flows by issuing preferred and common equity to finance such acquisitions; (ii) selling existing producing or midstream assets; (iii) merging with a strategic partner. The Special Committee has re-commenced discussions with the Wilks regarding an Exchange Transaction and intends to continue those discussions as part of its review of financing alternatives and deleveraging transactions. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our credit facility covenants.
Summary
Our financial results depend on many factors, but particularly on the price of oil, NGLs and gas. Commodity prices are affected by changes in market demand, which is impacted by factors outside of our control, including domestic and foreign supply of oil, NGLs and gas, overall domestic and global economic conditions, commodity processing, gathering and transportation availability and the availability of refining capacity, price and availability of alternative fuels, price and quantity of foreign imports, domestic and foreign governmental regulations, political conditions in or affecting other oil and gas producing countries, weather and technological advances affecting oil, NGLs and gas consumption. As a result, we cannot accurately predict future oil, NGLs and gas prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. For example, in 2018, NYMEX-WTI oil prices ranged from a high of $76.41 per Bbl to a low of $42.53 per Bbl, NYMEX-Henry Hub natural gas prices ranged from a high of $4.84 per MMBtu to a low of $2.55 per MMBtu, and our realized prices for NGLs ranged from a high of $31.68 per Bbl to a low of $15.26 per Bbl. If the current oil or natural gas prices do not improve from current levels, they could have a material adverse effect on our business, financial condition and results of operations and quantities of oil, natural gas and NGLs reserves that may be economically produced and liquidity that may be accessed through our borrowing base under our revolving credit facility and through capital markets.
We also face the challenge of financing exploration, development and future acquisitions. Our liquidity, ability to comply with debt covenants under our revolving credit facility and ability to increase our reserves and production have been adversely impacted by the recent decrease and volatility in commodity prices. See “Going Concern Uncertainty” above and Note 3 to our consolidated financial statements in this report for a more detailed description of these financial covenants. However, we believe we have adequate liquidity for current, near-term working capital needs from cash generated from operations and, to the extent available, unused borrowing capacity under our revolving credit facility, each assuming (i) no reduction in our borrowing base from our semi-annual borrowing base redetermination and (ii) no acceleration of amounts due under our revolving credit facility.
However, in the longer term, the Company expects a portion of its funding needs to be covered by cash flows from operations, and may issue debt or equity or monetize assets to cover any difference between cash flow from operations and capital or liquidity needs. We cannot guarantee that such financing will be available on acceptable terms or at all.
In addition to production volumes, financing and commodity prices, finding and developing sufficient amounts of oil and gas reserves at economical costs is critical to our long-term success. Future finding and development costs are subject to changes in the industry, including the costs of acquiring, drilling and completing our projects. We focus our efforts on increasing oil and gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flow from operations will depend on our ability to manage our overall cost structure.
Like all oil and gas production companies, we face the challenge of natural production declines. Oil and gas production from a given well naturally decreases over time. Additionally, our wells have a rapid initial production decline. We attempt to overcome this natural decline by drilling to develop and identify additional reserves, farm-ins
or other joint drilling ventures and by acquisitions. However, during times of severe price declines, we may reduce current capital expenditures and curtail drilling operations in order to preserve liquidity. A material reduction in capital expenditures and drilling activities could materially reduce our production volumes and revenues.
2018 Activity
Our 2018 activity focused on executing a disciplined capital budget in connection with slowly recovering commodity prices, strengthening our balance sheet and maintaining a competitive operating cost structure. We drilled six, and completed nine, horizontal wells in 2018 in the Wolfcamp shale oil resource play in the Midland Basin. We plan to continue to develop the Wolfcamp shale in Project Pangea in 2019, at a measured pace subject to commodity prices and leverage restrictions. Our 2018 activities included:
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Executed a disciplined capital budget and managed production decline. In 2018, we incurred capital expenditures of $46.8 million, spending 22% less than the midpoint of our annual budget, and we deferred well completions scheduled in the fourth quarter due to the sharp decrease in commodity prices. During 2018, we drilled six, and completed nine, horizontal Wolfcamp wells, and entered 2019 with an inventory of seven drilled horizontal wells waiting on completion. Production for 2018 totaled 4.1 MMBoe (11.2 MBoe/d) compared to 4.2 MMBoe (11.6 MBoe/d) in 2017, a decrease of 4%. Production for 2018 was 26% oil, 36% NGLs and 38% natural gas.
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Maintained competitive operating cost structure. Utilizing our infrastructure and field-level expertise, we maintained an industry leading average drilling and completion cost of $4.6 million per horizontal well and lease operating expense per Boe of $5.18. Additionally, in 2018, we reduced general and administrative expenses by $3.4 million, or 14%.
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Delineation of the multi-zone potential of the Wolfcamp shale. The Wolfcamp shale has a gross pay thickness of approximately 1,000 to 1,200 feet, which allows for stacked wellbores targeting three different zones that we call “benches.” We believe effectively developing the Wolfcamp shale may involve up to three lateral wellbores, each targeting a different bench, which we refer to as the Wolfcamp A, B and C. As of December 31, 2018, we had drilled and completed a total of 25 wells targeting the Wolfcamp A bench, 115 wells targeting the Wolfcamp B bench and 56 wells targeting the Wolfcamp C bench. We have successful wells targeting each of the Wolfcamp benches, and we continued development of the Wolfcamp shale in 2018.
Plans for 2019
For 2019, we have set our capital expenditure budget to a range of $30 million to $60 million, compared to $46.8 million of capital expenditures in 2018. We plan to operate one rig on an intermittent basis during the year in Project Pangea. Our 2019 capital budget excludes acquisitions and lease extensions and renewals and is subject to change depending upon a number of factors, including prevailing and anticipated prices for oil, NGLs and gas, results of horizontal drilling and completions, economic and industry conditions at the time of drilling, the availability of sufficient capital resources for drilling prospects, our financial results and the availability of lease extensions and renewals on reasonable terms. The eventual results of our strategic and deleveraging efforts will have a substantial impact on the Company’s capital expenditure budget. Although the impact of changes in these collective factors in the current commodity price environment is difficult to estimate, we currently expect to execute our development plan based on current conditions. To the extent there is a significant increase or decrease in commodity prices in the future or a change to our capital structure, we will assess the impact on our development plan at that time, and we may respond to such changes by altering our capital budget or our development plan.
Results of Operations
The following table sets forth summary information regarding oil, NGLs and gas revenues, production, average product prices and average production costs and expenses for the last three years. We determined the Boe using the ratio of six Mcf of natural gas to one Boe, and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas or NGLs may differ significantly from the price for a barrel of oil.
Oil, NGLs and gas sales. Oil, NGLs and gas sales for 2018 increased $8.7 million, or 8%, to $114 million from $105.3 million in 2017. The increase in oil, NGLs and gas sales was due to an increase in average realized commodity prices ($12.4 million), partially offset by a decrease in production volumes ($3.7 million). In 2018, the average price we received for our production, before the effect of commodity derivatives, increased 12% to $27.94 per Boe, up from $24.89 per Boe in the prior year. Production volumes decreased from 2017, as a result of reduced drilling and completion activity. We expect oil, NGLs and gas sales to decrease in 2019 due to continued depressed commodity prices and natural production decline.
Oil, NGLs and gas sales for 2017 increased $15 million, or 17%, to $105.3 million from $90.3 million in 2016. The increase in oil, NGLs and gas sales was due to an increase in average realized commodity prices ($21.1 million), partially offset by a decrease in production volumes ($6.1 million). In 2017, the average price we received for our production, before the effect of commodity derivatives, increased 25% to $24.89 per Boe, up from $19.90 per Boe in the prior year. Production volumes decreased from 2016, as a result of reduced drilling and completion activity.
Net (loss) income. Net loss for 2018 was $19.9 million, or $0.21 per diluted share, compared to $112.4 million, or $1.35 per diluted share, for 2017. Net loss for 2018 included a tax benefit of $4.3 million and a commodity derivative loss of $0.3 million. The decrease in the net loss for 2018 was due to the decrease in our tax provision compared to 2017 ($80.8 million), an increase in revenue ($8.7 million) and a decrease in operating expenses ($12.2 million). These items were partially offset by an increase in interest expense ($4.1 million) and the gain on debt extinguishment of ($5.1 million) in 2017.
Net loss for 2017 was $112.4 million, or $1.35 per diluted share, compared to $52.2 million, or $1.26 per diluted share, for 2016. Net loss for 2017 included a tax provision of $76.4 million, a gain on debt extinguishment of $5.1 million due to two debt-for-equity exchange transactions and a commodity derivative loss of $0.3 million. The increase in the net loss for 2017 was primarily due to the increase in our tax provision of $100.8 million. This resulted from our cumulative change in ownership following the two debt-for-equity exchange transactions, partially offset by the change in the corporate federal income tax rate. The increase in our tax provision was partially offset by an increase in revenues ($15 million), a decrease in operating expenses ($10.1 million), a decrease in interest expense ($6.2 million), a decrease in commodity derivative loss ($5.2 million) and the gain on debt extinguishment ($5.1 million).
Oil, NGLs and gas production. Production for 2018 totaled 4,082 MBoe (11.2 MBoe/d), compared to 4,232 MBoe (11.6 MBoe/d) in 2017, a decrease of 4%. Production for 2018 was 26% oil, 36% NGLs and 38% natural gas, compared to 26% oil, 35% NGLs and 39% natural gas in 2017. Production volumes decreased during 2018, due to natural production decline. We expect production to slightly decrease in 2019 as a result of natural production decline.
Production for 2017 totaled 4,232 MBoe (11.6 MBoe/d), compared to 4,537 MBoe (12.4 MBoe/d) in 2016, a decrease of 7%. Production for 2017 was 26% oil, 35% NGLs and 39% natural gas, compared to 28% oil, 34% NGLs and 38% natural gas in 2016. The decrease in production in 2017 was the result of our reduced drilling and completion activity in 2016.
Commodity derivative loss. The following table sets forth the components of our commodity derivative loss for the years ended December 31, 2018, 2017 and 2016 (dollars in thousands).
Historically, we have not designated our derivative instruments as cash-flow hedges. Commodity derivative settlements are derived from the relative movement of commodity prices in relation to the fixed notional pricing in our derivative contracts for the respective years. As commodity prices increase or decrease, the fair value of the open portion of those positions decreases or increases, respectively. We record our open derivative instruments at fair value on our consolidated balance sheets as either current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts, not designated as cash-flow hedges, and cash settlements are recorded in earnings as they occur on our consolidated statements of operations under the caption entitled “commodity derivative loss.”
In April 2018, we entered into basis swaps for the NYMEX Calendar Monthly Average Roll (the “CMA Roll”) covering 2,000 Bbls per day for May 2018 through December 2018 at $0.66/Bbl. Basis swaps for the CMA Roll are pricing adjustments to the trade month versus the delivery month for contract pricing. These derivative contracts were designated as cash-flow hedges. The changes in fair value of the derivative contracts designated as cash-flow hedges, to the extent the hedge is effective, will be recognized in other comprehensive income until the hedged item is recognized in revenue. Oil, NGLs and gas sales includes $79,000 related to this cash-flow hedge in 2018. As of December 31, 2018, we had no outstanding derivative instruments designated as cash-flow hedges.
For 2019, we currently have 182,500 Bbls of oil hedged at a floor price of $65.00 per Bbl and a ceiling price of $71.00 per Bbl and 239,575 Bbls of NGLs hedged at weighted average prices of $14.12 per Bbl (C2-ethane), $36.54 per Bbl (C3-propane), $38.63 per Bbl (NC4-butane) and $65.21 per Bbl (C5 - Pentane).
Lease operating expenses. Our lease operating expenses (“LOE”) increased $3.2 million, or 18%, for 2018, to $21.1 million ($5.18 per Boe) from $17.9 million ($4.23 per Boe) for 2017. The increase in LOE in 2018 over 2017 was primarily due to well repairs, workovers and maintenance and water hauling operations. The increase in well repairs, workovers and maintenance was related to oil and gas wells to manage natural production decline and saltwater disposal wells to improve the efficiency of our water handling operations.
Our LOE decreased $1.4 million, or 7%, for 2017, to $17.9 million ($4.23 per Boe) from $19.3 million ($4.24 per Boe) for 2016. The decrease in LOE in 2017 over 2016 was primarily due to increased efficiency in our water hauling operations, partially offset by an increase in compression rental and repair, well repairs, workovers and maintenance to manage production declines.
The following tables summarize LOE (in millions) and LOE per Boe.
Production and ad valorem taxes. Our 2018 production and ad valorem taxes increased approximately $0.3 million, or 3%, to $8.9 million from $8.6 million for 2017. The increase in production and ad valorem taxes was primarily the result of an increase in oil, NGLs and gas sales over 2017. Production and ad valorem taxes were approximately 7.8% and 8.2% of oil, NGLs and gas sales for the respective periods.
Our 2017 production and ad valorem taxes increased approximately $0.4 million, or 5%, to $8.6 million from $8.2 million for 2016. The increase in production and ad valorem taxes was primarily the result of an increase in oil, NGLs and gas sales over 2016. Production and ad valorem taxes were approximately 8.2% and 9.1% of oil, NGLs and gas sales for the respective periods.
Exploration expense. We recorded $0.4 million, $3.7 million and $3.9 million of exploration expense for 2018, 2017 and 2016, respectively. The decrease in exploration expense in 2018 was primarily due to a decrease in lease expirations in the current year. Exploration expense for 2018 resulted primarily from the drilling of an exploratory monitor well which is being used to gather geological, geophysical or engineering data concerning one or more potentially productive formations in other wells. Exploration expense for 2017 and 2016 resulted primarily from lease expirations in the Permian Basin.
General and administrative expenses. Our general and administrative expenses (“G&A”) decreased $3.4 million, or 14%, to $20.9 million ($5.13 per Boe) for 2018 from $24.3 million ($5.75 per Boe) for 2017. The decrease in G&A was primarily due to lower salaries and benefits and share-based compensation. In 2018 and 2017, G&A included $0.2 million and $0.8 million in expense related to cash-settled performance awards, respectively. These awards are re-measured each interim reporting period based on the fair market value of our common stock. Significant changes in the fair market value of our common stock will impact G&A per Boe.
Our G&A decreased $0.4 million, or 2%, to $24.3 million ($5.75 per Boe) for 2017 from $24.7 million ($5.45 per Boe) for 2016. The decrease in G&A was primarily due to lower share-based compensation, partially offset by an increase in salaries and benefits and professional fees. In 2017 and 2016, G&A included $0.8 million and $1.3 million in expense related to cash-settled performance awards, respectively.
The following table summarizes G&A (in millions) and G&A per Boe.
Depletion, depreciation and amortization expense. Our depletion, depreciation and amortization expense (“DD&A”) decreased $9.1 million, or 13%, to $61.4 million for 2018, from $70.5 million for 2017. Our DD&A per Boe decreased by $1.61, or 10%, to $15.05 per Boe for 2018, compared to $16.66 per Boe for 2017. The decrease in DD&A in 2018 over 2017 was attributable to a decrease in production. The decrease in DD&A per Boe over the prior-year period was primarily due to lower oil and gas property carrying costs relative to estimated proved developed reserves.
