10-K 1 rexx-10k_20161231.htm 10-K rexx-10k_20161231.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2016

Commission file number: 001-33610

 

REX ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

 

 

Delaware

 

20-8814402

(State or other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. employer

identification number)

366 Walker Drive

State College, Pennsylvania 16801

(Address of Principal Executive Offices)

(Zip Code)

(814) 278-7267

(Registrant’s telephone number, including area code)

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

 

Title of each class

 

Name of each exchange on which registered

Common Stock, $.001 par value per share

 

The NASDAQ Capital 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 (§232.405 of this chapter) 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 (§229.405) 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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (check one):

 

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 Rule 12b-2 of the Exchange Act).    Yes      No  

The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2016 was $46,993,210. This amount is based on the closing price of the registrant’s common stock on The NASDAQ Global Select Market, the exchange on which the common stock traded as of June 30, 2016, on that date. Shares of common stock beneficially held by executive officers and directors of the registrant are not included in the computation. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

98,013,126 common shares, $.001 par value, were outstanding on March 2, 2017.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for its 2017 Annual Meeting of Stockholders to be held in May 2017, are incorporated by reference herein in Items 10, 11, 12, 13 and 14 of Part III of this report.

 

 

 

 

 


 

REX ENERGY CORPORATION

FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2016

Unless otherwise indicated, all references to “Rex Energy Corporation,” “the Company,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries. Natural gas is converted throughout this report at a rate of six Mcf of gas to one barrel of oil equivalent (“BOE”). Natural Gas Liquids (“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” at the end of “Item 15. Exhibits and Financial Statement Schedules” of this report.

 

 

 

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TABLE OF CONTENTS

 

PART I

 

Item 1.

 

Business

6

Item 1A.

 

Risk Factors

15

Item 1B.

 

Unresolved Staff Comments

32

Item 2.

 

Properties

33

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

41

Item 7.

 

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

48

Item 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

71

Item 8.

 

Financial Statements and Supplementary Data

73

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

133

Item 9A.

 

Controls and Procedures

133

Item 9B.

 

Other Information

135

 

PART III

 

 

 

Item 10.

 

Directors, Executive Officers and Corporate Governance

135

Item 11.

 

Executive Compensation

135

Item 12.

 

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

135

Item 13.

 

Certain Relationships and Related Transactions and Director Independence

135

Item 14.

 

Principal Accountant Fees and Services

135

 

PART IV

 

 

 

Item 15.

 

Exhibits and Financial Statement Schedules

136

Item 16.

 

Form 10-K Summary

143

 

GLOSSARY

SIGNATURES

 

 

 

 

 

 

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CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS

Some of the information, including all of the estimates and assumptions, in this report contain forward-looking statements within the meaning of Sections 27A of the Securities Act of 1933, as amended, and 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this report, including, but not limited to, statements regarding our future financial position, business strategy, budgets, projected costs, savings and plans, objectives of management for future operations, legal strategies, and legal proceedings, are forward-looking statements. Forward-looking statements generally can be identified by the use of forward-looking terminology such as “may”, “will”, “expect”, “intend”, “estimate”, “anticipate”, “believe”, or “continue” or the negative thereof or variations thereon or similar terminology.

These forward-looking statements are subject to numerous assumptions, risks, and uncertainties. Factors that may cause our actual results, performance, or achievements to be materially different from those anticipated in forward-looking statements include, among others, the following:

 

economic conditions in the United States and globally;

 

domestic and global supply and demand for oil, NGLs and natural gas;

 

realized prices for oil, natural gas and NGLs and volatility of those prices;

 

the adequacy and availability of capital resources, credit and liquidity, including, but not limited to, access to additional borrowing capacity and our inability to generate sufficient cash flow from operations to fund our capital expenditures and meeting working capital needs;

 

our ability to comply with restrictions imposed by our senior credit facility and other existing and future financing arrangements;

