10-K 1 arex-10k_20161231.htm 10-K arex-10k_20161231.htm

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark one)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to             

Commission file number: 001-33801

 

APPROACH RESOURCES INC.

(Exact name of registrant as specified in its charter)

 

Delaware

 

51-0424817

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

 

 

One Ridgmar Centre

6500 West Freeway, Suite 800

Fort Worth, Texas

 

76116

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code

(817) 989-9000

Securities registered pursuant to Section 12(b) of the Act:

 

 

 

 

Title of each class

 

Name of each exchange on which registered

Common stock, par value $0.01 per share

 

NASDAQ Global Select Market

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes      No  

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes      No  

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes      No  

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes      No  

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer

 

Accelerated filer

Non-accelerated filer

 

Smaller reporting company

Indicate by check mark whether the registrant is a shell company (as defined in Exchange Act Rule 12b-2).    Yes      No  

The aggregate market value of the voting and non-voting common equity held by non-affiliates (excluding voting shares held by officers and directors) as of June 30, 2016 was $80.3 million. This amount is based on the closing price of the registrant’s common stock on the NASDAQ Global Select Market on that date.

The number of shares of the registrant’s common stock, par value $0.01, outstanding as of March 6, 2017, was 80,903,376.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s proxy statement for its 2017 annual meeting of stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2016, are incorporated by reference in Part III, Items 10-14 of this report.

Certain exhibits previously filed with the Securities and Exchange Commission are incorporated by reference into Part IV of this report.

 

 

 

 

 


APPROACH RESOURCES INC.

Unless the context otherwise indicates, all references in this report to “Approach,” the “Company,” “we,” “us,” “our” or “ours” are to Approach Resources Inc. and its subsidiaries. Unless otherwise noted, (i) all information in this report relating to oil, NGLs and natural gas reserves and the estimated future net cash flows attributable to reserves is based on estimates and is net to our interest, and (ii) all information in this report relating to oil, NGLs and natural gas production is net to our interest. Natural gas is converted throughout this report at a rate of six Mcf of gas to one barrel of oil equivalent (“Boe”). NGLs are converted throughout this report 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. If you are not familiar with the oil and gas terms or abbreviations used in this report, please refer to the definitions of these terms and abbreviations under the caption “Glossary” after Item 16 of this report.

TABLE OF CONTENTS

 

 

 

 

 

Page

PART I

 

 

Item 1.

 

Business

 

1

Item 1A.

 

Risk Factors

 

14

Item 1B.

 

Unresolved Staff Comments

 

30

Item 2.

 

Properties

 

31

Item 3.

 

Legal Proceedings

 

38

Item 4.

 

Mine Safety Disclosures

 

38

 

 

 

 

 

PART II

 

 

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

39

Item 6.

 

Selected Financial Data

 

42

Item 7.

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

43

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

 

60

Item 8.

 

Financial Statements and Supplementary Data

 

62

Item 9.

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

62

Item 9A.

 

Controls and Procedures

 

63

Item 9B.

 

Other Information

 

63

 

 

 

 

 

PART III

 

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

 

64

Item 11.

 

Executive Compensation

 

64

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

64

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

 

64

Item 14.

 

Principal Accounting Fees and Services

 

64

 

 

 

 

 

PART IV

 

 

Item 15.

 

Exhibits, Financial Statement Schedules

 

65

Item 16.

 

Form 10-K Summary

 

65

Signatures

 

71

Index to Consolidated Financial Statements of Approach Resources Inc.

 

F-1

Index to Exhibits

 

72

 

ii

 


Cautionary Statement Regarding Forward-Looking Statements

Various statements in this report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). The forward-looking statements may include projections and estimates concerning the timing and success of specific projects, typical well economics and our future reserves, production, revenues, costs, income, capital spending, 3-D seismic operations, interpretation and results and obtaining permits and regulatory approvals. When used in this report, the words “will,” “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” “potential” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

These forward-looking statements are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. We caution all readers that the forward-looking statements contained in this report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the “Risk Factors” section and elsewhere in this report. All forward-looking statements speak only as of the date of this report. We disclaim any obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, unless required by law. These cautionary statements qualify all forward-looking statements attributable to us, or persons acting on our behalf. The risks, contingencies and uncertainties relate to, among other matters, the following:

 

uncertainties in drilling, exploring for and producing oil and gas;

 

oil, NGLs and natural gas prices;

 

overall United States and global economic and financial market conditions;

 

issuance of our common stock in connection with the Exchange Transactions (defined below) causing substantial dilution;

 

our leverage negatively affecting our semi-annual redetermination of our revolving credit facility;

 

domestic and foreign demand and supply for oil, NGLs, natural gas and the products derived from such hydrocarbons;

 

actions of the Organization of Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies relating to oil price and production controls;

 

our ability to obtain additional financing necessary to fund our operations and capital expenditures and to meet our other obligations;

 

our ability to maintain a sound financial position;

 

our cash flows and liquidity;

 

the effects of government regulation and permitting and other legal requirements, including laws or regulations that could restrict or prohibit hydraulic fracturing;

 

disruption of credit and capital markets;

 

disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, NGLs and natural gas and other processing and transportation considerations;

 

marketing of oil, NGLs and natural gas;

iii

 


 

high costs, shortages, delivery delays or unavailability of drilling and completion equipment, materials, labor or other services;

 

competition in the oil and gas industry;

 

uncertainty regarding our future operating results;

 

profitability of drilling locations;

 

interpretation of 3-D seismic data;

 

replacing our oil, NGLs and natural gas reserves;

 

our ability to retain and attract key personnel;

 

our business strategy, including our ability to recover oil, NGLs and natural gas in place associated with our Wolfcamp shale oil resource play in the Permian Basin;

 

development of our current asset base or property acquisitions;

 

estimated quantities of oil, NGLs and natural gas reserves and present value thereof;

 

plans, objectives, expectations and intentions contained in this report that are not historical; and

 

other factors discussed under Item 1A. “Risk Factors” in this report.