DD&A decreased $8.5 million, or 11%, to $70.5 million for 2017, from $79 million for 2016. The decrease in DD&A in 2017 over 2016 was primarily attributable to a decrease in production. Our DD&A per Boe decreased by $0.76, or 4%, to $16.66 per Boe for 2017, compared to $17.42 per Boe for 2016. The decrease in DD&A per Boe over the prior-year period was primarily due to lower oil and gas property carrying costs relative to estimated proved developed reserves.
Interest expense, net. The following table sets forth interest expense, weighted average interest rates and weighted average debt balances for the years ended December 31, 2018, 2017 and 2016 (dollars in thousands).
Interest expense for the years ended December 31, 2018, 2017 and 2016 includes amortization of debt issuance costs of $1 million, $0.9 million and $1.4 million, respectively. Interest expense, net increased $4.1 million or 19% to $25.1 million for 2018, compared to $21.1 million for 2017. This increase was primarily due to increases in the applicable margin rates, outstanding borrowings and floating interest rates under our revolving credit facility.
Interest expense, net, decreased $6.2 million or 23%, to $21.1 million for 2017, compared to $27.3 million for 2016. This decrease was primarily due to the reduction in our interest expense on outstanding 7% Senior Notes due 2021 (the “Senior Notes) of $9.8 million, due to two debt-for-equity exchange transactions, partially offset by an increase in the applicable margin rates, outstanding borrowings and floating interest rates under our revolving credit facility.
Write-off of debt issuance costs. In 2016, we recorded a $0.6 million write-off of unamortized debt issuance costs, related to the third amendment of our revolving credit facility, due to the reduction in our borrowing base from $450 million to $325 million.
Gain on extinguishment of debt. In 2017, we recognized a gain of $5.1 million on two debt-for-equity exchange transactions, for the difference between the fair market value of the shares issued, a Level 1 fair value measurement, and the net carrying value of the Senior Notes exchanged. In 2018 and 2016, we did not repurchase or retire any outstanding debt.
Other (expense) income. Other (expense) income for the years ended December 31, 2018, 2017 and 2016 was an expense of $29,000, and income of $32,000 and $1.5 million, respectively. In 2016, we recorded a contractual settlement of $1.4 million in other income.
Income taxes. In 2018, we recognized an income tax benefit of $4.3 million, compared to an income tax provision of $76.4 million in 2017, and an income tax benefit of $24.4 million in 2016. The following table reconciles our income tax expense for the years ended December 31, 2018, 2017 and 2016, to the U.S. federal statutory rate of 21%, 35% and 35%, respectively (dollars in thousands).
In 2017, the completed debt-for-equity exchange transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the future use of our pre-change net operating losses (“NOLs”). Accordingly, we reduced our NOL deferred tax assets by $139.1 million.
On December 22, 2017, the Tax Cuts and Jobs Act was enacted which, among other things, lowered the U.S. Federal income tax rate applicable to corporations from 35% to 21% and repealed the corporate alternative minimum tax. We recorded a net tax benefit of $51.9 million to reflect the impact of the Tax Cuts and Jobs Act as of December 31, 2017, as it is required to reflect the change in the period in which the law is enacted.
Liquidity and Capital Resources
We generally will rely on cash generated from operations, to the extent available, borrowings under our revolving credit facility and, to the extent that credit and capital market conditions will allow, future equity and debt
offerings to satisfy our liquidity needs. Our ability to fund planned capital expenditures and to make acquisitions depends upon commodity prices, our future operating performance, availability of borrowings under our revolving credit facility, and more broadly, on the availability of equity and debt financing, which is affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control. We cannot predict whether additional liquidity from equity or debt financings or borrowings under our revolving credit facility will be available on acceptable terms, or at all, in the foreseeable future.
Our liquidity and ability to comply with debt covenants under our revolving credit facility have been negatively impacted by the recent decrease in commodity prices. Our revolving credit facility contains three principal financial covenants: (i) a consolidated interest coverage ratio, (ii) a consolidated modified current ratio and (iii) a consolidated total leverage ratio. See Note 3 to our consolidated financial statements for additional information regarding the financial covenants under our revolving credit facility. At December 31, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.
At December 31, 2018, our total leverage ratio was 6.6 to 1.0, which is above the level that will be required as of March 31, 2019, of 5.0 to 1.0. If we are unable to improve our total leverage ratio by March 31, 2019, the obligations of the Company under the revolving credit facility may be accelerated, which would have a material adverse effect on our business. Our total leverage ratio has decreased from 9.7 to 1.0 as of December 31, 2016, to 6.6 to 1.0 as of December 31, 2018. Based on our current operating and commodity price forecast and capital structure, and in the absence of deleveraging transactions as discussed below, we do not believe we will be able to comply with the total leverage ratio covenant beginning with the measurement date of March 31, 2019. In addition, our revolving credit facility is subject to scheduled redeterminations of its borrowing bases semi-annually, based on our reserves. Continued low commodity prices may adversely impact the results of the upcoming redetermination, and have a significant negative impact on the Company’s liquidity. If an event of default occurred, our lenders could accelerate the maturity of the outstanding indebtedness, making it immediately due and payable, and we would not have sufficient liquidity to repay those amounts. These factors raise substantial doubt about our ability to continue as a going concern. See Note 1 to our consolidated financial statements in this report for additional information regarding our plans to improve our leverage and our ability to continue to comply with the financial covenants under our revolving credit facility.
In order to improve our leverage position to meet upcoming financial covenants under the revolving credit facility, we have been, and currently are, pursuing or considering a number of deleveraging and strategic actions, which in certain cases may require the consent of current lenders, stockholders or bond holders.
On April 12, 2018, our largest shareholder, Wilks, disclosed on Schedule 13D/A that they intended to engage in discussions with the Company regarding their investment in the Company, including the possible acquisition of additional shares of common stock through the exchange of approximately $60 million of Senior Notes currently held by Wilks. In April 2018, our board of directors formed the Special Committee to evaluate a potential Exchange Transaction as well as other Competing Transactions. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters. The Special Committee engaged in discussions with Wilks regarding an Exchange Transaction in 2018, but in mid-2018 the Wilks and the Special Committee deferred further discussions regarding a stand-alone Exchange Transaction pending resolution of the Company’s discussions regarding the potential transaction described in the following paragraph.
In addition, management has reviewed numerous cash flow producing properties for potential acquisition over the last several years in order to grow our production base and reduce our leverage ratio to a sustainable level and one that is in compliance with our financial covenants. In early 2018, we retained a financial advisor, separate from the Special Committee’s advisor, and began discussions with a potential seller and multiple financing counterparties for the purchase of a set of substantial cash flow producing properties. Despite a deteriorating commodity price market, discussions with both the seller and financing parties progressed throughout 2018. However, no definitive agreements ultimately were executed, and the negotiations currently are not active.
In March 2019, our board of directors expanded the scope of the Special Committee to explore, in addition to an Exchange Transaction, other financing alternatives and deleveraging transactions, including without limitation (i) amendments or waivers to the covenants or other provisions of our revolving credit facility, (ii) raising new capital in private or public markets and (iii) restructuring our balance sheet either in court or through an out of court agreement with creditors. We are also considering operational matters such as adjusting our capital budget and
improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives, including: (i) acquiring assets with existing production and cash flows by issuing preferred and common equity to finance such acquisitions; (ii) selling existing producing or midstream assets; (iii) merging with a strategic partner. The Special Committee has re-commenced discussions with the Wilks regarding an Exchange Transaction and intends to continue those discussions as part of its review of financing alternatives and deleveraging transactions. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our credit facility covenants.
Our cash flow from operations is driven by commodity prices, production volumes and the effect of commodity derivatives. Cash flows from operations are primarily used to fund exploration and development of our oil and gas properties. If commodity prices do not improve from current levels, our operating cash flows will decrease and our lenders may reduce our borrowing base, thus limiting the amounts available to fund future capital expenditures. If we are unable to replace our oil, NGLs and gas reserves through acquisitions, development and exploration, we may also suffer a reduction in operating cash flows and access to funds under our revolving credit facility.
We believe we currently have adequate liquidity from cash generated from operations and unused borrowing capacity under our revolving credit facility for current working capital needs and maintenance of our current development plan, absent the reduction in our borrowing base under our revolving credit facility or the acceleration of the maturity date of our revolving credit facility. However, we may determine to use various financing sources, including the issuance of common stock, preferred stock, debt, convertible securities and other securities for future development of reserves, acquisitions, additional working capital or other liquidity needs, if such financing is available on acceptable terms. We cannot guarantee that such financing will be available on acceptable terms or at all. Using some of these financing sources may require approval from the lenders under our revolving credit facility.
Liquidity
We define liquidity as funds available under our revolving credit facility plus year-end net cash and cash equivalents. Our liquidity is subject to our continued compliance with the covenants under our revolving credit facility. At December 31, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default under our debt instruments. See Note 3 to our consolidated financial statements in this report for additional discussion of the covenants under our revolving credit facility. At December 31, 2018, we had $301.5 million in borrowings outstanding under our revolving credit facility and $22,000 in cash and cash equivalents, compared to $291 million and $273 million in borrowings outstanding under our revolving credit facility at December 31, 2017 and 2016, respectively, and $21,000 in cash and cash equivalents at both December 31, 2017 and 2016. Our liquidity position at December 31, 2018, decreased compared to December 31, 2017, due to an increase in the outstanding borrowings under our revolving credit facility. In December 2017, we entered into a fourth amendment to our revolving credit facility, which among other things, extended the maturity date of the revolving credit facility from May 7, 2019 to May 7, 2020 and reaffirmed the aggregate lender commitments of $325 million. The borrowing base under our revolving credit facility is redetermined semi-annually based on our oil, NGLs and gas reserves.
The following table summarizes our liquidity position at December 31, 2018, 2017 and 2016 (in thousands).
Working Capital
Our working capital is affected primarily by the fair value of our commodity derivative positions and our capital spending program. At December 31, 2018, we had a working capital deficit of $4.8 million, compared to a
working capital deficit of $8.4 million and $13.9 million at December 31, 2017 and 2016, respectively. The change in working capital during 2018 was attributable to changes in fair value of our commodity derivatives, partially offset by a decrease in accounts receivable. The change in working capital during 2017 was primarily attributable to prepayment of hydraulic fracturing services and changes in fair value of our commodity derivatives partially offset by an increase in accrued liabilities due to an increase in capital expenditures. The change in working capital during 2016 was primarily attributable to changes in fair value of our commodity derivatives partially offset by a decrease in accounts payable and accrued liabilities due to a decrease in capital expenditures and cost reductions. To the extent we operate or end 2019 with a working capital deficit, we expect such deficit to be offset by liquidity available under our revolving credit facility, assuming (i) continued compliance with the financial covenants under our revolving credit facility, (ii) no reduction in our borrowing base from our semi-annual borrowing base redetermination and (iii) no acceleration of amounts due under our revolving credit facility.
Cash Flows
The following table summarizes our sources and uses of funds for the periods noted (in thousands).
For 2018, our primary sources of cash were from operating activities and financing activities. Approximately $34.7 million of cash from operations and $8 million of cash from financing activities were used to fund our development project in the Permian Basin. Cash flows used in investing activities were lower in 2018 compared to 2017, primarily due to prepayment of a hydraulic fracturing services agreement in 2017, which was terminated in 2018. Cash flows provided by financing activities were lower in 2018 primarily due to $10.5 million in net borrowings on our revolving credit facility in 2018, compared to $18 million in net borrowings on our revolving credit facility in 2017.
For 2017, our primary sources of cash were from operating activities and financing activities. Approximately $37.5 million of cash from operations and $15 million of cash from financing activities were used to fund our development project in the Permian Basin. Cash flows used in investing activities were higher in 2017 compared to 2016, primarily due to an increase in capital expenditures of $27.3 million as a result of improved commodity prices and a decrease in interest expense as a result of the completed debt-for-equity exchange transactions. Cash flows provided by financing activities were higher in 2017 primarily due to $18 million in net borrowings on our revolving credit facility in 2017, compared to no net borrowings on our revolving credit facility in 2016.
For 2016, our primary source of cash was from operating activities. Approximately $23.9 million of cash from operations was used to fund our $19.8 million of capital expenditures in 2016 for our development project in the Permian Basin and $4.1 million for changes in working capital related to investing activities. Cash flows used in investing activities were lower in 2016 compared to 2015, primarily due to a decrease in capital expenditures of $131.4 million as a result of depressed commodity prices. Cash flows used in financing activities were lower in 2016 primarily due to no net borrowings on our revolving credit facility in 2016, compared to $123 million in net borrowing on our credit facility in 2015.
Operating Activities
For 2018, our cash flows from operations were used primarily for drilling and development activities in the Permian Basin. Cash flows from operating activities decreased by $2.8 million, or 7%, to $34.7 million in 2018 from $37.5 million in 2017. The decrease in cash flows from operating activities in 2018 from 2017 was primarily due to an increase in cash paid for interest ($3.5 million), an increase in LOE ($3.2 million), an increase in net cash payments under our commodity derivatives ($2.7 million), and changes in working capital related to operating activities ($3.2 million), partially offset by an increase in oil, NGLs and gas sales ($8.7 million).
For 2017, our cash flows from operations were used primarily for drilling and development activities in the Permian Basin. Cash flows from operating activities increased by $11.4 million, or 44%, to $37.5 million in 2017 from $26.1 million in 2016. The increase in cash flows from operating activities in 2017 from 2016 was primarily due to an increase in oil, NGLs and gas sales as a result of higher commodity prices and a decrease in interest expense as a result of the completed debt-for-equity exchange transactions, partially offset by an increase in net cash payments under our commodity derivatives.
For 2016, our cash flows from operations were used primarily for drilling and development activities in the Permian Basin. Cash flows from operating activities decreased by $76.6 million, or 75%, to $26.1 million in 2016 from $102.7 million in 2015. The decrease in cash flows from operating activities in 2016 from 2015 was primarily due to a decrease in oil, NGLs and gas sales as a result of lower commodity prices and production, a decrease in net cash receipts under our commodity derivatives, partially offset by a decrease in operating expenses.
Investing Activities
During the years ended December 31, 2018, 2017 and 2016, we invested $46.7 million, $47.1 million and $19.8 million, respectively, for capital expenditures on oil and gas properties. Cash flows used in investing activities was lower in 2018 compared to 2017 primarily due to prepayment of a hydraulic fracturing services agreement in 2017, which was terminated in 2018. Our capital expenditures for 2018 were primarily attributable to drilling and development ($39.4 million), infrastructure projects and equipment ($6.6 million), an exploratory project ($0.4 million) and acreage acquisitions and extensions ($0.4 million). Cash used in investing activities also included changes in working capital associated with investing activities ($4 million) primarily related to termination of a prepaid hydraulic fracturing services agreement. Cash flows used in investing activities were higher in 2017 compared to 2016, primarily due to an increase in capital expenditures of $27.3 million as a result of improved operating cash flow.
The following table is a summary of capital expenditures related to our oil and gas properties (in thousands).
Financing Activities
The following is a description of our financing activities in 2018, 2017 and 2016.
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In 2017, we completed the two debt-for-equity exchange transactions, which reduced our Senior Notes by $145.1 million and provided $44.3 million in interest savings over the remaining term of the Senior Notes. These exchange transactions improved our operating cash flow through the reduction of interest expense. We incurred equity issuance costs of $2.8 million related to these exchange transactions, which were recorded as a reduction to additional paid-in capital.