 

our ability to service our outstanding indebtedness

 

impairments of our natural gas and oil asset values due to declines in commodity prices;

 

conditions in the domestic and global capital and credit markets and their effect on us;

 

new or changing government regulations, including those relating to environmental matters, permitting or other aspects of our operations;

 

the willingness and ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain oil price and production controls;

 

the geologic quality of our properties with regard to, among other things, the existence of hydrocarbons in economic quantities;

 

uncertainties inherent in the estimates of our oil, NGL and natural gas reserves;

 

our ability to increase oil, NGL and natural gas production and income through exploration and development;

 

drilling and operating risks;

 

counterparty credit risks;

 

the success of our drilling techniques in both conventional and unconventional reservoirs;

 

the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future;

 

the number of potential well locations to be drilled, the cost to drill, and the time frame within which they will be drilled;

 

the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services;

 

the availability of equipment, such as drilling rigs, and infrastructure, such as transportation, pipelines, processing and midstream services;

 

the effects of adverse weather or other natural disasters on our operations;

 

competition in the oil and gas industry in general, and specifically in our areas of operations;

 

changes in our drilling plans and related budgets;

 

the success of prospect development and property acquisitions;

 

the success of our business and financial strategies, and hedging strategies;

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uncertainties related to the legal and regulatory environment for our industry and our own legal proceedings and their outcome;

 

our ability to cure the deficiencies with respect to the continued listing standards of The NASDAQ Capital Market or any other exchange on which our securities trade; and

 

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

Because forward-looking statements are subject to risks and uncertainties, actual results may differ materially from those expressed or implied by such statements. You are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this report. Other unknown or unpredictable factors may cause actual results to differ materially from those projected by the forward-looking statements. Most of these factors are difficult to anticipate and may be beyond our control. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

All forward-looking statements attributable to us are expressly qualified in their entirety by these cautionary statements.

 

 

 

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PART I

ITEM 1

BUSINESS

General

We are an independent condensate, NGL and natural gas company operating in the Appalachian Basin. We are focused on drilling and exploration activities in the Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale. We pursue a balanced growth strategy of exploiting our sizable inventory of high potential exploration drilling prospects while actively seeking to acquire complementary oil and natural gas properties.

We are headquartered in State College, Pennsylvania and have a regional office in Cranberry, Pennsylvania.

We were incorporated in the state of Delaware on March 8, 2007. Our common stock currently trades on The NASDAQ Capital Market under the symbol “REXX”. The information set forth in this report is exclusive of our discontinued operations related to the DJ Basin, for which the related assets were sold in 2012 and 2013, Water Solutions Holdings, LLC and its subsidiaries (“Water Solutions”), which were sold in July 2015, and the Illinois Basin, for which the related assets were sold in August 2016, unless otherwise noted. These operations are classified as Discontinued Operations on our Consolidated Statements of Operations and Assets Held for Sale on our Consolidated Balance Sheets. Our estimated proved reserves account for the sale of our Illinois Basin assets in August 2016 and have not been retroactively restated to remove the associated estimated proved reserves from prior year balances.

At December 31, 2016, our estimated proved reserves had the following characteristics:

 

647.8 Bcfe;

 

56.8% natural gas, 41.5% NGLs and 1.7% condensate;

 

100.0% proved developed; and

 

a reserve life index of approximately 9.1 years (based upon 2016 production).

At December 31, 2016, we owned an interest in approximately 559.0 condensate, NGL and natural gas wells. For the quarter ended December 31, 2016, we produced an average of 194.9 net MMcfe per day, composed of approximately 62.0% natural gas, 3.4% condensate and 34.6% NGLs.

In the Appalachian Basin during 2016, we averaged net production of approximately 195.3 MMcfe per day of natural gas, NGLs and condensate. As of December 31, 2016, including both developed and undeveloped acreage, we controlled approximately 214,600 gross (160,700 net) acres in Pennsylvania that we believe are prospective for Marcellus Shale exploration and 174,400 gross (147,700 net) acres in Pennsylvania that we believe are prospective for Burkett Shale exploration. In addition, as of December 31, 2016, we controlled approximately 219,000 gross (180,100 net) acres, which includes both developed and undeveloped acreage, in Pennsylvania and Ohio that we believe are prospective for Utica Shale exploration.