 

 

 

iv

 


PART I

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 123,000 net acres as of December 31, 2016. We believe our concentrated acreage position and extensive, integrated field infrastructure system provides 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, 2016, our estimated proved reserves were 156.4 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, 2016:

 

32% oil, 30% NGLs and 38% natural gas;

 

38% proved developed;

 

100% operated;

 

Reserve life of approximately 34 years based on 2016 production of 4.5 MMBoe;

 

Standardized measure of discounted future net cash flows (“standardized measure”) of $297.8 million; and

 

PV-10 (non-GAAP) of $307.9 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, 2016, we owned and operated 806 producing oil and gas wells in the Permian Basin. During 2016, we produced 4.5 MMBoe, or 12.4 MBoe/d. Production for 2016 was 28% oil, 34% 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.

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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. During 2014 and 2015, we experienced dramatic price decreases in the commodities we produce. As a result, we substantially reduced our drilling activity beginning in 2015 and throughout 2016, which led to a natural decline in production in 2016. Commodity prices were volatile in 2016 but improved throughout the year. We have positioned ourselves to increase our drilling activity at a measured and disciplined pace, and potentially resume production growth, in the event of a continued commodity price recovery, by focusing on the following strategies:

 

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 in a normalized commodity price environment. During 2016, we drilled six, and completed five, horizontal Wolfcamp wells. With our 2017 drilling plan, we expect to continue to develop our core properties in Project Pangea at an increased pace compared to 2016 due to a strengthened balance sheet resulting from the Exchange Transactions and recent commodity price improvement. 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.

 

Operate our business at or near cash-flow breakeven. In 2016, we generated $26.1 million in cash flow from operations and had capital expenditures of $19.8 million. In 2017, we have increased our expected capital expenditure budget to a range of $50 million to $70 million in response to increasing commodity prices and anticipated interest expense savings from the Initial Exchange (defined below) and the Follow-On Exchange (defined below) (together, the “Exchange Transactions”). We believe that over the long term we will be able to maintain and grow production out of operating cash flow. We have the operational flexibility to adjust our capital spending upward in response to a continued 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.

 

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 salt water 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.

 

Further strengthen our balance sheet and preserve financial flexibility. On November 2, 2016, we entered into an exchange agreement (the “Exchange Agreement”) with the largest holder of our 7% Senior Notes due 2021 (the “Senior Notes”) under which we exchanged $130,552,000 principal amount of our Senior Notes for 39,165,600 newly issued shares of our common stock (the “Initial Exchange”). We also have offered to exchange our remaining $99,768,000 principal amount of outstanding Senior Notes for shares of our common stock at a ratio of 276 shares of common stock for each $1,000 principal amount of the Senior Notes (the “Follow-On Exchange”). The Initial Exchange closed on January 27, 2017, resulting in future interest savings of approximately $40 million, which will provide us the flexibility to increase our capital budget out of operating cash flow. We anticipate the Follow-On Exchange will close on or around March 22, 2017.

 

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 look at conventional opportunities based on individual project economics.

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Mitigate commodity price volatility. We enter into commodity derivative contracts to partially mitigate the risk of commodity price volatility. For 2016, we hedged approximately 59% and 65% of our oil and gas production, respectively, which resulted in a realized gain on commodity derivatives of $6.1 million. For 2017, we currently have 8,400,000 MMBtu of gas hedged at an average floor price of $2.79 per MMBtu and an average ceiling price of $3.15 per MMBtu and 709,750 Bbls of NGLs hedged at average prices of $11.34 per Bbl (C2-ethane), $27.92 per Bbl (C3-propane), $36.73 per Bbl (IC4-isobutane) and $35.92 per Bbl (NC4-butane). For 2018, we currently have 5,400,000 MMBtu of gas hedged at an average price of $3.08 per MMBtu.

Our Competitive Strengths

We have a number of competitive strengths, which we believe will help us to successfully execute our business strategies:

 

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 790 wells in the area since 2004. Our acreage position of 137,000 gross, 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 2016 was 62% liquids (28% oil and 34% 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.

 

High degree of operational control.  We operate 100% of our estimated proved reserves, and we have approximately 100% 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.

 

Proactive financial management.  In 2016, we generated $26.1 million in operating cash flow, incurred $19.8 million of capital expenditures and had no increase in the principal balance of our debt outstanding.  As of December 31, 2016, we had liquidity of approximately $51.4 million. In addition, we are committed to a disciplined capital program and improving our operating cash flow. We are strengthening our balance sheet through the Exchange Transactions, which will enhance our liquidity position. We also enter into commodity derivative contracts to partially mitigate the risk of commodity price volatility.

 

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.