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In December 2017, we entered into a fourth amendment to the revolving credit facility. The fourth amendment, among other things, (a) extended the maturity date of the revolving credit facility from May 7, 2019, to May 7, 2020, (b) added the total leverage ratio financial covenant, (c) reaffirmed the aggregate lender commitments of $325 million, (d) increased the applicable margin rates on borrowings by 50 basis points, and (e) required the Company to hedge 50% of the Company’s estimated 2018 oil and gas production from proved developed producing (“PDP”) reserves. In connection with the fourth amendment to the revolving credit facility, we incurred $1 million of debt issuance costs.
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In May 2016, the lenders under our revolving credit facility completed their semi-annual borrowing base redetermination and decreased the aggregate lender commitments to $325 million from $450 million.
In 2018, we increased the net outstanding balance under our revolving credit facility by $10.5 million, compared to $18 million in 2017, and no net borrowings under our revolving credit facility in 2016.
As market conditions warrant and subject to our contractual restrictions in our revolving credit facility or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure. We may accomplish this through open market or privately negotiated transactions, which may include, among other things, repurchases of our common stock or outstanding debt, debt-for-debt or debt-for-equity exchanges or refinancings, and private or public equity raises and rights offerings. Many of these alternatives may require the consent of current lenders, stockholders or bond holders, and there is no assurance that we will be able to execute any of these alternatives on acceptable terms or at all. The amounts involved in any such transaction, individually or in the aggregate, may be material.
Revolving Credit Facility
We have a $1 billion revolving credit facility with a borrowing base and aggregate lender commitments of $325 million. The borrowing base is redetermined semi-annually based upon a number of factors, including commodity prices and our oil and gas reserves. We or the lenders can each request one additional borrowing base redetermination each calendar year.
The maturity date under our revolving credit facility is May 7, 2020. Borrowings bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 2% to 3%, or the sum of the London Interbank Offered Rate (“LIBOR”) rate plus an applicable margin ranging from 3% to 4%. Margins vary based on the borrowings outstanding compared to the borrowing base. In addition, we pay an annual commitment fee of 0.50% of unused borrowings available under our revolving credit facility.
We had outstanding borrowings of $301.5 million and $291 million under our revolving credit facility at December 31, 2018 and 2017, respectively. The weighted average interest rate applicable to borrowings under our revolving credit facility in 2018 was 6%. We also had outstanding unused letters of credit under our revolving credit facility totaling $0.3 million at December 31, 2018, which reduce amounts available for borrowing under our revolving credit facility.
Obligations under our revolving credit facility are secured by mortgages on substantially all of the oil and gas properties of the Company and its subsidiaries. The Company is required to maintain liens covering the oil and gas properties of the Company and its subsidiaries representing at least 95% of the total value of all oil and gas properties of the Company and its subsidiaries.
On December 21, 2017, we entered into a fourth amendment to the revolving credit facility. The fourth amendment, among other things, (a) extended the maturity date of the revolving credit facility from May 7, 2019, to May 7, 2020, (b) added the total leverage ratio financial covenant, (c) increased the applicable margin rates on borrowings by 50 basis points, and (d) required the Company to hedge 50% of the Company’s estimated 2018 oil and gas production from PDP reserves. In connection with the fourth amendment to the revolving credit facility, we incurred $1 million of debt issuance costs.
On May 3, 2016, we entered into a third amendment to our revolving credit facility. Specifically, the third amendment (a) decreased the borrowing base to $325 million from $450 million, (b) increased the applicable margin rates on borrowings by 100 basis points, (c) permits the Company to issue up to $150 million of second lien indebtedness, subject to various conditions and limitations, (d) permits the Company to repurchase outstanding debt with proceeds of certain asset sales, equity issuances or second lien indebtedness and (e) requires cash and cash equivalents in excess of $35 million held by the Company to be applied to reduce outstanding borrowings under our revolving credit facility. In connection with the third amendment to our revolving credit facility, $0.6 million of debt issuance costs were written off as a result of the reduction in the borrowing base, and we incurred $0.2 million of debt issuance costs.
Covenants
Our revolving credit facility contains three principal financial covenants:
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a consolidated interest coverage ratio covenant that requires us to maintain a ratio of (i) consolidated EBITDAX for the period of four fiscal quarters then ending to (ii) Cash Interest Expense for such period as of the last day of any fiscal quarter of not less than 1.75 to 1.0 through December 31, 2018, a ratio of not less than 2.25 to 1.0 through December 31, 2019, and 2.5 to 1.0 thereafter. EBITDAX is defined as consolidated net (loss) income plus (i) interest expense, net, (ii) income tax provision (benefit), (iii) depreciation, depletion, amortization, (iv) exploration expenses and (v) other noncash loss or expense (including share-based compensation and the change in fair value of any commodity derivatives), less noncash income. Cash Interest Expense is calculated as interest expense, net less amortization of debt issuance costs. At December 31, 2018, our consolidated interest coverage ratio was 2.5 to 1.0;
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a consolidated modified current ratio covenant that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. The consolidated modified current ratio is defined as the ratio of (i) current assets plus funds available under our revolving credit facility, less the current derivative asset, to (ii) current liabilities less the current derivative liability. At December 31, 2018, our consolidated modified current ratio was 1.6 to 1.0; and
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a consolidated total leverage ratio covenant that imposes a maximum permitted ratio of (i) Total Debt to (ii) EBITDAX for the period of four fiscal quarters then ending of no more than 5.0 to 1.0, as of the last day of any fiscal quarter from March 31, 2019, through June 30, 2019, thereafter no more than 4.75 to 1.0 as of the last day of any fiscal quarter through December 31, 2019, and (iii) no more than 4.0 to 1.0 as of the last day of any fiscal quarter thereafter. Total Debt is defined as the face or principal amount of debt. Our leverage ratio is currently above the level that will be required as of March 31, 2019. At December 31, 2018, our leverage ratio was 6.6 to 1.0.
Failure to comply with any of the financial covenants under our revolving credit facility would represent an event of default. In the case of an event of default the lenders (i) would not be required to lend any additional amounts to us, (ii) could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees, to be due and payable, (iii) could require us to apply all of our available cash to repay these borrowings and (iv) could prevent us from making debt service payments under our other agreements.
Our revolving credit facility also contains covenants restricting cash distributions and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investment in other entities and liens on properties.
The obligations of the Company may be accelerated upon the occurrence of an Event of Default (as defined in our revolving credit facility). Events of default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as defined in our revolving credit facility), which includes instances where a third party becomes the beneficial owner of more than 50% of the Company’s outstanding equity interests entitled to vote.
At December 31, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default under our debt instruments. See Note 1 to our consolidated financial statements in this report for additional information regarding our plans to improve our leverage and our ability to continue to comply with the financial covenants under our revolving credit facility.
To date, we have experienced no disruptions in our ability to access our revolving credit facility. However, our lenders have substantial ability to reduce our borrowing base on the basis of subjective factors, including the loan collateral value that each lender, in its discretion and using the methodology, assumptions and discount rates as such lender customarily uses in evaluating oil and gas properties, assigns to our properties.
Senior Notes
At December 31, 2018, and 2017, $85.2 million principal amount of Senior Notes was outstanding. Annual interest on the Senior Notes is payable semi-annually on June 15 and December 15.
During the year ended December 31, 2017, we completed the two debt-for-equity exchange transactions, which reduced the outstanding principal balance of our Senior Notes by $145.1 million and reduced future interest payments by $44.3 million over the remaining term of the Senior Notes.
We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wilmington Trust, National Association, as successor trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.”
On December 20, 2016, we entered into the second supplemental indenture (the “Second Supplemental Indenture”), which became effective on January 27, 2017, in connection with the closing of the Initial Exchange. The Second Supplemental Indenture (i) eliminated certain definitions and references to definitions contained in the Indenture, (ii) eliminated and revised, as applicable, certain events of default contained in the Indenture, (iii) eliminated certain conditions to consolidation, merger, conveyance, transfer or lease contained in the Indenture, (iv) eliminated certain covenants contained in the Indenture, including substantially all of the restrictive covenants set forth therein, and (v) supplemented and amended the Senior Notes and the securities guarantees, as and to the same extent as the Indenture has been amended and supplemented in accordance with the preceding clauses (i), (ii), (iii) and (iv).
We may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:
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in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if the sale or other disposition otherwise complies with the Indenture;
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in connection with any sale or other disposition of the capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if that guarantor no longer qualifies as a subsidiary of the Company as a result of such disposition and the sale or other disposition otherwise complies with the Indenture;
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if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the Indenture;
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upon defeasance or covenant defeasance of the notes or satisfaction and discharge of the Indenture, in each case, in accordance with the Indenture;
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upon the liquidation or dissolution of that guarantor, provided that no default or event of default occurs under the Indenture as a result thereof or shall have occurred and is continuing; or
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in the case of any restricted subsidiary that, after the issue date of the notes is required under the Indenture to guarantee the notes because it becomes a guarantor of indebtedness issued or an obligor under the revolving credit facility with respect to the Company and/or its subsidiaries, upon the release or discharge in full from its (x) guarantee of such indebtedness or (y) obligation under such revolving credit facility, in each case, which resulted in such restricted subsidiary’s obligation to guarantee the notes.
As a result of the Second Supplemental Indenture, the Indenture contains limited events of default.
At December 31, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments. An event of default under our revolving credit facility would not result in an event of default under our Senior Notes.
Contractual Obligations
As of December 31, 2018, our contractual obligations include long-term debt, operating lease obligations, asset retirement obligations and employment agreements with our executive officers.
In April 2007, we signed a five-year lease for approximately 13,000 square feet of office space in Fort Worth, Texas. Since that time, we have expanded the lease to approximately 35,000 square feet and extended the term to September 30, 2021.
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.
At December 31, 2018, we had outstanding employment agreements with all four of our executive officers that contained automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless the employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, was approximately $6.5 million at December 31, 2018. This estimate assumes the maximum potential bonus for 2018 is earned by each executive officer during 2018.
The following table summarizes these commitments as of December 31, 2018 (in thousands).
(1)
Credit agreement matures on May 7, 2020. See Note 3 to our consolidated financial statements in this report for a discussion regarding interest payable under our revolving credit facility.
(2)
7% Senior Notes due 2021, including interest payable semi-annually on June 15 and December 15.
(3)
Operating lease obligations are for office space and equipment.
(4)
See Note 1 to our consolidated financial statements in this report for a discussion of our asset retirement obligations.
(5)
See Note 5 to our consolidated financial statements in this report for a discussion of our cash-settled performance awards. The amount above assumes that performance criteria of the cash-settled performance awards are met.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some 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. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 1 to our consolidated financial statements in this report.
Segment reporting is not applicable to us as we have a single, company-wide management team that administers all significant properties as a whole, rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis. We use the successful efforts method of accounting for our oil and gas activities.
Successful Efforts Method of Accounting
Accounting for oil and gas activities is subject to special, unique rules. We use the successful efforts method of accounting for our oil and gas activities. The significant principles for this method are:
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costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves;
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dry holes for exploratory wells are expensed and dry holes for development wells are capitalized;
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geological and geophysical evaluation costs are expensed as incurred; and
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capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge in income from operations equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows.
Proved Reserves
For the year ended December 31, 2018, we engaged DeGolyer and MacNaughton, independent petroleum engineers, to prepare independent estimates of the extent and value of 100% of our reported proved reserves, in accordance with rules and guidelines established by the SEC.
Estimates of proved oil and gas reserves directly impact financial accounting estimates including DD&A, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are those quantities of 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. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time due to results from operational activity. Proved reserve volumes at December 31, 2018, were estimated based on the average of the closing price on the first day of each month for the 12-month period prior to December 31, 2018, for oil, NGLs and gas in accordance with SEC rules. Changes in commodity prices and operations costs may increase or decrease estimates of proved oil, NGLs and natural gas reserves. Depletion expense for our oil and gas properties is determined using our estimates of proved oil, NGLs and gas reserves.
See also Item 2. “Properties - Proved Oil and Gas Reserves” and Note 10 to our consolidated financial statements in this report for additional information regarding our estimated proved reserves.
Derivative Instruments and Commodity Derivative Activities
We enter into commodity derivative contracts to mitigate portions of the risk of market price fluctuations related to future oil, NGLs and gas production. Derivative assets and liabilities on our commodity derivative contracts, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts, not designated as cash-flow hedges, and cash settlements are recorded in earnings as they occur on our consolidated statements of operations under the caption entitled “commodity derivative loss.” For commodity derivative contracts designated as cash-flow hedges, the changes in fair value of the derivative contracts, to the extent the hedge is effective, will be recognized in other comprehensive income until the hedged item is recognized in revenue.
We estimate the fair values of swap or collar contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets.
We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.
For the years ended December 31, 2018, 2017 and 2016 we recognized commodity derivative losses of $0.3 million, $0.3 million and $5.5 million, respectively.
Asset Retirement Obligation
Our asset retirement obligation primarily represents the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives, in accordance with applicable federal, state and local laws. We determine our asset retirement obligation by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value as of the asset’s inception, with an offsetting increase to proved properties. Periodic accretion of discount of the estimated liability is recorded as an expense in the income statement.
Our liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of wells and our risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation.
Impairment of Long-Lived Assets
All of our long-lived assets are monitored for potential impairment when circumstances indicate that the carrying value of an asset may be greater than its future net cash flows. The evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil, NGLs and gas, future costs to produce these products, estimates of future oil and gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test an asset for impairment may result from significant declines in commodity prices or downward revisions to estimated quantities of oil and gas reserves. Any assets held for sale are reviewed for impairment when we approve the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, we cannot predict when or if future impairment charges will be recorded.
Provision for Income Taxes
We estimate our provision for income taxes using historical tax basis information from prior years’ income tax returns, along with the estimated changes to such bases from current-period activity and enacted tax rates. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the
position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes in our consolidated statements of operations. Additionally, we compare liabilities to actual settlements of such assets or liabilities during the current period to identify considerations that might affect the current period’s estimate.
We monitor our deferred tax assets by jurisdiction to assess their potential realization, and a valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are more likely than not to not be realized. In performing this review, we make estimates and assumptions regarding projected future taxable income, the expected timing of reversals of existing temporary differences and the implementation of tax planning strategies. To the extent that a valuation allowance is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense. We currently have a valuation allowance of $0.5 million on our deferred tax assets.
Valuation of Share-Based Compensation
Our 2018 Long Term Incentive Plan and our 2007 Stock Incentive Plan (collectively, the “Incentive Plans”) allow grants of stock and options to employees and outside directors. Granting of awards may increase our G&A, subject to the size and timing of the grants. See Note 4 to our consolidated financial statements in this report for additional information.
In accordance with GAAP, we calculate the fair value of share-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. We use (i) the closing stock price on the date of grant for the fair value of restricted stock awards, including performance-based awards, (ii) the Monte Carlo simulation method for the fair value of market-based awards, (iii) the fair market value of our common stock on the valuation date for cash-settled performance awards and (iv) the Black-Scholes option price model to measure the fair value of stock options.