Our total revenue from continuing operations for the year ended December 31, 2016 was $139.0 million, which was primarily derived from the sale of condensate, NGLs and natural gas.

For the year ended December 31, 2016, we drilled 20.0 gross (8.4 net) wells. We placed into sales 34.0 gross (16.2 net) wells and ended the year with nine gross (3.8 net) wells in inventory that are awaiting completion.

The following table sets forth selected data concerning our continuing operations for production, estimated proved reserves and undeveloped acreage for the periods indicated: 

 

2016 Average

Daily Mcfe1

 

 

Total Proved

Bcfe

(as of December

31, 2016)

 

 

Percent of

Total

Proved Bcfe

 

 

Standardized Measure (as of December 31, 2016) (in millions)

 

 

PV-10 (as of December

31, 2016)2 (in millions)

 

 

Total Net

Undeveloped

Acres (as of

December

31, 2016)3

 

 

195,331

 

 

 

647.8

 

 

 

100.0

%

 

$

165.6

 

 

$

175.5

 

 

 

75,568

 

 

1

Oil, condensate and NGLs are converted at the rate of one BOE to six Mcfe.

2

Represents the present value, discounted at 10% per annum (PV-10), of our estimated future net cash flows of our estimated proved reserves before income tax and asset retirement obligations. PV-10 is a non-GAAP financial measure because it excludes the effects of income taxes and asset retirement obligations. The most directly comparable GAAP measure is standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows includes the effects of estimated future income tax expenses and asset retirement obligations and is calculated in accordance with Accounting Standards Topic 932. Standardized measure is based on proved reserves as of fiscal year-end calculated using the unweighted arithmetic average first-day-of-month prices

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for the prior 12 months. PV-10 should not be considered as an alternative to the standardized measure of discounted future net cash flows as defined under GAAP. Our PV-10 measure and the Standardized Measure of discounted future cash flows do not purport to represent the fair value of our oil and natural gas reserves. At December 31, 2016, our standardized measure was $165.6 million. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, please read “Item 6. Selected Financial Data – Non-GAAP Financial Measures.” Please also read “Risk Factors – Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”

3

Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage includes estimated proved reserves.

Our Competitive Strengths

We believe our strengths provide us with significant competitive advantages and position us to successfully execute our business and growth strategies.

High Quality Asset Base with Liquids-Weighted Growth. We are focused on developing acreage that we believe to be prospective for three producing zones, the Marcellus Shale, the Burkett Shale and the Utica Shale. A substantial portion of our acreage holdings are in liquids-rich areas that we believe are prospective for condensate and NGL production. As of December 31, 2016, our holdings believed to be prospective for liquids-rich production accounted for approximately 85.5% of our total net acreage.

Track Record of Production Growth. Our management and operations teams have a proven track record of performance and have consistently demonstrated our ability to acquire and develop reserves at attractive costs in the basins in which we operate. Our production has grown at a CAGR of 61.0% between the fourth quarter of 2010 and the fourth quarter of 2016. We believe we have competitive finding and development costs as compared to our industry peers.

Significant Operational Control in Our Core Areas. As a result of successfully executing our strategy of acquiring concentrated acreage positions and operating properties with a high working interest, we currently operate and manage over 93.6% of our net acreage. Our high percentage of operated properties enables us to exercise a significant level of control with respect to the timing and scope of drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas.