2016 Activity

Our 2016 activity focused on operating within cash flow while managing production declines, improving our cost structure and strengthening our balance sheet. We drilled six, and completed five, horizontal wells in 2016 in the Wolfcamp shale oil resource play in the Midland Basin. We plan to continue to develop the Wolfcamp shale in Project Pangea in 2017, at a measured, but increased pace from 2016, subject to commodity prices. Our activities in 2016 included:

 

Managed production decline. In 2016, we reduced our capital expenditures by $131.4 million, to $19.8 million. During the first quarter of 2016, our production declined by 12% compared to the prior quarter due to no new well completions from August 2015 through the first quarter of 2016 and natural production decline. Our production decreased by 1%, 3% and 1% in the second, third and fourth quarters of 2016, respectively. We managed our natural production decline through operating efficiencies and investment in well repairs, workovers and maintenance. Production for 2016 totaled 4.5 MMBoe (12.4 MBoe/d), compared to 5.5 MMBoe (15.2 MBoe/d) in 2015. Production for 2016 was 28% oil, 34% NGLs and 38% natural gas. At December 31, 2016, six wells were waiting on completion.

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Operated within operating cash flow. In 2016, we generated $26.1 million in operating cash flow, incurred $19.8 million of capital expenditures and had no increase in the principal balance of our debt outstanding.

 

Reduced operating expenses to improve operating cash flow. In 2016, through our cost saving initiatives, we reduced lease operating expenses by $9.7 million, general and administrative expenses by $3.6 million and production and ad valorem taxes by $2.9 million.  

 

Strengthened our balance sheet.  On November 2, 2016, we entered into the Exchange Agreement. In January 2017, we closed the Initial Exchange and launched the Follow-On Exchange. The Initial Exchange reduced our long-term debt by $130.6 million and will result in future interest savings of approximately $40 million. The Follow-On Exchange, if closed, is expected to further reduce our debt and improve our operating cash flow through the reduction of interest expense.

 

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, 2016, we had drilled and completed a total of 17 wells targeting the Wolfcamp A bench, 106 wells targeting the Wolfcamp B bench and 46 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 2016.

 

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 $115 million in building field infrastructure since 2012. We now have an extensive network of centralized production facilities, water transportation, handling and recycling systems, gas lift lines and salt water 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. In large part due to this infrastructure investment, we were able to reduce our lease operating expenses per Boe by 19% to $4.24, and our drilling and completion cost by 22% to $3.5 million, in 2016.

Plans for 2017

In January 2017, we closed the Initial Exchange and issued 39,165,600 shares of common stock in exchange for Senior Notes with a principal amount of $130,552,000. Additionally, we launched the Follow-On Exchange offering shares of our common stock, at a ratio of 276 shares of common stock per $1,000 principal amount of our Senior Notes, to the holders of our remaining $99,768,000 principal amount of outstanding Senior Notes. We anticipate closing the Follow-On Exchange on or around March 22, 2017. Assuming full participation in the Follow-On Exchange, together with the Initial Exchange, we would reduce our cash interest payments by $13.9 million in 2017 and by $69.5 million over the term of the Senior Notes. This will provide us the flexibility to use the interest savings to invest in our capital budget, to continue to reduce long-term debt or for other corporate purposes. There are no minimum subscription requirements for the Follow-On Exchange, and we cannot predict participation levels.

For 2017, we increased our capital expenditure budget to a range of $50 million to $70 million, compared to $19.8 million of capital expenditures in 2016. We currently have one rig running. Our 2017 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. 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, 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.

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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, seasonality, 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, 2016, sales to JP Energy Development, LP (“JP Energy”) and DCP Midstream, LP (“DCP”) accounted for approximately 54% and 46%, respectively, of our total sales. As of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy. In addition, as of December 31, 2016, we had dedicated all 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 2016, we realized $6.1 million in gains from our derivatives contracts, and the estimated fair value of our derivatives contracts at December 31, 2016, was a liability of $4.9 million. For 2017, we currently have 8,400,000 MMBtu of gas hedged at an average floor price of $2.79 per MMBtu and an average ceiling price of $3.15 per MMBtu and 709,750 Bbls of NGLs at average prices of $11.34 per Bbl (C2-ethane), $27.92 per Bbl (C3-propane), $36.73 per Bbl (IC4-isobutane) and $35.92 per Bbl (NC4-butane). For 2018, we currently have 5,400,000 MMBtu of gas hedged at an average price of $3.08 per MMBtu.

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

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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 that are subject to supervision by state regulators. 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.

Hydraulic fracturing requires the use of a significant amount of water. Upon flowback of the water, we dispose of it in a way that we believe minimizes the impact to nearby surface water by disposing into approved disposal facilities or injection wells. 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

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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.

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.”

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) 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 material compliance with federal, state and local rules, regulations and procedures, 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.

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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. 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. The failure to comply with these rules and regulations can result in substantial penalties. 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:

 

require the acquisition of various permits or authorizations before drilling begins;

 

require the installation of expensive pollution controls or emissions monitoring equipment;

 

restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and gas drilling, completion, production, transportation and processing activities;

 

suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, endangered species habitat and other protected areas; and

 

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.

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 clear trend in environmental regulation is 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 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

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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. It remains unclear what actions, if any, the Trump administration will undertake related to these laws, rules and regulations.