Recently Issued Accounting Standards
In February 2016, FASB issued an accounting standards update for “Leases,” which amends existing guidance to require lessees to recognize liabilities and right-of-use (“ROU”) assets on the balance sheet for the rights and obligations created by long-term leases and to disclose additional quantitative and qualitative information about leasing arrangements. This new guidance is effective for interim and annual periods beginning after December 15, 2018, and we adopted it using a modified retrospective approach on January 1, 2019 using the transition method that allows a cumulative-effect adjustment to the opening balance to retained earnings in the period of adoption.
We currently enter into lease agreements to support our operations. These agreements are for leases on assets such as office space, compressors and well equipment. We have substantially completed our process to implement this standard, and we have designed processes and internal controls necessary for adoption of this standard. We have made policy elections to (i) not capitalize short-term leases for all asset classes, (ii) to not separate non-lease components from lease components for all of our current asset classes, (iii) apply the package of practical expedients that allows us to not reassess: whether any expired or existing contracts contain leases, lease classification for any expired or existing leases and initial direct costs for existing leases, (iv) apply the land easement practical expedient to not evaluate land easements that existed or expired prior to adoption and (v) apply the practical expedient to apply hindsight in estimating lease term and impairment.
The impact of applying this standard is not expected to significantly impact our results of operations or cash flows. As of January 1, 2019, we expect to recognize ROU assets and liabilities of approximately $15 million from operating leases on our consolidated balance sheet. We expect an increase in our working capital deficit due to the adoption of this standard as the entire ROU asset balance will be presented as a non-current asset, and a portion of the lease liability will be presented as a current liability. Under the terms of our revolving credit facility, the current liability related to operating leases will not be considered in our modified current ratio financial covenant calculation.
Effects of 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, 2018, 2017 or 2016. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property and equipment. It may also increase the cost of labor or supplies.
Off-Balance Sheet Arrangements
From time-to-time, we enter into off-balance sheet arrangements and transactions that can give rise to off-balance sheet obligations. As of December 31, 2018, the off-balance sheet arrangements and transactions that we have entered into include undrawn letters of credit and operating lease agreements. We do not believe that these arrangements are reasonably likely to materially affect our liquidity or availability of, or requirements for, capital resources.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Some of the information below contains forward-looking statements. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, NGLs and gas prices, and other related factors. The disclosure is not meant to be a precise indicator of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides an indicator of how we view and manage our ongoing market risk exposures. Our market risk sensitive instruments were entered into for commodity derivative and investment purposes, not for trading purposes.
Proved Reserves
Estimates of proved oil and gas reserves directly impact financial accounting estimates including DD&A, evaluation of impairment of properties and the calculation of plugging and abandonment liabilities. Proved oil and gas reserves are those quantities of 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. The process of estimating quantities of proved reserves is very complex, requiring significant subjective decisions in the evaluation of all geological, engineering and economic data for each reservoir. The data for any reservoir may change substantially over time due to results from operational activity. Proved reserve volumes at December 31, 2018, were estimated based on the average of the closing price on the first day of each month for the 12-month period prior to December 31, 2018, for oil, NGLs and natural gas in accordance with SEC rules. Changes in commodity prices and operations costs may increase or decrease estimates of proved oil, NGLs and natural gas reserves.
We expect that reductions in oil, NGLs and gas prices will not only decrease our revenues, but will also reduce the amount of oil, NGLs and gas that we can produce economically and therefore lower our oil, NGLs and gas reserves. A decrease of 10% in the oil, NGLs and gas prices used in our reserve report as of December 31, 2018, holding production and development costs constant, would result in:
•
a decrease in our PV-10 as of December 31, 2018 of 26 %;
•
a decrease in our total proved reserves of 4%; and
•
a decrease in our proved undeveloped reserves of 6%.
Actual future net revenues and reserve volumes also will be affected by factors such as the amount and timing of actual production, prevailing operating and development costs, supply and demand for oil and gas, increases or decreases in consumption and changes in governmental regulations or taxation. Additionally, depletion expense for our oil and gas properties is determined using our estimates of proved oil, NGLs and natural gas reserves. A hypothetical 10% decline in our December 31, 2018, estimated proved reserves would have increased our depletion expense by approximately $1.6 million for the year ended December 31, 2018.
Commodity Price Risk
Given the current economic outlook, we expect commodity prices to remain volatile. Even modest decreases in commodity prices can materially affect our revenues and cash flow. In addition, if commodity prices remain suppressed for a significant amount of time, we could be required under successful efforts accounting rules to write down our oil and gas properties.
In the year ended December 31, 2018, the NYMEX WTI prompt month price ranged from a low of $42.53 per barrel to a high of $76.41 per barrel. In the year ended December 31, 2017, the NYMEX WTI prompt month price ranged from a low of $42.53 per barrel to a high of $60.42 per barrel.
In the year ended December 31, 2018, the NYMEX Henry Hub natural gas prompt month price ranged from a low of $2.55 per MMBtu to a high of $4.84 per MMBtu. In the year ended December 31, 2017, the NYMEX Henry Hub natural gas prompt month price ranged from a low of $2.56 per MMBtu to a high of $3.72 per MMBtu.
We enter into financial swaps and options to reduce the risk of commodity price fluctuations. As of December 31, 2018, we had no outstanding derivative instruments designated as cash-flow hedges. We record open commodity derivative positions on our consolidated balance sheets at fair value and recognize changes in such fair values as commodity derivative loss on our consolidated statements of operations as they occur, for commodity derivative contracts not designated as cash-flow hedges.
The table below summarizes our commodity derivatives positions outstanding at December 31, 2018.
At December 31, 2018, the fair value of our open derivative contracts was a net asset of $5.9 million, compared to net liability of $0.8 million at December 31, 2017.
We are exposed to credit losses in the event of nonperformance by counterparties on our commodity derivatives positions. We do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions; however, we cannot be certain that we will not experience such losses in the future. All of the counterparties to our commodity derivative positions are participants in our revolving credit facility, and the collateral for the outstanding borrowings under our revolving credit facility is used as collateral for our commodity derivatives.
Derivative assets and liabilities on our commodity derivative contracts, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Cash settlements under our commodity derivative contracts and changes in the fair value of our commodity derivative contracts, not designated as cash-flow hedges are recorded in earnings as they occur and included in commodity derivative loss on our consolidated statements of operations. We estimate the fair values of swap or collar contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets.
For the years ended December 31, 2018, 2017 and 2016 we recognized commodity derivative losses of $0.3 million, $0.3 million and $5.5 million, respectively. A hypothetical 10% increase in the NYMEX floating prices would have resulted in a $1.7 million decrease in the fair value recorded of our commodity derivative positions on our balance sheet at December 31, 2018, and a corresponding increase to the commodity derivative loss on our statement of operations for the year ended December 31, 2018.
See Note 7 to our consolidated financial statements in this report for a discussion of our fair value measurements.
Interest Rate Risk
We are exposed to interest rate risk on the outstanding borrowings under our revolving credit facility. At December 31, 2018, we had $301.5 million outstanding under our revolving credit facility. Outstanding borrowings under our revolving credit facility bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 2% to 3%, or the sum of the London Interbank Offered Rate (“LIBOR”) rate plus an applicable margin ranging from 3% to 4%. Margins vary based on the borrowings outstanding compared to the borrowing base. A hypothetical increase of 50 basis points in the floating interest rate on outstanding borrowings under our revolving credit facility at December 31, 2018, would result in a $1.5 million increase in annual interest expense. We currently do not engage in any interest rate hedging activities.
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Our consolidated financial statements and supplemental data are included in this report beginning on page.
ITEM 9.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
We had no changes in, and no disagreements with, our accountants on accounting and financial disclosure.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness 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, 2018. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of December 31, 2018, our disclosure controls and procedures were effective, in that they ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting
Management’s Annual Report on Internal Control Over Financial Reporting and Attestation Report of Registered Public Accounting Firm
Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, we have included a report of management’s assessment of the design and effectiveness of our internal controls as part of this annual report on Form 10-K for the fiscal year ended December 31, 2018. Moss Adams LLP (“Moss Adams”), our independent registered public accounting firm, also attested to, and reported on, our internal control over financial reporting. Management’s report and Moss Adams’s attestation report are referenced on page under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm -Internal Control over Financial Reporting” and are incorporated herein by reference.
Changes in Internal Control over Financial Reporting
No changes to our internal control over financial reporting occurred during the quarter ended December 31, 2018, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act).
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required under Item 10 of this report will be contained under the captions “Election of Directors-Directors,” “Executive Officers” and “Corporate Governance” to be provided in our proxy statement for our 2019 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2018, which is incorporated herein by reference. Also, the charters of our Audit Committee, Compensation Committee and Nominating and Corporate Governance Committee, our Lead Independent Director Charter, our Governance Guidelines and our Code of Conduct may be found on our website at www.approachresources.com.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
Information required by Item 11 of this report will be contained under the caption “Executive Compensation” in our definitive proxy statement for our 2019 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2018, which is incorporated herein by reference.
ITEM 12.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information required by Item 12 of this report will be contained under the caption “Stock Ownership Matters” in our definitive proxy statement for our 2019 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2018, which is incorporated herein by reference.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information required by Item 13 of this report will be contained under the captions “Certain Relationships and Related-Party Transactions” and “Corporate Governance-Board Independence” in our definitive proxy statement for our 2019 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2018, which is incorporated herein by reference.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
Information required by Item 14 of this report will be contained under the caption “Independent Registered Public Accountants” in our definitive proxy statement for our 2019 annual meeting of stockholders to be filed with the SEC within 120 days of December 31, 2018, which is incorporated herein by reference.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
Documents filed as part of this report
(1) and (2) Financial Statements.
See “Index to Consolidated Financial Statements” on page.
All financial statement schedules are omitted because they are not applicable, or are immaterial or the required information is presented in the consolidated financial statements or the related notes.
(3) Exhibits.
The following documents are filed as exhibits to this report.
Exhibit Number
Exhibit title
3.1
Certificate of Amendment of Restated Certificate of Incorporation of Approach Resources Inc. (filed as Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed March 10, 2017, and incorporated herein by reference).
3.2
Restated Certificate of Incorporation of Approach Resources Inc. (filed as Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed December 13, 2007, and incorporated herein by reference).
3.3
Second Amended and Restated Bylaws of Approach Resources Inc. (filed as Exhibit 3.2 to the Company’s Current Report on Form 8-K filed November 8, 2013, and incorporated herein by reference).
4.1
Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512), and incorporated herein by reference).
4.2
Second Supplemental Indenture, dated as of December 20, 2016, by and among Approach Resources Inc., the guarantors named therein and Wilmington Trust, National Association, as successor trustee under the Indenture (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed December 22, 2016, and incorporated herein by reference).
4.3
First Supplemental Indenture, dated as of June 11, 2013, among Approach Resources Inc., as issuer, the subsidiary guarantors named therein, as guarantors, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed June 11, 2013, and incorporated herein by reference).
4.4
Senior Indenture, dated as of June 11, 2013, among Approach Resources Inc., as issuer, the subsidiary guarantors named therein, as guarantors, and Wells Fargo Bank, National Association, as trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K filed June 11, 2013, and incorporated herein by reference).
4.5
Agreement dated as of April 28, 2016, by and among Approach Resources Inc., Wells Fargo Bank, National Association, and Wilmington Trust, National Association (filed as Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q filed August 4, 2016, and incorporated herein by reference).
Exhibit Number
Exhibit title
4.6
Registration Rights Agreement, dated as of January 27, 2017, by and among Approach Resources Inc., Wilks Brothers, LLC and SDW Investments, LLC (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K filed January 30, 2017, and incorporated herein by reference).
4.7
Registration Rights Agreement, dated as of November 14, 2007, by and among Approach Resources Inc. and investors identified therein (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K/A filed December 3, 2007, and incorporated herein by reference).
4.8
Registration Rights Agreement, dated as of November 20, 2017, by and among Approach Resources Inc. and Amistad Energy Partners, LLC (filed as Exhibit 4.8 to the Company’s Annual Report on Form 10-K filed March 9, 2018, and incorporated herein by reference).
10.1
Form of Amended and Restated Indemnity Agreement between Approach Resources Inc. and each of its directors and officers (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 7, 2012 (File No. 333-144512), and incorporated herein by reference).
10.2†
Amended and Restated Employment Agreement by and between Approach Resources Inc. and J. Ross Craft dated January 1, 2011 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 6, 2011, and incorporated herein by reference).
10.3†
Amendment to Employment Agreement by and between Approach Resources Inc. and J. Curtis Henderson dated January 26, 2017 (filed as Exhibit 10.3 to the Company’s Annual Report on Form 10-K filed March 10, 2017, and incorporated herein by reference).
10.4†
Employment Agreement by and between Approach Resources Inc. and J. Curtis Henderson dated January 1, 2011 (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K filed January 6, 2011, and incorporated herein by reference).
10.5†
Amendment to Employment Agreement by and between Approach Resources Inc. and Qingming Yang dated January 26, 2017 (filed as Exhibit 10.5 to the Company’s Annual Report on Form 10-K filed March 10, 2017, and incorporated herein by reference).
10.6†
Employment Agreement by and between Approach Resources Inc. and Qingming Yang dated January 24, 2011 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 28, 2011, and incorporated herein by reference).
10.7†
Employment Agreement by and between Approach Resources Inc., and Sergei Krylov dated January 3, 2014 (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed May 9, 2014, and incorporated herein by reference).
10.8
Form of Business Opportunities Agreement among Approach Resources Inc. and the other signatories thereto (filed as Exhibit 10.11 to the Company’s Registration Statement on Form S-1/A filed October 18, 2007 (File No. 333-144512), and incorporated herein by reference).
10.9†
2018 Long Term Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 6, 2018, and incorporated herein by reference).
10.10†
Sixth Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan effective as of June 7, 2017 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 7, 2017, and incorporated herein by reference).
10.11†
Fifth Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan effective as of June 2, 2016 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 2, 2016, and incorporated herein by reference).
Exhibit Number
Exhibit title
10.12†
Fourth Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed May 5, 2016, and incorporated herein by reference).
10.13†
Third Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 2, 2015, and incorporated herein by reference).
10.14†
Second Amendment to the Approach Resources Inc. 2007 Stock Incentive Plan, effective as of May 31, 2012 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed June 1, 2012, and incorporated herein by reference).
10.15†
First Amendment dated December 31, 2008, to Approach Resources Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007 (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 31, 2008, and incorporated herein by reference).
10.16†
Approach Resources Inc. 2007 Stock Incentive Plan, effective as of June 28, 2007 (filed as Exhibit 10.6 to the Company’s Registration Statement on Form S-1 filed July 12, 2007, and incorporated herein by reference).
10.17†
Second Revised Form of TSR-Based Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q filed May 3, 2018, and incorporated herein by reference).
10.18†
Revised Form of Cash Settled Performance Share Unit Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed May 3, 2018, and incorporated herein by reference).
10.19†
Form of Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q filed November 6, 2008, and incorporated herein by reference).
10.20†
Form of Performance-Based, Time-Vesting Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.14 to the Company’s Annual Report on Form 10-K filed March 11, 2011, and incorporated herein by reference).
10.21†
Revised Form of TSR-Based Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.17 to the Company’s Annual Report on Form 10-K filed March 10, 2017, and incorporated herein by reference).
10.22†
Form of TSR-Based Restricted Stock Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed February 20, 2012, and incorporated herein by reference).
10.23†
Form of Cash Settled Performance Share Unit Award Agreement under Approach Resources Inc. 2007 Stock Incentive Plan (filed as Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q filed May 5, 2016, and incorporated herein by reference).