History of Maximizing Operating Efficiencies. Our costs of operations continue to decrease year-over-year as we leverage our increasing production, pricing concessions from service providers and our expertise in the regions in which we operate. Our field level lease operating expense per Mcfe, which excludes the effect of transporting, marketing and processing, has decreased from $0.17 per Mcfe in 2014 to $0.15 per Mcfe in 2015 and $.012 per Mcfe in 2016. Our general and administrative expense per Mcfe has decreased from $0.62 per Mcfe in 2014 to $0.40 per Mcfe in 2015 and $0.28 per Mcfe in 2016.

Business Strategy

Our goal is to build long-term stockholder value by growing reserves and production in a cost-effective manner. Key elements of our strategy include:

Develop Our Existing Properties. Our core leasehold consists entirely of interests in developed and undeveloped condensate, NGL and natural gas resources located in the Appalachian Basin. We pursue an active, technology-driven drilling program to develop and maximize the value of our existing acreage. We actively allocate capital in an effort to maximize value and estimated proved reserve growth based on our assessment of the relative risk of development and the economics of potential projects. Additionally, by concentrating our drilling and producing activities in our core areas, we are able to develop the regional expertise needed to interpret specific geological and operating trends and develop economies of scale in our operations. Our areas of focus include:

 

our Marcellus Shale play with approximately 214,600 gross (160,700 net) acres;

 

our Utica Shale play with approximately 219,000 gross (180,100 net) acres;

 

our Burkett Shale play with approximately 174,400 gross (147,700 net) acres;

Employ Technological Expertise. We intend to utilize and expand the technological expertise that has enabled us to achieve a drilling success rate of approximately 100.0% over the last three years, to improve operations and to enhance field recoveries. We intend to continue to apply this expertise to our proved reserve base and our development projects.

Reduce Per Unit Operating Costs Through Economies of Scale and Efficient Operations. As we continue to increase our production and develop our existing properties, we believe that our per unit production costs can benefit from leveraging our existing infrastructure and expertise over a larger number of wells. Our acreage positions are tightly concentrated, which we believe will

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enable us to achieve greater cost efficiencies in our drilling and completion operations than those of our competitors who have less consolidated positions. As we continue to develop our acreage positions, we expect to realize increased capital efficiencies through greater utilization of multi-well pads and existing infrastructure and facilities.

Maintain Capital Budgeting Flexibility. Because of the volatility of commodity prices and the risks involved in our industry, we believe in remaining flexible in our capital budgeting process. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs.

Manage Commodity Price Exposure Through an Active Hedging Program. We actively hedge our future exposure to commodity price fluctuations by entering into oil, natural gas and NGL derivative contracts. This strategy is designed to provide us with stability in our cash flows to support our on-going capital requirements. As of December 31, 2016, we had over 65.0% of our 2016 condensate production volumes hedged through 2017, over 75.0% of our 2016 natural gas production volumes hedged through 2017 and over 50.0% of our 2016 NGL production volumes hedged through 2017. Including the effects of derivatives added since December 31, 2016, we have over 80.0% of our 2016 natural gas production hedged through 2016 and over 60.0% of our 2016 NGL production hedged through 2016. These percentages exclude the effects of our basis swaps and do not include any estimated impact of increased production from future development or the natural decline of our condensate, NGL and gas production.

Significant Accomplishments in 2016

We have described certain of our significant accomplishments in 2016 below.

 

Completed the divestiture of Illinois Basin Assets. In August 2016, we sold our Illinois Basin assets for total consideration of approximately $40.5 million, inclusive of cash and debt.

 

Entered into a joint venture to develop properties in our Butler County, Pennsylvania and Warrior North, Ohio core areas. In March 2016, we entered into a joint venture agreement with an affiliate of Benefit Street Partners, LLC (“BSP”) to jointly develop 58 specifically designated wells in our Butler County, Pennsylvania and Warrior North, Ohio operated areas. We expect to receive consideration for the transaction of approximately $175.0 million, with $19.5 million received at closing. As of December 31, 2016, BSP had committed to approximately $126.1 million and paid approximately $82.4 million for its interest in wells that have been drilled or are in the process of being drilled. In January 2017, BSP elected into an additional five wells for a total of $15.8 million in additional capital commitments.