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, for damages to natural resources and for the costs of 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. Crude oil and fractions of crude oil are excluded from regulation under CERCLA. Nevertheless, many chemicals commonly used at oil and gas production facilities fall outside of the CERCLA 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 potentially 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 auspices of the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced water and most of the 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 classified as non-hazardous could be classified 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. 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. On May 12, 2016, the EPA issued

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three additional rules for the oil and gas industry to reduce emissions of methane, volatile organic compounds (“VOCs”) and other compounds.  These rules apply to all new, reconstructed, and modified processes and equipment since September 2015.  Among other things, the new rules impose green completion requirements on new hydraulically fractured oil wells and reduce allowable emissions of methane and VOCs. We do not expect that the NSPS or NESHAP 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 permit 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 greenhouse gases (“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 April 2010 and became effective in January 2011, but it does not require immediate reductions in GHG emissions. On August 3, 2015, the EPA issued a final rule to limit GHG emissions from new power plants. The agency simultaneously released a final rule to limit carbon emissions from existing power plants. While these regulations are currently the subject of litigation, including a stay issued by the U.S. Supreme Court, if the regulation ultimately is upheld 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. 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 December 2010, the EPA enacted final rules on mandatory reporting of GHGs. In 2011, the EPA published amendments to the rule containing technical and clarifying changes to certain GHG reporting requirements and a six-month extension for reporting GHG emissions from petroleum and natural gas industry sources. Under the amended rule, 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 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 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 or reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory requirements. In addition, the EPA has stated that the data collected from GHG emissions reporting programs may be the basis for future regulatory action to establish substantive GHG emissions factors. 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

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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”) 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. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

In June 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 re-injected into underground formations that do not contain potable water.

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 are 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 salt water disposal wells. The EPA has delegated administration of the UIC program 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.

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 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 salt water 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 October 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 new 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 salt water 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 water supply.

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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. Specifically, the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) has been introduced in each Congress since 2008 to accomplish these 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 February 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 December 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 June 2011, the RRC enacted a rule in December 2011, 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 compliance costs and could have a material adverse effect on our business, financial condition and results of operations.

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, 2016. 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 2017. 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.

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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, wetlands and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Clean Water Act and CERCLA. The United States Fish and Wildlife Service 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 prevent oil and gas exploration activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or 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 Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced 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.

Employees

As of February 22, 2017, we had 100 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

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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.

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.

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:

 

declines in oil, NGLs and gas prices;

 

inadequate capital resources or liquidity to maintain current production levels or further develop our assets;

 

compliance with governmental regulations, which may include limitations on hydraulic fracturing, access to water or the discharge of GHGs;

 

limited transportation services and infrastructure to deliver the oil, NGLs and natural gas we produce to market;

 

inability to attract and retain qualified personnel;

 

unavailability or high cost of drilling and completion equipment, services or materials;

 

unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents;

 

lack of acceptable prospective acreage;

 

adverse weather conditions;

 

surface access restrictions;

 

title problems;

 

mechanical difficulties;

 

natural disasters; and

 

civil unrest or protest activities.

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Oil, NGLs and gas prices are volatile and have declined significantly in recent years. Sustained declines in oil, NGLs or gas prices from current levels 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:

 

domestic and foreign supply of oil, NGLs and gas;

 

domestic and foreign consumer demand for oil, NGLs and gas;

 

overall United States and global economic conditions impacting the global supply of and demand for oil, NGLs and gas;

 

actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;

 

commodity processing, gathering and transportation availability, the availability of refining capacity and other factors that result in differentials to benchmark prices;

 

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 natural gas producing countries;

 

weather conditions, including unseasonably warm winter weather and tropical storms; and

 

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 $54.06 per Bbl to a low of $26.21 per Bbl in 2016. NYMEX-Henry Hub natural gas prices ranged from a high of $3.93 per MMBtu to a low of $1.64 per MMBtu in 2016. While prices have increased from recent lows, they are still significantly below previous highs. 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 decline from current levels for an extended period of time.

The ways that a decline in oil and gas prices from current levels could affect us include the following:

 

Cash flows would be reduced, decreasing funds available for capital expenditures needed to maintain or increase production and replace reserves;

 

We may breach covenants in our revolving credit facility;

 

Future net cash flows from our properties would decrease, which could result in significant impairment expenses;

 

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

 

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 decline from the 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 the Follow-On Exchange is not successful, we may seek alternative refinancing transactions.

We have been actively engaged in the process of analyzing various options to address our liquidity as well as assessing our overall capital structure. On January 27, 2017, we closed the Initial Exchange of $130,552,000 principal amount of our Senior Notes for 39,165,600 shares of newly issued shares of common stock, par value $0.01 per share. On January 30, 2017, we launched the Follow-On Exchange. If the Follow-On Exchange is not successful, we may determine to evaluate alternative transactions designed to reduce leverage and increase liquidity and operating cash flow. These alternative transactions may not be as advantageous to the existing holders of our common stock as the Follow-On Exchange. 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 or transactions which may have a more dilutive effect on our existing stockholders than the Follow-On Exchange.

The issuance of our common stock in connection with the Follow-On Exchange may cause substantial dilution, which could materially affect the trading price of our Common Stock.

If the maximum number of shares of common stock issuable is issued in connection with the Follow-On Exchange, these shares would represent approximately 25% of our outstanding shares of common stock.  These issuances could result in substantial decreases to our stock price.  In addition, subject to the terms of the Stockholders Agreement between the former largest holder of our Senior Notes (the “Equitizing Noteholder”) and the Company (the “Stockholders Agreement”), our existing stockholders may have reduced input on matters for which a stockholder vote is requested or required.

The Initial Exchange transaction concentrated significant voting power in the hands of one stockholder.

The Initial Exchange transaction resulted in a significant concentration of voting power held by the Equitizing Noteholder.  Even assuming full participation in the Follow-On Exchange, the Equitizing Noteholder will continue to be the Company’s largest individual stockholder immediately after the Follow-On Exchange.  Subject to the restrictions set forth in the Stockholders Agreement, the Equitizing Noteholder may have significant input on matters for which a stockholder vote is requested or required.

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The completion of the Follow-On Exchange is expected to result in a significant limitation on the use of our federal net operating loss carryforwards (“NOLs”), which could have a material adverse effect on our tax position.