10.24
Exchange Agreement, dated as of November 2, 2016, by and among Approach Resources Inc., Wilks Brothers, LLC and SDW Investments, LLC (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 3, 2016, and incorporated herein by reference).
Exhibit Number
Exhibit title
10.25
Stockholder Agreement, dated as of January 27, 2017, by and among Approach Resources Inc., Wilks Brothers, LLC and SDW Investments, LLC (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 30, 2017, and incorporated herein by reference).
10.26
Amendment dated August 4, 2014 to Gas Purchase Contract dated as of January 1, 2011, between Approach Resources I, LP and Approach Oil & Gas Inc., as Seller, and DCP Midstream, LP, as Buyer (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission) (filed as Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q filed November 6, 2014, and incorporated herein by reference).
10.27
Gas Purchase Contract dated as of January 1, 2011, between Approach Resources I, LP and Approach Oil & Gas Inc., as Seller, and DCP Midstream, LP, as Buyer (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 14, 2011, and incorporated herein by reference).
10.28
Specimen Oil and Gas Lease for University Lands (filed as Exhibit 10.19 to the Company’s Annual Report on Form 10-K filed March 12, 2012, and incorporated herein by reference).
10.29
Fourth Amendment dated as of December 21, 2017, to Amended and Restated Credit Agreement dated as of May 7, 2014, by and among the Company and its subsidiary guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed December 26, 2017, and incorporated herein by reference).
10.30
Third Amendment dated as of May 3, 2016, to Amended and Restated Credit Agreement dated as of May 7, 2014, by and among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 4, 2016, and incorporated herein by reference).
10.31
Second Amendment dated as of December 30, 2014, to Amended and Restated Credit Agreement, dated as of May 7, 2014, by and among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed January 6, 2015, and incorporated herein by reference).
10.32
First Amendment dated as of November 4, 2014, to Amended and Restated Credit Agreement, dated as of May 7, 2014, by and among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed November 5, 2014, and incorporated herein by reference).
10.33
Amended and Restated Credit Agreement, dated as of May 7, 2014, by and among the Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders from time-to-time party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed May 8, 2014, and incorporated herein by reference).
Exhibit Number
Exhibit title
10.34
Amended and Restated Guaranty and Pledge Agreement, dated as of May 7, 2014, by and among the Company, the subsidiary guarantors and JPMorgan Chase Bank, N.A., as Administrative Agent (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K filed May 8, 2014, and incorporated herein by reference).
10.35
Amendment No. 1 to Crude Oil Purchase Agreement dated as of October 7, 2013, between Approach Operating, LLC, Approach Oil & Gas Inc. and Approach Resources I, LP, and Wildcat Permian Services LLC and JP Energy Development, LP (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission) (filed as Exhibit 10.37 to the Company’s Annual Report on Form 10-K filed February 25, 2014, and incorporated herein by reference).
10.36
Crude Oil Purchase Agreement dated as of September 12, 2012, between Approach Operating, LLC and Approach Oil & Gas Inc., as Seller, and Wildcat Permian Services LLC, as Buyer (pursuant to a request for confidential treatment, portions of this exhibit have been redacted and have been provided separately to the Securities and Exchange Commission) (filed as Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q filed or November 6, 2012, and incorporated herein by reference).
*12.1
Statement of Computation Ratio of Earnings to Fixed Charges.
14.1
Code of Conduct (filed as Exhibit 14.1 to the Company’s Annual Report on Form 10-K filed March 28, 2008, and incorporated herein by reference).
*21.1
Subsidiaries.
*23.1
Consent of Moss Adams LLP.
*23.2
Consent of Hein & Associates LLP.
*23.3
Consent of DeGolyer and MacNaughton.
*31.1
Certification by the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*31.2
Certification by the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
*32.1
Certification by the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*32.2
Certification by the Chief Financial Officer Pursuant to U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
*99.1
Report of DeGolyer and MacNaughton.
*101.INS
XBRL Instance Document.
*101.SCH
XBRL Taxonomy Extension Schema Document.
*101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document.
*101.LAB
XBRL Taxonomy Extension Label Linkbase Document.
Exhibit Number
Exhibit title
*101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document.
*101.DEF
XBRL Taxonomy Extension Definition Linkbase Document.
*
Filed herewith.
†
Denotes management contract or compensatory plan or arrangement.
ITEM 16.
FORM 10-K SUMMARY
None.
GLOSSARY AND SELECTED ABBREVIATIONS
The following is a description of the meanings of some of the oil and gas industry terms used in this report.
3-D seismic
(Three Dimensional Seismic Data) Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two dimensional seismic data.
Basin
A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Bbl
One stock tank barrel, of 42 U.S. gallons liquid volume, used to reference oil, condensate or NGLs.
Boe
Barrel of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.
Btu or British Thermal Unit
The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion
The installation of permanent equipment for production of oil or gas, or, in the case of a dry well, for reporting to the appropriate authority that the well has been abandoned.
Developed acreage
The number of acres that are allocated or assignable to productive wells or wells that are capable of production.
Developed oil and gas reserves
Has the meaning given to such term in Rule 4-10(a)(6) of Regulation S-X, as follows:
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development project
The means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Development well
A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well
An exploratory, development or extension well that proved to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
Dry hole costs
Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.
Exploratory well
A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.
Extension well
A well drilled to extend the limits of a known reservoir.
Farm-in
An arrangement in which the owner or lessee of mineral rights (the first party) assigns a working interest to an operator (the second party), the consideration for which is specified exploration and/or development activities. The first party retains an overriding royalty, working interest or other type of economic interest in the mineral production. The arrangement from the viewpoint of the second party is termed a “farm-in” arrangement.
Field
An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Field fuel
Gas consumed to operate field equipment (primarily for compressors and artificial lifts).
Hydraulic fracturing
The technique designed to improve a well’s production rates by pumping a mixture of water and sand (in our case, over 99% by mass) and chemical additives (in our case, less than 1% by mass) into the formation and rupturing the rock, creating an artificial channel.
Henry Hub
Henry Hub is the major exchange for pricing for natural gas futures on the NYMEX.
Gross acres or gross wells
The total acres or wells, as the case may be, in which a working interest is owned.
Lease operating expenses
The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
LNG
Liquefied natural gas.
MBbls
Thousand barrels of oil or other liquid hydrocarbons.
MBoe
Thousand barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.
Mcf
Thousand cubic feet of natural gas.
MMBoe
Million barrels of oil equivalent, determined using the ratio of six Mcf of gas to one Boe, and one Bbl of NGLs to one Boe.
MMBtu
Million British thermal units.
MMcf
Million cubic feet of gas.
Net acres or net wells
The sum of the fractional working interests owned in gross acres or wells, as the case may be.
NGLs
Natural gas liquids. The portions of gas from a reservoir that are liquefied at the surface in separators, field facilities or gas processing plants.
NYMEX
New York Mercantile Exchange.
Play
A set of known or postulated oil and/or gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.
Productive well
An exploratory, development or extension well that is not a dry well.
Prospect
A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed producing reserves
Proved developed oil and gas reserves that are expected to be recovered:
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii)
Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Proved oil and gas reserves
Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, as follows:
Proved oil and gas reserves are those quantities of 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.
(i)
The area of the reservoir considered as proved includes:
(A)
The area identified by drilling and limited by fluid contacts, if any, and
(B)
Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv)
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A)
Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B)
The project has been approved for development by all necessary parties and entities, including governmental entities.
(v)
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
PV-10
An estimate of the present value of the future net revenues from proved oil and gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of PV-10 are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.
“Recompletion” or to “recomplete” a well
The addition of production from another interval or formation in an existing wellbore.
Reserve life
This index is calculated by dividing year-end 2018 estimated proved reserves by 2018 production of 4.1 MMBoe to estimate the number of years of remaining production.
Reservoir
A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Spacing
The distance between wells producing from the same reservoir. Spacing is expressed in terms of acres (e.g., 40-acre spacing) and is established by regulatory agencies.
Standardized measure
The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the period end date) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depletion, depreciation and amortization and discounted using an annual discount rate of 10%. Standardized measure does not give effect to derivative transactions.
Tight gas sands
A sandstone formation with low permeability that produces natural gas with low flow rates for long periods of time.
Unconventional resources or reserves
Natural gas or oil resources or reserves from (i) low-permeability sandstone and shale formations and (ii) coalbed methane.
Undeveloped acreage
Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether such acreage contains proved reserves.
Undeveloped oil and gas reserves
Has the meaning given to such term in Rule 4-10(a)(31) of Regulation S-X, which defines proved undeveloped reserves as follows:
Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i)
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii)
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
(iii)
Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir, an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
Working interest
The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
Workover
Operations on a producing well to restore or increase production.
WTI
West Texas Intermediate, a grade of crude oil used as a benchmark in oil pricing.
/d
“Per day” when used with volumetric units or dollars.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Date: March 18, 2019
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated and on March 18, 2019.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS OF APPROACH RESOURCES INC.
Page
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm - Internal Control Over Financial Reporting
Reports of Independent Registered Public Accounting Firms - Financial Statements
Consolidated Balance Sheets as of December 31, 2018 and 2017
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to management and our board of directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2018. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control -Integrated Framework in 2013. Based on our assessment, we believe that, as of December 31, 2018, our internal control over financial reporting is effective based on those criteria.
Moss Adams LLP, the independent registered public accounting firm that audited our financial statements included in this annual report, has issued an attestation report on our internal control over financial reporting as of December 31, 2018. This report appears on the following page.
By:
/s/ J. Ross Craft
By:
/s/ Sergei Krylov
J. Ross Craft
Sergei Krylov
Chairman of the Board and Chief Executive Officer
Executive Vice President and Chief Financial Officer
Fort Worth, Texas
March 18, 2019
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of
Approach Resources Inc.
Opinion on Internal Control over Financial Reporting
We have audited Approach Resources Inc. and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2018, 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 Company maintained, in all material respects, effective control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of Approach Resources Inc. and subsidiaries as of December 31, 2018 and 2017, the related consolidated statements of operations, change in stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”) and our report dated March 18, 2019 expressed an unqualified opinion on those consolidated financial statements (and included an explanatory paragraph relating to the Company’s ability to continue as a going concern).
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting included in Item 9A. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the 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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
/s/ Moss Adams LLP
Dallas, Texas
March 18, 2019
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of
Approach Resources Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Approach Resources Inc. and subsidiaries (the “Company”) as of December 31, 2018 and 2017, the related consolidated statement of operations, changes in stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2018 and 2017, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 18, 2019 expressed an unqualified opinion on the Company’s internal control over financial reporting.
Going Concern Uncertainty
The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company has determined that, based on its current operating forecast, it will not comply with its debt covenants contained in its revolving credit facility in 2019 which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the 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. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to 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. We believe that our audits provide a reasonable basis for our opinion.
/s/ Moss Adams LLP
Dallas, Texas
March 18, 2019
We have served as the Company’s auditor since 2017.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Approach Resources Inc.
We have audited the accompanying consolidated statements of operations, changes in stockholders’ equity and cash flows of Approach Resources Inc. and subsidiaries (collectively, the “Company”) for the year ended December 31, 2016. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Approach Resources Inc. and subsidiaries for the year ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
/s/ Hein & Associates LLP
Dallas, Texas
March 10, 2017
Approach Resources Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except shares and per-share amounts)
See accompanying notes to these consolidated financial statements.
Approach Resources Inc. and Subsidiaries
Consolidated Statements of Operations
(In thousands, except shares and per-share amounts)
See accompanying notes to these consolidated financial statements.
Approach Resources Inc. and Subsidiaries
Consolidated Statements of Changes in Stockholders’ Equity
for the Years Ended December 31, 2016, 2017 and 2018
(In thousands, except shares and per-share amounts)
See accompanying notes to these consolidated financial statements.
Approach Resources Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In thousands, except shares and per-share amounts)
See accompanying notes to these consolidated financial statements.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements
1.
Summary of Significant Accounting Policies
Organization and Nature of Operations
Approach Resources Inc. (“Approach,” the “Company,” “we,” “us” or “our”) is an independent energy company focused on the exploration, development, production and acquisition of unconventional oil and gas properties. We focus on finding and developing oil and natural gas reserves in oil shale and tight gas sands. Our properties are primarily located in the Permian Basin in West Texas. We also own interests in the East Texas Basin.
Consolidation, Basis of Presentation and Significant Estimates
The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America and include the accounts of the Company and its wholly owned subsidiaries. Intercompany accounts and transactions are eliminated. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies. Actual results may differ from those estimates. Significant assumptions are required in the valuation of proved oil and natural gas reserves, which affect our estimate of depletion expense as well as our impairment analyses. Significant assumptions also are required in our estimation of accrued liabilities, commodity derivatives, income tax provision, share-based compensation and asset retirement obligations. It is at least reasonably possible these estimates could be revised in the near term, and these revisions could be material. Certain prior-year amounts have been reclassified to conform to current-year presentation. These classifications have no impact on the net loss reported. For all periods reported, other comprehensive loss equals net loss.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Going Concern
These consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business for the twelve-month period following the date of issuance of these consolidated financial statements. As such, the accompanying consolidated financial statements do not include any adjustments relating to the recoverability and classification of assets and their carrying amount, or the amount and classification of liabilities that may result should the Company be unable to continue as a going concern.
Our liquidity and ability to comply with debt covenants under our revolving credit facility have been negatively impacted by the recent decrease in commodity prices. Our revolving credit facility contains three principal financial covenants: (i) a consolidated interest coverage ratio, (ii) a consolidated modified current ratio and (iii) a consolidated total leverage ratio. See Note 3 for additional information regarding the financial covenants under our revolving credit facility. At December 31, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.
At December 31, 2018, our total leverage ratio was 6.6 to 1.0, which is above the level that will be required as of March 31, 2019, of 5.0 to 1.0. If we are unable to improve our total leverage ratio by March 31, 2019, the obligations of the Company under the revolving credit facility may be accelerated, which would have a material adverse effect on our business. See Note 3 for additional information regarding the financial covenants under our revolving credit facility. Our total leverage ratio has decreased from 9.7 to 1.0 as of December 31, 2016, to 6.6 to 1.0 as of December 31, 2018. Based on our current operating and commodity price forecast and capital structure, and in the absence of deleveraging transactions as discussed below, we do not believe we will be able to comply with the leverage ratio covenant beginning with the measurement date of March 31, 2019. These factors raise substantial doubt about our ability to continue as a going concern.
In order to continue to improve our leverage position to meet the financial covenants under the revolving credit facility, we are currently pursuing or considering a number of actions, which in certain cases may require the consent of current lenders, stockholders or bond holders. On April 12, 2018, our largest shareholder, Wilks Brothers, LLC, and its affiliate SDW Investments, LLC (collectively, “Wilks”), disclosed on Schedule 13D/A that they intended to engage in discussions with the Company regarding their investment in the Company, including the possible acquisition of additional shares of common stock through the exchange of approximately $60 million aggregate principal amount of 7 % Senior Notes due 2021 (the “Senior Notes”) currently held by Wilks (the “Exchange Transaction”). In April 2018, our board of directors formed a committee of independent directors (the “Special Committee”) to evaluate a potential Exchange Transaction as well as other strategic alternatives. The Special Committee hired financial and legal advisors to advise the Special Committee on these matters. The Special Committee engaged in discussions with Wilks regarding an Exchange Transaction in 2018, but in mid-2018 the Wilks and the Committee deferred further discussions regarding a stand-alone Exchange Transaction pending resolution of the Company’s discussions regarding the potential transaction described in the following paragraph.