A change in ownership of our common stock by more than 50% within a three-year period would result in a substantial portion of our NOLs being eliminated or becoming restricted, and we would need to reduce our deferred tax assets reflecting the restricted use of these NOLs when such an ownership change occurs. An ownership change would establish an annual limitation on the amount of our pre-change NOLs that we could use to offset our taxable income in any future taxable year to an amount generally equal to the value of our common stock immediately before the ownership change multiplied by the federal long-term tax exempt rate for the month of the ownership change. We do not expect that the Initial Exchange resulted in a change of ownership of 50% or more of our common stock; however, the Follow-On Exchange, or another significant acquisition of our common stock, may result in such an ownership change. We believe that we may be able to offset, in part, such limitation through our potential to generate NOLs in the future, and may be able to use otherwise limited NOLs to the extent we recognize, or are treated as recognizing, built-in gain on assets owned before the ownership change. If such an ownership change occurs as a result of the Follow-On Exchange, we estimate that we could recognize a non-recurring non-cash charge, in our statement of operations for the three months ended March 31, 2017, in the range of $100 million to $130 million, due to change in our deferred tax assets.

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 2016 reserve report, the estimated future capital required to develop our current proved oil and gas reserves is $808.8 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 2016, we funded our capital expenditures 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 decline from current levels, our cash flow from operations may 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.

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 $99.8 million principal amount of Senior Notes, after the Initial Exchange, and $273 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:

 

selling assets;

 

reducing or delaying capital investments;

 

seeking to raise additional capital; or

 

refinancing or restructuring our remaining debt.

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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 lenders can limit our borrowing capabilities, which may materially impact our operations.

At December 31, 2016, we had $273 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. We expect that our borrowing base will be redetermined in the second quarter of 2017. 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. If commodity prices decrease significantly, it is likely that our borrowing base will be reduced further in the next semi-annual borrowing base 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 March 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.  Low participation in the Follow-On Exchange transaction would result in our continuing with leverage in excess of OCC guidelines, which would increase 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 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:

 

sell assets, including equity interests in our subsidiaries;

 

consolidate, merge or transfer all or substantially all of our assets;

 

incur or guarantee additional indebtedness or issue preferred stock;

 

redeem or prepay other debt;

 

pay distributions on, redeem or repurchase our common stock or redeem or repurchase our subordinated debt;

 

create or incur certain liens;

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make certain acquisitions and investments;

 

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

 

engage in transactions with affiliates;

 

create unrestricted subsidiaries;

 

enter into financing transactions; and

 

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 decline from current levels, 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, could 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:

 

would not be required to lend any additional amounts to us;

 

could elect to declare all borrowings outstanding, together with accrued and unpaid interest and fees, to be due and payable;

 

may have the ability to require us to apply all of our available cash to repay these borrowings; or

 

may prevent us from making debt service payments under our other agreements.

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 recorded no impairment of our proved properties for the year ended December 31, 2016. For the year ended December 31, 2015, we recorded an impairment loss of $220.2 million. 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, 2016, we reclassified 22.4 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.

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The estimated volumes, standardized measure and present value of future net revenues (“PV-10”) from our proved reserves as of December 31, 2016, 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, 2016, our standardized measure of discounted cash flows was $297.8 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, 2016, and related standardized measure and PV-10, were calculated under the SEC rules using 12-month trailing average benchmark prices of $42.69 per Bbl of oil, $14.12 per Bbl of NGLs and $2.47 per MMBtu of gas. If oil, NGLs and gas prices decline by 10% from $42.69 per Bbl of oil, $14.12 per Bbl of NGLs and $2.47 per MMBtu of gas, to $38.42 per Bbl of oil, $12.71 per Bbl of NGLs and $2.22 per MMBtu of gas, then our PV-10 as of December 31, 2016, would decrease from $307.9 million to approximately $263.1 million. The average market price received for our production for the three months ended December 31, 2016 was $46.02 per Bbl of oil, $15.25 per Bbl of NGLs and $2.65 per Mcf of gas (after basis differential and Btu adjustments). 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 reduction, working capital or acquisitions. 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 2016, the price of our common stock fluctuated from a high of $4.35 per share to a low of $0.60 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.

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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. 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. We may experience differentials to benchmark prices in the future, which may be material.

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 2017 and 2018 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 on approximately 8,400,000 MMBtu of natural gas hedged with swaps and collars in 2017 at an average floor price of $2.79 per MMBtu and an average ceiling price of $3.15 per MMBtu and 709,750 BBls of NGLs at average prices of $11.34 per Bbl (C2-ethane), $27.92 per Bbl (C3-propane), $36.73 per Bbl (IC4-isobutane), and $35.92 per Bbl (NC4-butane). 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 2017 or our production after 2017. We have entered into derivative contracts for approximately 5,400,000 MMbtu of natural gas hedged with swaps at average prices of $3.08 per MMBtu for 2018. 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

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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 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 Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air emissions released during hydraulic fracturing, and, in June 2016, the EPA finalized regulations that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. 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. While the BLM’s final rule regarding hydraulic fracturing was struck down by the United States District Court for the District of Wyoming in June 2016, an appeal is currently pending in the Tenth Circuit Court of Appeals.   However, several states have already 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, 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.

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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 October 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 March 2016, the United States Geological Survey identified at least six 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 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. 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, 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 November 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 has indicated that it intends to use the information from this request to develop Existing Source Performance Standards for the oil and gas industry. If adopted, these standards would not be imposed directly on regulated entities. Instead, they would become guidelines that the states must consider in developing their own rules for regulating sources within their borders. The EPA has indicated that this information may also be used to develop standards for certain kinds of new and modified equipment and facilities not currently covered under the NSPS.