In addition, management has reviewed numerous cash flow producing properties for potential acquisition over the last several years in order to grow our production base and reduce our leverage ratio to a sustainable level and one that is in compliance with our financial covenants. In early 2018, we retained a financial advisor, separate from the Special Committee’s advisor, and began discussions with a potential seller and multiple financing counterparties for the purchase of a set of substantial cash flow producing properties. Despite a deteriorating commodity price market, discussions with both the seller and financing parties progressed throughout 2018. However, no definitive agreements ultimately were executed, and the negotiations currently are not active.
In March 2019, our board of directors expanded the scope of the Special Committee to explore, in addition to an Exchange Transaction, other financing alternatives and deleveraging transactions, including without limitation (i) amendments or waivers to the covenants or other provisions of our revolving credit facility, (ii) raising new capital in private or public markets and (iii) restructuring our balance sheet either in court or through an out of court agreement with creditors. We are also considering operational matters such as adjusting our capital budget and improving cash flows from operations by continuing to reduce costs, and intend to continue to pursue and consider other strategic alternatives, including: (i) acquiring assets with existing production and cash flows by issuing preferred and common equity to finance such acquisitions; (ii) selling existing producing or midstream assets; and (iii) merging with a strategic partner. The Special Committee has re-commenced discussions with the Wilks
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
regarding an Exchange Transaction and intends to continue those discussions as part of its review of financing alternatives and deleveraging transactions.
As of December 31, 2018, we have incurred approximately $1.5 million in costs related to the potential issuance of equity in the above alternatives, which are recorded in prepaid expenses and other current assets. There can be no assurance that we will be able to implement any of these plans successfully, or that such plans, if executed, will result in compliance with our credit facility covenants.
Cash and Cash Equivalents
We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. At times, the amount of cash and cash equivalents on deposit in financial institutions exceeds federally insured limits. We monitor the soundness of the financial institutions and believe the Company’s risk is negligible.
Oil and Gas Properties
Capitalized Costs. Our oil and gas properties comprised the following (in thousands):
We follow the successful efforts method of accounting for our oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties and to drill and equip development wells and related asset retirement costs are capitalized. Costs to drill exploratory wells are capitalized pending determination of whether the wells have proved reserves. If we determine that the wells do not have proved reserves, the costs are charged to exploration expense. There were no exploratory wells capitalized, pending determination of whether the wells have proved reserves, at December 31, 2018 or 2017. Geological and geophysical costs, including seismic studies are charged to exploration expense as incurred. We capitalize interest on expenditures for significant exploration and development projects that last more than six months while activities are in progress to bring the assets to their intended use and while these expenditures are excluded from our depletable base. Through December 31, 2018, we have capitalized no interest costs because our individual wells and infrastructure projects are generally developed in less than six months. Costs incurred to maintain wells and related equipment are charged to expense as incurred.
On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depreciation, depletion and amortization with no gain or loss recognized in income.
Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves using the unit conversion ratio of six Mcf of gas to one barrel of oil equivalent (“Boe”), and one barrel of NGLs to one Boe. The ratios of six Mcf of natural gas to one Boe and one barrel of NGLs to one Boe do not assume price equivalency and, given price differentials, the price for a Boe for natural gas may differ significantly from the price for a barrel of oil. Capitalized costs of proved mineral interests are depleted over
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
total estimated proved reserves, and capitalized costs of wells and related equipment and facilities are depleted over estimated proved developed reserves. Depreciation, depletion and amortization expense for oil and gas producing property and related equipment was $61.2 million, $70.3 million and $78.7 million for the years ended December 31, 2018, 2017 and 2016, respectively.
Capitalized costs related to proved oil and gas properties, including wells and related equipment and facilities, are periodically evaluated for impairment based on an analysis of undiscounted future net cash flows in accordance with ASC 360, Accounting for the Impairment or Disposal of Long-Lived Assets, as events or changes in circumstances indicate that the carrying values of those assets may not be recoverable. If undiscounted cash flows are insufficient to recover the net capitalized costs related to proved properties, then we recognize an impairment charge equal to the difference between the net capitalized costs related to proved properties and their estimated fair values based on the present value of the related future net cash flows. Estimating future net cash flows involves the use of judgments, including estimation of the proved and unproved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. We recorded no impairment of our proved properties for the years ended December 31, 2018, 2017 and 2016.
Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance.
On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained.
Other Property
Furniture, fixtures and equipment are carried at cost. Depreciation of furniture, fixtures and equipment is provided using the straight-line method over estimated useful lives ranging from three to 15 years. Gain or loss on retirement or sale or other disposition of assets is included in income in the period of disposition. Depreciation expense for other property and equipment was $262,000, $237,000 and $343,000 for the years ended December 31, 2018, 2017 and 2016, respectively.
Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value, as of December 31, 2018 and 2017. See Note 7 for fair value disclosures.
Income Taxes
We are subject to U.S. federal income taxes along with state income taxes in Texas. When tax returns are filed, it is highly certain that some positions taken would be sustained upon examination by the taxing authorities, while others are subject to uncertainty about the merits of the position taken or the amount of the position that would be ultimately sustained. The benefit of a tax position is recognized in the financial statements in the period during which, based on all available evidence, management believes it is more likely than not that the position will be sustained upon examination, including the resolution of appeals or litigation processes, if any. Tax positions taken are not offset or aggregated with other positions. Tax positions that meet the more-likely-than-not recognition threshold are measured as the largest amount of tax benefit that is more than 50% likely of being realized upon settlement with the applicable taxing authority. The portion of the benefits associated with tax positions taken that exceeds the amount measured as described above is reflected as a liability for unrecognized tax benefits in the accompanying balance sheet along with any associated interest and penalties that would be payable to the taxing authorities upon examination. Interest and penalties associated with unrecognized tax benefits are classified as additional income taxes on the consolidated statements of operations.
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Based on our analysis, we did not have any uncertain tax positions as of December 31, 2018 or 2017. The Company’s income tax returns are subject to examination by the relevant taxing authorities as follows: U.S. Federal income tax returns for tax years 2015 and forward and Texas income and margin tax returns for tax years 2015 and forward. There are currently no income tax examinations underway for these jurisdictions.
Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to the differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using the tax rate in effect for the year in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the year of the enacted tax rate change.
We monitor our deferred tax assets by jurisdiction to assess their potential realization, and a valuation allowance is recognized on deferred tax assets when we believe that certain of these assets are more likely than not to be realized. In performing this review, we make estimates and assumptions regarding projected future taxable income, the expected timing of reversals of existing temporary differences and the implementation of tax planning strategies. To the extent that a valuation allowance is established or changed during any period, we would recognize expense or benefit within our consolidated tax expense. We currently have a valuation allowance of $0.5 million on our deferred tax assets.
Derivative Activity
We enter commodity derivative contracts to reduce our exposure to fluctuations in commodity prices related to our oil, NGLs and gas production. We record our open derivative instruments at fair value on our consolidated balance sheets as either current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts, not designated as cash-flow hedges, and cash settlements are recorded in earnings as they occur on our consolidated statements of operations under the caption entitled “commodity derivative loss.”
In April 2018, we entered into swaps for the NYMEX Calendar Monthly Average Roll (the “CMA Roll”) covering 2,000 Bbls of oil per day for May 2018 through December 2018 at $0.66/bbl. Swaps for the CMA Roll are pricing adjustments to the trade month versus the delivery month for contract pricing. These derivative contracts were designated as cash-flow hedges. The changes in fair value of the derivative contracts designated as cash-flow hedges, to the extent the hedge is effective, will be recognized in other comprehensive income until the hedged item is recognized in revenue. As of December 31, 2018, we had no outstanding derivative instruments designated as cash-flow hedges.
Prepaid Expenses and Other Assets
In April 2017, we entered into an agreement that secured pricing and availability of a dedicated hydraulic fracturing services crew. Under this agreement, we made a prepayment of $5 million, to be used as we completed wells. We have used $1.2 million of this prepayment related to hydraulic fracturing services provided during the first year of the agreement. In March 2018, this agreement was terminated and $3.8 million of the unused prepaid balance was refunded to us.
Asset Retirement Obligations
Our asset retirement obligations relate to future plugging and abandonment expenses on oil and gas properties. Based on the expected timing of payments, the full asset retirement obligation is classified as non-current. There were no significant changes to the asset retirement obligations for the years ended December 31, 2018, 2017 and 2016.
Share-Based Compensation
We measure and record compensation expense for share-based payment awards to employees and outside directors based on estimated grant date fair values. We recognize compensation costs for awards granted over the
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requisite service period based on the grant date fair value in general and administrative expenses on our consolidated statements of operations. Additionally, we recognize forfeitures of share-based compensation as they occur.
In 2018 and 2016, we awarded cash-settled performance awards, subject to certain performance conditions, to our executive officers. The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations.
Earnings Per Common Share
We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. The following are reconciliations of the numerators and denominators of our basic and diluted earnings per share (dollars in thousands, except per-share amounts):
(1)
Approximately 39,000 options to purchase our common stock were excluded from this calculation because they were antidilutive for the year ended December 31, 2016. No options were outstanding for the years ended December 31, 2018 and 2017, as they had expired.
Oil and Gas Operations
Revenue and Accounts Receivable. Revenues from the sale of oil, NGLs, and gas are recognized as the product is delivered to our customers’ custody transfer points and collectability is reasonably assured. We fulfill the performance obligations under our customer contracts through daily delivery of oil, NGLs and gas to our customers’ custody transfer points and revenues are recorded on a monthly basis. The prices received for oil, NGLs and natural gas sales under our contracts are generally derived from stated market prices which are then adjusted to reflect deductions including transportation, fractionation and processing. As a result, our revenues from the sale of oil, natural gas and NGLs will decrease if market prices decline. The sales of oil, NGLs and gas as presented on the Consolidated Statements of Operations represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil, NGLs and gas 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 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 following table presents our disaggregated revenue by major source for the years ended December 31, 2018, 2017 and 2016 (in thousands)
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Accounts receivable, joint interest owners, consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date. Accounts receivable, oil, NGLs and gas sales, consist of uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production. No interest is charged on past-due balances. Payments made on all accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No such allowance was considered necessary at December 31, 2018 or 2017.
Oil, NGLs and Gas Sales Payable. Oil, NGLs and gas sales payable represents amounts collected from purchasers for oil, NGLs and gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 60 days of the end of the month in which the related production occurred.
Production Costs. Production costs, including compressor rental and repair, pumpers’ and supervisors’ salaries, saltwater disposal, insurance, repairs and maintenance, expensed workovers and other operating expenses are expensed as incurred and included in lease operating expenses on our consolidated statements of operations.
Exploration expenses. Exploration expenses include lease expirations, delay rentals, geological and geophysical costs and dry hole costs. In 2018, we incurred exploration expense of $0.4 million to drill an exploratory monitor well used for gathering geological, geophysical or engineering data concerning one or more potentially productive formations in other wells.
Dependence on Major Customers. For the year ended December 31, 2018, sales to American Midstream, LP (“AMID”), a successor to JP Energy Development, LP (“JP Energy”), and DCP Midstream, LP (“DCP”) accounted for approximately 56% and 41%, respectively, of our total sales. As of December 31, 2018, we had dedicated the majority of our oil production from Project Pangea through September 2022 to AMID. In addition, as of December 31, 2018, we had contracted to sell the majority of our NGLs and natural gas production from Project Pangea to DCP through August 2023. For the year ended December 31, 2017, sales to AMID and DCP accounted for approximately 52% and 47%, respectively, of our total sales. For the year ended December 31, 2016, sales to DCP and JP Energy accounted for approximately 46% and 54%, respectively of our total sales. We believe that there are potential alternative purchasers and that it may be necessary to establish relationships with new purchasers. However, there can be no assurance that we can establish such relationships and that those relationships will result in increased purchasers. Although we are exposed to a concentration of credit risk, we believe that all of our purchasers are credit worthy.
Segment Reporting
The Company presently operates in one business segment, the exploration and production of oil, NGLs and natural gas.
Recent Accounting Pronouncements
On January 1, 2018, we adopted the Financial Accounting Standards Board (“FASB”) accounting standards update for “Revenue from Contracts with Customers,” which superseded the revenue recognition requirements in “Topic 605, Revenue Recognition,” using the modified retrospective method. Adoption of this standard did not have
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a significant impact on our consolidated statements of operations or cash flows. We implemented processes to ensure new contracts are reviewed for the appropriate accounting treatment and generate the disclosures required under the new standard. Additional disclosures required under this accounting standards update related to the nature, amount, timing and uncertainty of revenue and cash flows from contracts with customers, including disaggregation of revenue, were included above.
In February 2016, FASB issued an accounting standards update for “Leases,” which amends existing guidance to require lessees to recognize liabilities and right-of-use (“ROU”) assets on the balance sheet for the rights and obligations created by long-term leases and to disclose additional quantitative and qualitative information about leasing arrangements. This new guidance is effective for interim and annual periods beginning after December 15, 2018, and we adopted it using a modified retrospective approach on January 1, 2019 using the transition method that allows a cumulative-effect adjustment to the opening balance to retained earnings in the period of adoption.
We currently enter into lease agreements to support our operations. These agreements are for leases on assets such as office space, compressors and well equipment. We have substantially completed our process to implement this standard, and we have designed processes and internal controls necessary for adoption of this standard. We have made policy elections to (i) not capitalize short-term leases for all asset classes, (ii) to not separate non-lease components from lease components for all of our current asset classes, (iii) apply the package of practical expedients that allows us to not reassess: whether any expired or existing contracts contain leases, lease classification for any expired or existing leases and initial direct costs for existing leases, (iv) apply the land easement practical expedient to not evaluate land easements that existed or expired prior to adoption and (v) apply the practical expedient to apply hindsight in estimating lease term and impairment.
The impact of applying this standard is not expected to significantly impact our results of operations or cash flows. As of January 1, 2019, we expect to recognize ROU assets and liabilities of approximately $15 million from operating leases on our consolidated balance sheet. We expect an increase in our working capital deficit due to the adoption of this standard as the entire ROU asset balance will be presented as a non-current asset, and a portion of the lease liability will be presented as a current liability. Under the terms of our revolving credit facility, the current liability related to operating leases will not be considered in our modified current ratio financial covenant calculation.
In March 2016, FASB issued an accounting standards update for “Compensation - Stock Compensation,” which amends existing guidance related to the accounting for forfeitures, employer tax withholding on share-based compensation and financial statement presentation of excess tax benefits or deficiencies. This standard is effective for interim and annual reporting periods beginning after December 15, 2016, with early adoption permitted. We applied this standard using a modified retrospective approach. We have elected to (i) recognize forfeitures of share-based compensation as they occur, (ii) permit tax withholdings in excess of the minimum statutory requirements and (iii) recognize previously un-recognized excess tax benefits related to share-based compensation in the current year. As a result, we have recognized an increase in accumulated earnings in 2016 of $1.7 million related to the change in accounting principal as of January 1, 2016. Adoption of this guidance did not impact our consolidated statements of operations or cash flows.