The adoption of legislation or regulatory programs to reduce GHG or VOC emissions 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. 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.

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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 late 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.

Changes in tax laws or fees may adversely affect our results of operations and cash flows.

Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this legislation or any other similar changes in U.S. federal income tax laws, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations. Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil, NGLs and gas.

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:

 

landing our wellbore in the desired drilling zone;

 

staying in the desired drilling zone while drilling horizontally through the formation;

 

running our casing the entire length of the wellbore; and

 

being able to run tools and other equipment consistently through the horizontal wellbore.

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Risks that we face while completing our wells include, but are not limited to:

 

the ability to fracture stimulate the planned number of stages;

 

the ability to run tools the entire length of the wellbore during completion operations; and

 

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:

 

our ability to finance development of the project;

 

the extent of our success in drilling and completing horizontal Wolfcamp wells;

 

our ability to control costs and manage drilling and completion risks;

 

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

 

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 2016, JP Energy and DCP collectively accounted for more than 99% of our total oil, NGLs and gas sales, excluding realized commodity derivative settlements. As of December 31, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy. In addition, as of December 31, 2016, we had dedicated all 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

25

 


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 any of these individuals, 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. In January 2011, we entered into an amended and restated employment agreement with J. Ross Craft, P.E., our Chairman and Chief Executive Officer. On January 3, 2014, we entered into an employment agreement with Sergei Krylov as the Company’s Executive Vice President and Chief Financial Officer. In January 2017, we amended our employment agreements with Qingming Yang, our President and Chief Operating Officer; and J. Curtis Henderson, our Chief Administrative Officer. If any of these officers or other key personnel resign or become unable to continue in their present roles 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

26

 


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, 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.

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.

27

 


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, 2016, 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 27% of our net acreage, and 3% of our proved undeveloped reserves. Unless we continue to develop and produce on the properties subject to these leases, these leases may expire in 2017. If these leases expire, we will lose our right to develop the related properties, unless we renew such leases. 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 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:

 

historical production from the area compared with production from other similar producing areas;

 

the assumed effects of regulations by governmental agencies;

 

assumptions concerning future oil, NGLs and gas prices; and

 

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:

 

the quantities of oil, NGLs and gas that are ultimately recovered;

 

the production and operating costs incurred;

 

the amount and timing of future development expenditures; and

 

future oil, NGLs and gas prices.

As of December 31, 2016, approximately 62% 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.

28

 


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. Repercussions of severe weather conditions may include:

 

curtailment of services, including oil, NGLs and gas pipelines, processing plants and trucking services;

 

weather-related damage to drilling rigs, resulting in a temporary suspension of operations;

 

weather-related damage to our producing wells or facilities;

 

inability to deliver materials to jobsites in accordance with contract schedules; and

 

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

29

 


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:

 

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

 

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.

UNRESOLVED STAFF COMMENTS

As of the date of this filing, we have no unresolved comments from the staff of the SEC.

 

 


30

 


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 137,000 gross (123,000 net) acres as of year-end 2016. At December 31, 2016, we owned interests in approximately 806 gross (794 net) wells, all of which we operate. As of December 31, 2016, we had working and net revenue interests of approximately 100% 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, 2016, we have drilled and completed a total of 17 wells targeting the Wolfcamp A bench, 106 wells targeting the Wolfcamp B bench and 46 wells targeting the Wolfcamp C bench. As of December 31, 2016, estimated proved reserves attributable to the horizontal Wolfcamp shale oil play accounted for 93% of our total proved reserves.

31

 


 

During 2016, we incurred costs of approximately $17.8 million to drill six, and complete five, horizontal Wolfcamp wells. At December 31, 2016, we had six horizontal Wolfcamp wells waiting on completion. We currently have one rig running in Project Pangea.

East Texas Basin — North Bald Prairie

In July 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 began drilling operations in August 2007. We have drilled and completed 11 gross wells, including one well completed as a saltwater disposal well. 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, 2016, we had estimated proved reserves of 512 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, 2016. 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 $42.69 per Bbl West Texas Intermediate posted oil price, $14.12 per Bbl received for NGLs and $2.47 per MMBtu Henry Hub spot natural gas price during 2016. 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

 

 

 

Proved Reserves

 

 

 

 

 

Reserves Category

 

Oil

(MBbls)

 

 

NGLs

(MBbls)

 

 

Natural

Gas

(MMcf)(1)

 

 

Total

(MBoe)

 

 

Percent

(%)

 

 

PV-10

(in millions)(2)

 

Proved Developed

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

 

13,466

 

 

 

20,375

 

 

 

149,696

 

 

 

58,790

 

 

 

37.6

%

 

$

295.5

 

East Texas Basin

 

 

 

 

 

 

 

 

512

 

 

 

85

 

 

 

0.0

 

 

 

0.3

 

Proved Undeveloped

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Permian Basin

 

 

36,565

 

 

 

27,259

 

 

 

202,069

 

 

 

97,502

 

 

 

62.4

 

 

 

12.1

 

Total Proved Reserves

 

 

50,031

 

 

 

47,634

 

 

 

352,277

 

 

 

156,377

 

 

 

100.0

%

 

$

307.9

 

 

(1)

The gas reserves contain 44,178 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, 2016, were 156.4 MMBoe, made up of 32% oil, 30% NGLs and 38% natural gas. The proved developed portion of total proved reserves at year-end 2016 was 38%.

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

32

 


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.

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, 2016:

 

 

 

December 31,

2016

(in millions)

 

PV-10

 

$

307.9

 

Present value of future income tax discounted at 10%

 

 

(10.1

)

Standardized measure of discounted future net

   cash flows

 

$

297.8

 

 

Proved Undeveloped Reserves

As of December 31, 2016, we had 97.5 MMBoe of proved undeveloped (“PUD”) reserves, which is a decrease of 7.3 MMBoe, or 7%, compared with 104.8 MMBoe of PUD reserves at December 31, 2015. All of our PUD reserves at December 31, 2016, were associated with our core development project, Project Pangea.

The following table summarizes the changes in our PUD reserves during 2016.

 

 

 

Oil

(MBbls)

 

 

NGLs

(MBbls)

 

 

Natural Gas

(MMcf)

 

 

Total

(MBoe)

 

Balance — December 31, 2015

 

 

38,829

 

 

 

29,072

 

 

 

221,336

 

 

 

104,790

 

Extensions and discoveries

 

 

6,221

 

 

 

4,372

 

 

 

31,906

 

 

 

15,910

 

Revisions to previous estimates

 

 

(8,066

)

 

 

(5,752

)

 

 

(48,033

)

 

 

(21,822

)

Conversion to proved developed reserves

 

 

(419

)

 

 

(433

)

 

 

(3,140

)

 

 

(1,376

)

Balance — December 31, 2016

 

 

36,565

 

 

 

27,259

 

 

 

202,069

 

 

 

97,502

 

 

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The following table sets forth our PUD reserves converted to proved developed reserves during 2016, 2015 and 2014 and the net investment required to convert PUD reserves to proved developed reserves during each year.

 

 

 

Proved Undeveloped Reserves

Converted to Proved Developed

Reserves

 

 

Investment in Conversion of

Proved Undeveloped

Reserves to Proved

Developed Reserves

 

Year Ended

December 31,

 

Oil

(MBbls)

 

 

NGLs

(MBbls)

 

 

Natural

Gas

(MMcf)

 

 

Total

(MBoe)

 

 

(in thousands)

 

2014

 

 

3,430

 

 

 

1,645

 

 

 

10,753

 

 

 

6,867

 

 

$

106,309

 

2015

 

 

2,485

 

 

 

1,627

 

 

 

11,737

 

 

 

6,068

 

 

 

84,071

 

2016

 

 

419

 

 

 

433

 

 

 

3,140

 

 

 

1,376

 

 

 

11,008

 

Total

 

 

6,334

 

 

 

3,705

 

 

 

25,630

 

 

 

14,311

 

 

$

201,388

 

 

Estimated future development costs relating to the development of PUD reserves are projected to be approximately $55 million in 2017, $154 million in 2018 and $262 million in 2019. 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, 2016, 2015 and 2014, 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 2016, 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

34

 


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, 2016, NGLs represented approximately 30% 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 2016 averaged approximately 66% 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, 2016, 2015 and 2014, 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 2016 is included as Exhibit 99.1 to this annual report on Form 10-K.

35

 


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.

 

 

 

Years Ended December 31,

 

Production

 

2016

 

 

2015

 

 

2014

 

Oil (MBbls)

 

 

1,275

 

 

 

1,882

 

 

 

2,024

 

NGLs (MBbls)

 

 

1,529

 

 

 

1,694

 

 

 

1,461

 

Gas (MMcf)(1)

 

 

10,404

 

 

 

11,732

 

 

 

9,383

 

Total (MBoe)

 

 

4,537

 

 

 

5,532

 

 

 

5,049

 

Total (MBoe/d)

 

 

12.4

 

 

 

15.2

 

 

 

13.8

 

Average prices

 

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

 

$

37.90

 

 

$

43.65

 

 

$

87.69

 

NGLs (per Bbl)

 

 

12.93

 

 

 

12.06

 

 

 

28.74

 

Gas (per Mcf)

 

 

2.14

 

 

 

2.45

 

 

 

4.16

 

Total (per Boe)

 

 

19.90

 

 

 

23.74

 

 

 

51.20

 

Realized gain on commodity derivatives (per Boe)

 

 

1.35

 

 

 

9.49

 

 

 

0.47

 

Total including derivative impact (per Boe)

 

$

21.25

 

 

$

33.23

 

 

$

51.67

 

Production costs (per Boe)(2)

 

$

4.24

 

 

$

5.24

 

 

$

6.48

 

 

(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 is made up of 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.

 

 

 

Years Ended December 31,

 

 

 

2016

 

 

2015

 

 

2014

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

6.0

 

 

 

6.0

 

 

 

20.0

 

 

 

20.0

 

 

 

68.0

 

 

 

68.0

 

Dry(1)

 

 

 

 

 

 

 

 

1.0

 

 

 

1.0

 

 

 

2.0

 

 

 

2.0

 

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Dry

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

 

6.0

 

 

 

6.0

 

 

 

20.0

 

 

 

20.0

 

 

 

68.0

 

 

 

68.0

 

Dry

 

 

 

 

 

 

 

 

1.0

 

 

 

1.0

 

 

 

2.0

 

 

 

2.0

 

 

(1)

The Company encountered mechanical issues while drilling the wells classified as dry in 2015 and 2014.

In 2016, we drilled six horizontal wells and completed five horizontal wells. At December 31, 2016, six wells were waiting on completion. The Company encountered mechanical issues while drilling one well in 2015 and two wells in 2014, and these wells cost $2.4 million and $5.6 million, respectively.

36

 


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 one horizontal rig running in the Permian Basin targeting the Wolfcamp shale oil resource play.