In January 2017, FASB issued an accounting standards update for “Clarifying the Definition of a Business,” which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This standard requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. This standard is effective for interim and annual reporting periods beginning after December 15, 2016. The Company is evaluating the impact of this new guidance on its consolidated financial statements.
In August 2017, FASB issued an accounting standards update for “Derivatives and Hedging,” which amends existing guidance related to the recognition and presentation requirements of hedge accounting, including eliminating the requirement to separately measure and report hedge ineffectiveness, and presenting all items that affect earnings in the same income statement line item as the hedged item. This standard is effective for interim and annual reporting periods beginning after December 15, 2018, with early adoption permitted. We have elected to early adopt this standard in the first quarter of 2018. Adoption of this standard did not impact our consolidated statements of operations or cash flows. Although we have not historically designated our derivative contracts as
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cash-flow hedges, we designated CMA Roll swap derivative contracts entered in April 2018 as cash-flow hedges. See Note 6 for additional information related to the derivative contracts designated as cash-flow hedges.
2.
Equity Exchange Transactions
Debt exchange
On November 2, 2016, we entered into an exchange agreement with Wilks Brothers, LLC and SDW Investments, LLC (collectively, “Wilks”), the largest holder of our 7% Senior Notes due 2021 (the “Senior Notes”), to exchange $130,552,000 principal amount of our Senior Notes for 39,165,600 newly issued shares of common stock, par value $0.01 per share (the “Initial Exchange”). On January 26, 2017, our stockholders approved the 2017 Exchange Transactions (defined below) and an increase in our authorized common stock from 90 million shares to 180 million shares. We closed the Initial Exchange on January 27, 2017, and paid $1.1 million of accrued interest on the Senior Notes held by Wilks. In connection with the Initial Exchange, a second supplemental indenture became effective, which removed certain covenants and events of default from the indenture governing our Senior Notes and eliminated certain restrictive covenants discussed in Note 3.
On March 22, 2017, we exchanged an additional $14,528,000 principal amount of outstanding Senior Notes for 4,009,728 shares of our common stock (the “Follow-On Exchange”).
The Initial Exchange and the Follow-On Exchange (together, the “2017 Exchange Transactions”) reduced the principal amount of outstanding Senior Notes by $145.1 million and reduced interest payments by $44.3 million over the remaining term of the Senior Notes. The 2017 Exchange Transactions were accounted for as a debt extinguishment. A gain of $5.1 million was recognized on the 2017 Exchange Transactions for the difference between the fair market value of the shares issued, a Level 1 fair value measurement, and the net carrying value of the Senior Notes exchanged. We incurred equity issuance costs of $2.8 million related to the 2017 Exchange Transactions, which were recorded as a reduction to additional paid-in capital.
The 2017 Exchange Transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the usage of our pre-change net operating losses (“NOLs”) in the future. Accordingly, we reduced our NOL deferred tax assets by $139.1 million.
Acquisition
On November 1, 2017, we entered into a definitive agreement to acquire producing properties directly adjacent to our acreage in the Permian Basin (the “Bolt-On Acquisition”). The Bolt-On Acquisition closed on November 20, 2017, and we issued 7,573,403 newly issued shares of common stock, par value $0.01 per share, with an effective date of September 1, 2017. The purchase price is subject to customary post-closing adjustments. The purchase price was finalized in April 2018, and we received 142,362 of the previously issued shares of our common stock, which were retired, pursuant to adjustments under the Purchase Agreement. The Bolt-On Acquisition was accounted for using the acquisition method under ASC Topic 805, “Business Combinations,” which requires the acquired assets and liabilities to be recorded at fair values as of the acquisition date. In connection with the Bolt-On Acquisition, we incurred $0.1 million of acquisition-related costs which were expensed as incurred and are included in general and administrative expenses on our consolidated statements of operations.
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The following table summarizes the final estimated fair value of the assets acquired and liabilities assumed as a result of the Bolt-On Acquisition (in thousands):
We estimated the fair value of oil and gas properties and equipment and asset retirement obligations as of November 20, 2017, using a discounted cash flow model, which is a non-recurring Level 3 fair value measurement. Significant inputs to the valuation of natural gas and oil properties include estimates of: (i) future sales prices for oil and gas based on NYMEX strip prices, (ii) pricing adjustments for differentials, (iii) production costs, (iv) future oil and gas reserves to be recovered and the timing thereof, and (v) discount rates.
3.
Long-Term Debt
The following table provides a summary of our long-term debt at December 31, 2018, and December 31, 2017 (in thousands).
Senior Secured Credit Facility
At December 31, 2018, the borrowing base and aggregate lender commitments under our amended and restated senior secured credit facility (the “Credit Facility”) were $325 million, with maximum commitments from the lenders of $1 billion. The Credit Facility has a maturity date of May 7, 2020. The borrowing base is redetermined semi-annually based on our oil, NGLs and gas reserves. We, or the lenders, can each request one additional borrowing base redetermination each calendar year.
Borrowings under the Credit Facility bear interest based on the agent bank’s prime rate plus an applicable margin ranging from 2% to 3%, or the sum of the LIBOR rate plus an applicable margin ranging from 3% to 4%. In addition, we pay an annual commitment fee of 0.50% of unused borrowings available under the Credit Facility. Margins vary based on the borrowings outstanding compared to the borrowing base of the lenders.
We had $301.5 million of outstanding borrowings under the Credit Facility at December 31, 2018, compared to $291 million of outstanding borrowings under the Credit Facility at December 31, 2017. The weighted average interest rate applicable to borrowings under the Credit Facility in 2018 was 6%. We had outstanding unused letters
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of credit under our Credit Facility totaling $0.3 million at December 31, 2018 and 2017, which reduce amounts available for borrowing under the Credit Facility.
Obligations under the Credit Facility are secured by mortgages on substantially all of the oil and gas properties of the Company and its subsidiaries. The Company is required to grant liens in favor of the lenders covering the oil and gas properties of the Company and its subsidiaries representing at least 95% of the total value of all oil and gas properties of the Company and its subsidiaries.
On December 21, 2017, we entered into a fourth amendment to the Credit Facility. The fourth amendment, among other things, (a) extended the maturity date of the Credit Facility from May 7, 2019, to May 7, 2020, (b) increased the applicable margin rates on borrowings by 50 basis points, and (c) required the Company to hedge 50% of the Company’s estimated 2018 oil and gas production from proved developed producing reserves. In connection with the fourth amendment to the Credit Facility we incurred $1 million of debt issuance costs.
On May 3, 2016, we entered into a third amendment to the Credit Facility. The third amendment, among other things, (a) decreased the borrowing base to $325 million from $450 million, (b) increased the applicable margin rates on borrowings by 100 basis points, (c) permits the Company to issue up to $150 million of second lien indebtedness, subject to various conditions and limitations, (d) permits the Company to repurchase outstanding debt with proceeds of certain asset sales, equity issuances or second lien indebtedness, and (e) requires cash and cash equivalents in excess of $35 million held by the Company to be applied to reduce outstanding borrowings under the Credit Facility. In connection with the third amendment to the Credit Facility, $0.6 million of debt issuance costs were written off as a result of the reduction in the borrowing base, and we incurred $0.2 million of debt issuance costs.
Covenants
The Credit Facility contains three principal financial covenants:
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a consolidated interest coverage ratio covenant that requires us to maintain a ratio of (i) consolidated EBITDAX for the period of four fiscal quarters then ending to (ii) Cash Interest Expense for such period as of the last day of any fiscal quarter of not less than 1.75 to 1.0 through December 31, 2018, a ratio of not less than 2.25 to 1.0 through December 31, 2019, and 2.5 to 1.0 thereafter. EBITDAX is defined as consolidated net (loss) income plus (i) interest expense, net, (ii) income tax provision (benefit), (iii) depreciation, depletion, amortization, (iv) exploration expenses and (v) other noncash loss or expense (including share-based compensation and the change in fair value of any commodity derivatives), less noncash income. Cash Interest Expense is calculated as interest expense, net less amortization of debt issuance costs. At December 31, 2018, our consolidated interest coverage ratio was 2.5 to 1.0;
•
a consolidated modified current ratio covenant that requires us to maintain a ratio of not less than 1.0 to 1.0 as of the last day of any fiscal quarter. The consolidated modified current ratio is defined as the ratio of (i) current assets plus funds available under our revolving credit facility, less the current derivative asset, to (ii) current liabilities less the current derivative liability. At December 31, 2018, our consolidated modified current ratio was 1.6 to 1.0; and
•
a consolidated total leverage ratio covenant that imposes a maximum permitted ratio of (i) Total Debt to (ii) EBITDAX for the period of four fiscal quarters then ending of not more than 5.0 to 1.0, as of the last day of any fiscal quarter from March 31, 2019, through June 30, 2019, thereafter not more than 4.75 to 1.0 as of the last day of any fiscal quarter through December 31, 2019, and (iii) not more than 4.0 to 1.0 as of the last day of any fiscal quarter thereafter. Total Debt is defined as the face or principal amount of debt. Our leverage ratio is currently above the level that will be required as of March 31, 2019. At December 31, 2018, our leverage ratio was 6.6 to 1.0.
Failure to comply with any of the financial covenants under the Credit Facility would represent an event of default. In the case of an event of default, the lenders (i) would not be required to lend any additional amounts to us, (ii) could elect to declare all outstanding borrowings, together with accrued and unpaid interest and fees to be due
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and payable, (iii) could require us to apply all of our available cash to repay these borrowings and (iv) could prevent us from making debt service payments under our other agreements.
The Credit Facility also contains covenants restricting cash distributions and other restricted payments, transactions with affiliates, incurrence of other debt, consolidations and mergers, the level of operating leases, asset sales, investment in other entities and liens on properties.
In addition, the obligations of the Company may be accelerated upon the occurrence of an Event of Default (as defined in the Credit Facility). Events of Default include customary events for a financing agreement of this type, including, without limitation, payment defaults, the inaccuracy of representations and warranties, defaults in the performance of affirmative or negative covenants, defaults on other indebtedness of the Company or its subsidiaries, bankruptcy or related defaults, defaults related to judgments and the occurrence of a Change of Control (as defined in the Credit Facility), which includes instances where a third party becomes the beneficial owner of more than 50% of the Company’s outstanding equity interests entitled to vote.
Senior Notes
At December 31, 2018, and 2017, $85.2 million principal amount of 7% Senior Notes due 2021 (the “Senior Notes”) was outstanding. Annual interest on the Senior Notes is payable semi-annually on June 15 and December 15. On December 15, 2018, we made a semi-annual interest payment of $3 million.
During the year ended December 31, 2017, we completed the 2017 Exchange Transactions which reduced the outstanding principal balance of our Senior Notes by $145.1 million and reduced future interest payments by $44.3 million over the remaining term of the Senior Notes.
We issued the Senior Notes under a senior indenture dated June 11, 2013, among the Company, our subsidiary guarantors and Wilmington Trust, National Association, as successor trustee. The senior indenture, as supplemented by a supplemental indenture dated June 11, 2013, is referred to as the “Indenture.”
On December 20, 2016, we entered into the second supplemental indenture (the “Second Supplemental Indenture”), which became effective on January 27, 2017, in connection with the closing of the Initial Exchange. The Second Supplemental Indenture (i) eliminated certain definitions and references to definitions contained in the Indenture, (ii) eliminated and revised, as applicable, certain events of default contained in the Indenture, (iii) eliminated certain conditions to consolidation, merger, conveyance, transfer or lease contained in the Indenture, (iv) eliminated certain covenants contained in the Indenture, including substantially all of the restrictive covenants set forth therein, and (v) supplemented and amended the Senior Notes and the securities guarantees, as and to the same extent as the Indenture has been amended and supplemented in accordance with the preceding clauses (i), (ii), (iii) and (iv).
We may redeem some or all of the Senior Notes at specified redemption prices, plus accrued and unpaid interest to the redemption date. The Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our subsidiaries, subject to certain customary release provisions. A subsidiary guarantor may be released from its obligations under the guarantee:
•
in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way of merger or consolidation) to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if the sale or other disposition otherwise complies with the Indenture;
•
in connection with any sale or other disposition of the capital stock of that guarantor to a person that is not (either before or after giving effect to such transaction) the Company or a subsidiary guarantor, if that guarantor no longer qualifies as a subsidiary of the Company as a result of such disposition and the sale or other disposition otherwise complies with the Indenture;
•
if the Company designates any restricted subsidiary that is a guarantor to be an unrestricted subsidiary in accordance with the Indenture;
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•
upon defeasance or covenant defeasance of the notes or satisfaction and discharge of the Indenture, in each case, in accordance with the Indenture;
•
upon the liquidation or dissolution of that guarantor, provided that no default or event of default occurs under the Indenture as a result thereof or shall have occurred and is continuing; or
•
in the case of any restricted subsidiary that, after the issue date of the notes is required under the Indenture to guarantee the notes because it becomes a guarantor of indebtedness issued or an obligor under the revolving credit facility with respect to the Company and/or its subsidiaries, upon the release or discharge in full from its (i) guarantee of such indebtedness or (ii) obligation under such revolving credit facility, in each case, which resulted in such restricted subsidiary’s obligation to guarantee the notes.
As a result of the Second Supplemental Indenture, the Indenture contains limited events of default.
Subsidiary Guarantors
The Senior Notes are guaranteed on a senior unsecured basis by each of our consolidated subsidiaries. Approach Resources Inc. is a holding company with no independent assets or operations. The subsidiary guarantees are full and unconditional and joint and several, and any subsidiaries of the Company other than the subsidiary guarantors are minor. There are no significant restrictions on the Company’s ability, or the ability of any subsidiary guarantor, to obtain funds from its subsidiaries through dividends, loans, advances or otherwise.
At December 31, 2018, we were in compliance with all of our covenants, and there were no existing defaults or events of default, under our debt instruments.
4.
Share-Based Compensation
In June 2018, our board of directors and stockholders approved the Long Term Incentive Plan (the “2018 Plan”). Under the 2018 Plan, we may grant restricted stock, stock options, stock appreciation rights, restricted stock units, performance awards, unrestricted stock awards and other incentive awards. The maximum number of shares of common stock available for the grant of awards under the 2018 Plan is 6,950,000. Awards of any stock options are to be priced at not less than the fair market value at the date of the grant. We use (i) the closing stock price on the date of grant for the fair value of restricted stock awards, including performance-based awards, (ii) the Monte Carlo simulation method for the fair value of market-based awards, (iii) the fair market value of our common stock on the valuation date for cash-settled performance awards and (iv) the Black-Scholes option price model to measure the fair value of stock options. The vesting period of any stock award is to be determined by the board or an authorized committee at the time of the grant.
Share-based compensation expense amounted to $3 million, $4.7 million and $6.3 million for the years ended December 31, 2018, 2017 and 2016, respectively. Such amounts represent the estimated fair value of stock awards for which the requisite service period elapsed during those periods. Share-based compensation expense for the years ended December 31, 2018, 2017 and 2016, included $384,000, $449,000 and $214,000, respectively, related to grants to non-employee directors.
Stock Options
There were no stock option grants during the years ended December 31, 2018, 2017 and 2016. During the year ended December 31, 2017, 38,525 options expired, and no options were outstanding as of December 31, 2018, and 2017. There were no options exercised during the years ended December 31, 2018, 2017 and 2016.
Nonvested Shares
Share grants totaling 1,348,488 shares, 2,343,522 shares and 1,318,229 shares with an approximate aggregate fair market value of $2.6 million, $5.6 million and $2.5 million, based on the closing price of our common stock on the date of grant, were granted to employees and non-employee directors during the years ended December 31,
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2018, 2017 and 2016, respectively. Included in the share grants for 2018, 2017 and 2016, are 387,295 shares, 1,492,652 shares and 550,272 shares, respectively, awarded to our executive officers. The aggregate fair market value of these shares on the grant date was $0.8 million, $3.6 million and $0.3 million, respectively, to be expensed over a service period of approximately three years, subject to certain performance restrictions. The share grants for executive officers noted above does not include the cash-settled performance awards, which are discussed in more detail below.
A summary of the status of nonvested shares for the years ended December 31, 2018, 2017 and 2016, is presented below:
As of December 31, 2018, unrecognized compensation expense related to the nonvested shares amounted to $3.1 million, which will be recognized over a remaining service period of two years.
Cash-settled performance awards
In 2018 and 2016, in addition to the share grants discussed above, we awarded cash-settled performance awards, subject to certain performance conditions, of 774,590 and 1,100,542 to our executive officers, respectively. The fair market value of these cash-settled performance awards on the grant date was $2.4 million and $1 million, respectively. During the years ended December 31, 2018, and 2017, 625,045 and 366,847 cash-settled performance awards vested. As of December 31, 2018, we had 883,240 unvested cash-settled performance awards, subject to certain performance conditions outstanding. As of December 31, 2018, the aggregate fair market value of the outstanding cash-settled performance awards was approximately $1 million, to be expensed over a remaining service period of approximately 1.3 years, subject to performance conditions.
The cash-settled performance awards represent a non-equity unit with a conversion value equal to the fair market value of a share of the Company’s common stock at the vesting date. These awards are classified as liability awards due to the cash settlement feature. Compensation costs associated with the cash-settled performance awards are re-measured, based on the fair market value of our common stock of the vested portion of the award, at each interim reporting period and an adjustment is recorded in general and administrative expenses on our consolidated statements of operations. For the years ended December 31, 2018, 2017 and 2016, we recognized $0.2 million, $0.8 million and $1.3 million in expense related to the cash-settled performance awards, respectively. As of December 31, 2018, we recorded a current liability of $1.2 million and a non-current liability of $0.1 million on our consolidated balance sheet related to these awards. During the year ended December 31, 2018, we paid $1 million related to vested cash-settled performance awards.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Employee Benefit Plan
The Company has a defined contribution employee benefit plan covering substantially all of its employees. We make a matching contribution equal to 100% of each pre-tax dollar contributed by the participant on the first 3% of eligible compensation and 50% on the next 2% of eligible compensation. The Company made contributions to the plan of approximately $335,000, $333,000 and $338,000 during the years ended December 31, 2018, 2017 and 2016, respectively.
5.
Income Taxes
Our provision for income taxes comprised the following (in thousands):
Total income tax expense differed from the amounts computed by applying the U.S. Federal statutory tax rates to pre-tax income (in thousands):
The 2017 Exchange Transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the future use of our pre-change net operating losses (“NOLs”). Accordingly, we reduced our NOL deferred tax assets by $139.1 million.
On December 22, 2017, the Tax Cuts and Jobs Act was enacted which, among other things, lowered the U.S. Federal income tax rate applicable to corporations from 35% to 21% and repealed the corporate alternative minimum tax. We recorded a net tax benefit of $51.9 million to reflect the impact of the Tax Cuts and Jobs Act as of December 31, 2017, as it is required to reflect the change in the period in which the law is enacted.
In 2018, 2017 and 2016, the Company recorded a tax shortfall related to share-based compensation of $0.3 million, $1.3 million and $1.8 million, respectively. This shortfall is for grants in which the realized tax deduction was less than the expense booked for these grants due to a decline in share price from the time of grant.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
In 2016, we early adopted accounting standards update for “Compensation - Stock Compensation.” As a result, we recognized an increase in accumulated earnings and our NOLs in 2016 of $1.7 million related to the change in accounting principal as of January 1, 2016.
Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and tax basis of assets and liabilities. Our net deferred tax assets and liabilities are recorded as a long-term liability of $77.8 million and $82.1 million at December 31, 2018 and 2017, respectively.
Significant components of net deferred tax assets and liabilities are (in thousands):
The 2017 Exchange Transactions triggered a cumulative change in ownership of our common stock by more than 50% under Section 382 of the Internal Revenue Code as of March 22, 2017. This established an annual limitation on the future use of our pre-change NOLs. Accordingly, we reduced our NOL deferred tax assets by $139.1 million in the year ended December 31, 2017. At December 31, 2018, we had federal NOLs of $191.2 million, after the reduction under Section 382 limitation, that expire between 2030 and 2037, and federal NOLs of $89.3 million that do not expire. As of December 31, 2018, we have a valuation allowance of $0.5 million on our deferred tax assets.
6.
Derivative Instruments and Fair Value Measurements
At December 31, 2018, we had the following commodity derivatives positions outstanding:
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following summarizes the fair value of our open commodity derivatives as of December 31, 2018 and 2017 (in thousands):
The following summarizes the cash settlements and change in the fair value of our commodity derivatives (in thousands):
The following table summarizes the changes in accumulated other comprehensive income (“AOCI”) for the year ended December 31, 2018 (in thousands).
Derivative assets and liabilities, at fair value, are included on our consolidated balance sheets as current or non-current assets or liabilities based on the anticipated timing of cash settlements under the related contracts. Changes in the fair value of our commodity derivative contracts, not designated as cash-flow hedges, and cash settlements are recorded in earnings as they occur on our consolidated statements of operations under the caption entitled “commodity derivative loss”.
In April 2018, we entered into swaps for the NYMEX Calendar Monthly Average Roll (the “CMA Roll”) covering 2,000 Bbls of oil per day for May 2018 through December 2018 at $0.66/bbl. Swaps for the CMA Roll are pricing adjustments to the trade month versus the delivery month for contract pricing. These derivative contracts were designated as cash-flow hedges. The changes in fair value of the derivative contracts designated as cash-flow hedges, to the extent the hedge is effective, will be recognized in other comprehensive income until the hedged item is recognized in revenue. As of December 31, 2018, we had no outstanding derivative instruments designated as cash-flow hedges.
We estimate the fair value of swap contracts based on the present value of the difference in exchange-quoted forward price curves and contractual settlement prices multiplied by notional quantities. We internally valued the option contracts using industry-standard option pricing models and observable market inputs. We use our internal valuations to determine the fair values of the contracts that are reflected on our consolidated balance sheets.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
We are exposed to credit losses in the event of nonperformance by the counterparties on our commodity derivatives positions and have considered the exposure in our internal valuations. However, we do not anticipate nonperformance by the counterparties over the term of the commodity derivatives positions.
To estimate the fair value of our commodity derivatives positions, we use 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. We primarily apply the market approach for recurring fair value measurements and attempt to use the best available information. We determine the fair value based upon the 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 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:
•
Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. At December 31, 2018, we had no Level 1 measurements.
•
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which 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. Our derivatives, which consist primarily of commodity swaps and collars, are valued using commodity market data which is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2. At December 31, 2018, all of our commodity derivatives were valued using Level 2 measurements.
•
Level 3 - Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. The fair value of oil and gas properties acquired in the Bolt-on Acquisition represents a Level 3 measurement. At December 31, 2018, we had no recurring Level 3 measurements.
Financial Instruments Not Recorded at Fair Value
The following table sets forth the fair values of financial instruments that are not recorded at fair value on our financial statements (in thousands).
The fair value of the Senior Notes is based on quoted market prices, but the Senior Notes are not actively traded in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy.
7.
Commitments and Contingencies
At December 31, 2018, we had outstanding employment agreements with all four of our executive officers that contained automatic renewal provisions providing that such agreements may be automatically renewed for successive terms of one year unless the employment is terminated at the end of the term by written notice given to the employee not less than 60 days prior to the end of such term. Our maximum commitment under the employment agreements, which would apply if the employees covered by these agreements were each terminated without cause, resigned for good reason, or received a notice of non-renewal was approximately $6.5 million at December 31, 2018. This estimate assumes the maximum potential bonus for 2018 is earned by each executive officer during 2018.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
In 2016, we recorded a contractual settlement of $1.4 million, which is recorded in other income on our consolidated statements of operations.
We lease our office space in Fort Worth, Texas, under a non-cancelable agreement that expires on September 30, 2021. We also have non-cancelable operating lease commitments related to office equipment that expire by 2022. The following is a schedule by years of future minimum rental payments required under our operating lease arrangements as of December 31, 2018 (in thousands):
Rent expense under our lease arrangements amounted to $942,000, $748,000 and $1,025,000 for the years ended December 31, 2018, 2017 and 2016, respectively.
Litigation
We are involved in various legal and regulatory proceedings arising in the normal course of business. While we cannot predict the outcome of these proceedings with certainty, we do not believe that an adverse result in any pending legal or regulatory proceeding, individually or in the aggregate, would be material to our consolidated financial condition or cash flows.
In 2016, we received $1.1 million from a service provider in a legal settlement, which reduced our current liabilities on our consolidated balance sheets and is recorded as a reduction in additions to oil and gas properties on our consolidated statements of cash flows.
Environmental Issues
We are engaged in oil and gas exploration and production and may become subject to certain liabilities or damages as they relate to environmental clean up of well sites or other environmental restoration or ground water contamination, in connection with drilling or operating oil and gas wells. In connection with our acquisition of existing or previously drilled well bores, we may not be aware of what environmental safeguards were taken at the time such wells were drilled or during such time the wells were operated. Should it be determined that a liability exists with respect to any environmental clean up, restoration or contamination, we would be responsible for curing such a violation or paying damages. No claim has been made, nor are we aware of any liability that exists, as it relates to any environmental clean up, restoration, contamination or the violation of any rules or regulations relating thereto.
8.
Related Party Transactions
Wilks, a related party, purchased a portion of our outstanding Senior Notes in the open market subsequent to the Exchange Transactions. The Company believes that Wilks held approximately $60 million aggregate principal amount of our outstanding Senior Notes as of December 31, 2018. The Senior Notes held by Wilks are included in Senior Notes, net on our consolidated balance sheets. Our interest expense includes interest attributable to any Senior Notes held by Wilks on our consolidated statements of operations. As of December 31, 2018, we recorded a current liability $0.1 million of accrued interest attributable to the Senior Notes held by Wilks. On April 12, 2018, Wilks disclosed on Schedule 13D/A that they intend to engage in discussions with the Company regarding their investment in the Company, including the possible acquisition of additional shares of common stock through the exchange of the Senior Notes currently held by Wilks. In connection with these discussions the Company has incurred $0.1 million of legal fees on behalf of Wilks.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
In April 2018, we engaged ProFrac Services, LLC (“ProFrac”) to perform completion services for the Company. There is no required minimum or maximum number of wells committed, and we may use ProFrac on a well-by-well basis throughout 2019. Matthew D. Wilks, a member of our Board of Directors, serves as the Chief Financial Officer of ProFrac, and Wilks has an equity ownership interest in ProFrac. During the year ended December 31, 2018, we incurred capital expenditures of $8.1 million for hydraulic fracturing services with ProFrac, which is included in additions to oil and gas properties on our consolidated statements of cash flows. As of December 31, 2018, there is no recorded liability due to ProFrac.
9.
Oil and Gas Producing Activities
Set forth below is certain information regarding the costs incurred for oil and gas property acquisition, development and exploration activities (in thousands):
(1)
For the year ended December 31, 2017, acquisition costs of proved properties included the fair value of assets acquired in the Bolt-On Acquisition. See Note 2 for additional disclosures related to the Bolt-On Acquisition.
(2)
For the years ended December 31, 2018, 2017 and 2016, development costs included $19,000, $39,000 and $36,000, respectively, in non-cash asset retirement obligations.
Set forth below is certain information regarding the results of operations for oil and gas producing activities (in thousands):
10.
Disclosures About Oil and Gas Producing Activities (unaudited)
Proved Reserves
All of our estimated oil and natural gas reserves are attributable to properties within the United States, primarily in the Permian Basin in West Texas. The estimates of proved reserves and related valuations for the years ended December 31, 2018, 2017 and 2016, were prepared by DeGolyer and MacNaughton, independent petroleum engineers. Each year’s estimate of proved reserves and related valuations were also prepared in accordance with then-current rules and guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following table summarizes the prices used in the reserve estimates for 2018, 2017 and 2016. Commodity prices used for the reserve estimates, adjusted for basis differentials, grade and quality, are as follows:
Oil, NGLs and natural gas reserve estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
The following table provides a summary of the changes of the total proved reserves for the years ended December 31, 2018, 2017 and 2016, as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year.
(1)
Production included 1,330 MMcf, 1,319 MMcf and 1,385 MMcf related to field fuel in 2016, 2017 and 2018, respectively.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
The following is a discussion of the material changes in our proved reserve quantities for the years ended December 31, 2018, 2017 and 2016:
Year Ended December 31, 2018
Extensions and discoveries for 2018 were 35 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2018, we reclassified 33.1 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 0.2 MMBoe resulting from updated well performance and technical parameters, and an increase of 1.9 MMBoe due to higher commodity prices, partially offset by a decrease of 1.4 MMBoe due to an increase in operating expenses and natural gas price differentials. We produced 4.3 MMBoe during 2018. This production included 1,385 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.
Year Ended December 31, 2017
Extensions and discoveries for 2017 were 33.3 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2017, we acquired 1.6 MMBoe of proved reserves through the Bolt-On Acquisition, and we reclassified 17.7 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 9.4 MMBoe resulting from updated well performance and technical parameters and an increase of 3.1 MMBoe due to higher commodity prices We produced 4.5 MMBoe during 2017. This production included 1,319 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.
Year Ended December 31, 2016
Extensions and discoveries for 2016 were 16.7 MMBoe, primarily attributable to our development project in the Wolfcamp shale oil resource play in the Permian Basin. During 2016, we reclassified 22.4 MMBoe of proved undeveloped reserves to unproved reserves. The reserves reclassified are attributable to horizontal well locations in Project Pangea that are no longer expected to be developed within five years from their initial booking, as required by SEC rules. Revisions included an increase of 2.1 MMBoe resulting from cost reductions, updated well performance and technical parameters, offset by a decrease of 1.9 MMBoe due to lower commodity prices. We produced 4.8 MMBoe during 2016. This production included 1,330 MMcf of gas that was produced and used as field fuel (primarily for compressors and artificial lift) before the gas was delivered to a sales point.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves
The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first-day-of-the-month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rates to the difference.
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and natural gas properties. Estimates of fair value would also consider probable and possible reserves, anticipated future oil and natural gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
The following table provides the standardized measure of discounted future net cash flows at December 31, 2018, 2017 and 2016 (in thousands):
Future cash flows as shown above were reported without consideration for the effects of commodity derivative transactions outstanding at each period end.
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)
Changes in Standardized Measure of Discounted Future Net Cash Flows
The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows (in thousands):
11.
Supplementary Data
Selected Quarterly Financial Data (unaudited), (dollars in thousands, except per-share amounts):
Approach Resources Inc. and Subsidiaries
Notes to Consolidated Financial Statements - (Continued)