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, 2016, we had dedicated all of our oil production from northern Project Pangea and Pangea West through September 2022 to JP Energy and had dedicated all 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, 2016. Wells are classified as natural gas or oil according to their predominant production stream.

 

 

 

Natural Gas

Wells

 

 

Oil

Wells

 

 

Total

Wells

 

 

Average

Working

Interest

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

 

 

 

Permian Basin

 

 

534

 

 

 

523

 

 

 

272

 

 

 

271

 

 

 

806

 

 

 

794

 

 

 

98.5

%

East Texas Basin

 

 

9

 

 

 

4.5

 

 

 

 

 

 

 

 

 

9

 

 

 

4.5

 

 

 

49.9

%

Total

 

 

543

 

 

 

527.5

 

 

 

272

 

 

 

271

 

 

 

815

 

 

 

798.5

 

 

 

98.0

%

 

Acreage

The following table summarizes our developed and undeveloped acreage as of December 31, 2016.

 

 

 

Developed Acres

 

 

Undeveloped Acres

 

 

Total Acres

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Permian Basin

 

 

90,127

 

 

 

81,630

 

 

 

46,680

 

 

 

41,777

 

 

 

136,807

 

 

 

123,407

 

East Texas Basin

 

 

3,481

 

 

 

1,687

 

 

 

 

 

 

 

 

 

3,481

 

 

 

1,687

 

Total

 

 

93,608

 

 

 

83,317

 

 

 

46,680

 

 

 

41,777

 

 

 

140,288

 

 

 

125,094

 

 

Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres as of December 31, 2016, which will expire over the next three years by project area, 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.

 

 

 

2017

 

 

2018

 

 

2019

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Permian Basin

 

 

33,495

 

 

 

34,022

 

 

 

107

 

 

 

11

 

 

 

 

 

 

40

 

East Texas Basin

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total

 

 

33,495

 

 

 

34,022

 

 

 

107

 

 

 

11

 

 

 

 

 

 

40

 

 

The expiring acreage set forth in the table above accounts for 27% of our net acreage, and 3% of our PUD reserves. Of the 34,022 net acres scheduled to expire in 2017, 16,844 net acres are leased from The Board for Lease of University Lands (“University Lands”) under a Drilling and Development Unit Agreement (“D&D agreement”). Under the D&D agreement, we are required to drill and complete two wells per calendar year until September 2017, and in September 2017, we will present a development plan to University Lands that will outline a proposed capital

37

 


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. 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.

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.

MINE SAFETY DISCLOSURES

Not applicable.

38

 


PART II

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 2016, trading volume averaged 1,015,691 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.

 

 

 

Price Per Share

 

 

 

High

 

 

Low

 

2016

 

 

 

 

 

 

 

 

First quarter

 

$

2.05

 

 

$

0.60

 

Second quarter

 

 

3.10

 

 

 

1.13

 

Third quarter

 

 

4.35

 

 

 

1.35

 

Fourth quarter

 

 

4.33

 

 

 

2.51

 

2015

 

 

 

 

 

 

 

 

First quarter

 

$

9.15

 

 

$

5.01

 

Second quarter

 

 

9.57

 

 

 

6.35

 

Third quarter

 

 

6.95

 

 

 

1.65

 

Fourth quarter

 

 

3.19

 

 

 

1.23

 

 

Holders

As of February 21, 2017, there were 161 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, 2016.

 

Plan Category

 

Number of

Securities to be

Issued Upon

Exercise of

Outstanding

Options, Warrants

and Rights

(a)

 

 

Weighted-Average

Exercise Price of

Outstanding

Options, Warrants

and Rights

(b)

 

 

Number of Securities

Remaining Available for

Future Issuance under

Equity Compensation Plans

(Excluding Securities

Reflected in Column (a))(1)

(c)

 

Equity compensation plans

   approved by stockholders

 

 

38,525

 

 

$

12.00

 

 

 

2,742,394

 

Equity compensation plans not

   approved by stockholders

 

 

 

 

 

 

 

 

 

 

39

 


Performance Graph

The following graph compares the cumulative return on a $100 investment in our common stock from December 31, 2011, through December 31, 2016, to that of the cumulative return on a $100 investment in the Standard & Poor’s 500 (“S&P 500”) index, and Standard & Poor’s 600 Small Cap Energy index for the same period. In calculating the cumulative return, reinvestment of dividends, if any, is assumed. This graph is not “soliciting material,” is not deemed filed with the SEC and is not to be incorporated by reference in any of our filings under the Securities Act or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language in any such filing. This graph is included in accordance with the SEC’s disclosure rules. This historic stock performance is not indicative of future stock performance.

COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN

Among Approach Resources Inc., the S&P 500 Index and the S&P 600 Small Cap Energy Index

 

 

 

12/31/2011

 

 

12/31/2012

 

 

12/31/2013

 

 

12/31/2014

 

 

12/31/2015

 

 

12/31/2016

 

Approach Resources Inc.

 

$

100.00

 

 

$

85.04

 

 

$

65.62

 

 

$

21.73

 

 

$

6.26

 

 

$

11.39

 

S&P 500

 

 

100.00

 

 

 

113.41

 

 

 

146.98

 

 

 

163.72

 

 

 

162.53

 

 

 

178.02

 

S&P 600 Small Cap Energy Index

 

 

100.00

 

 

 

99.48

 

 

 

137.08

 

 

 

88.18

 

 

 

46.18

 

 

 

63.52

 

40

 


Issuer Repurchases of Equity Securities

Our 2007 Stock Incentive Plan (the “2007 Plan”) allows 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 2007 Plan.