 

Achieved horizontal drilling success. In our operated areas of the Appalachian Basin we drilled 20.0 gross (8.4 net) wells and placed 34.0 gross (16.2 net) wells into service during 2016. As of December 31, 2016, we had nine gross (3.8 net) wells awaiting completion in our operated areas in the Appalachian Basin.

 

Decreased operating expenses. Our costs of operations continue to decrease year-over-year as we leverage our increasing production, pricing concessions from service providers and our expertise in the regions in which we operate. Our field level lease operating expense per Mcfe, which excludes the effect of transporting, marketing and processing, has decreased from $0.17 per Mcfe in 2014 to $0.15 per Mcfe in 2015and $.012 per Mcfe in 2016. Our general and administrative expense per Mcfe has decreased from $0.62 per Mcfe in 2014 to $0.40 per Mcfe in 2015 and $0.28 per Mcfe in 2016.

 

Realized production growth. Due to the success of our development programs in the Appalachian Basin, we increased our total production by 6.5% in 2016. Specifically, our condensate production decreased 10.5%, NGL production increased 22.8% and natural gas production increased 0.2%.

 

Grew liquids-rich production. For the year ended December 31, 2016, our production related to condensate and NGLs comprised approximately 37.5% of our total production as compared to the year ended December 31, 2015, where our production related to condensate and NGLs comprised approximately 33.5% of our total production.

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Plans for 2017

We are currently in the process of developing our 2017 capital expenditure budget, which we expect to be between $70.0 and $80.0 million. We anticipate that a significant portion of this budget will be allocated toward further development in the Appalachian Basin. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending. The following table summarizes our actual 2016 capital expenditures: 

 

 

 

For the Years Ended December 31, ($ in thousands)

 

 

 

2017 (Estimated)

 

 

2016 (Actual)

 

Capital Expenditures

 

 

 

 

 

 

 

 

Drilling & Completion

 

$

73,000

 

 

$

24,021

 

Midstream

 

 

1,500

 

 

 

2,317

 

Other Field Assets

 

 

2,500

 

 

 

1,564

 

Other Corporate Expenditures

 

 

500

 

 

 

273

 

Total Capital Expenditures1

 

$

77,500

 

 

$

28,175

 

 

1

Does not reflect capital expenditures in the Illinois Basin, acquisitions of proved and unproved oil and gas properties or capitalized interest. Capital expenditures for the acquisition of proved and unproved properties and capitalized interest for the year ended December 31, 2016 totaled approximately $6.7 million and $2.7 million, respectively.

Production, Revenues and Price History

The following table sets forth information regarding condensate, NGL and gas production and revenues from continuing operations for the last three years:

  

 

 

Production and Revenue

For the Years Ended December 31,

($ in thousands)

 

 

 

2016

 

 

2015

 

 

2014

 

Revenue

 

$

139,000

 

 

$

138,707

 

 

$

225,511

 

Condensate Production (Bbls)1

 

 

360,384

 

 

 

402,867

 

 

 

334,944

 

Natural Gas Production (Mcf)

 

 

44,684,571

 

 

 

44,606,753

 

 

 

37,011,177

 

C3+ NGL Production (Bbls)

 

 

1,996,075

 

 

 

2,026,321

 

 

 

1,531,131

 

Ethane (Bbls)

 

 

2,111,321

 

 

 

1,319,582

 

 

 

551,315

 

Total Production (Mcfe)2

 

 

71,491,251

 

 

 

67,099,373

 

 

 

51,515,517

 

Condensate Average Sales Price

 

$

37.08

 

 

$

34.92

 

 

$

74.84

 

Natural Gas Average Sales Price

 

$

1.64

 

 

$

1.86

 

 

$

3.42

 

C3+ NGL Average Sales Price

 

$

17.97

 

 

$

16.18

 

 

$

45.47

 

Ethane Average Sales Price

 

$

7.81

 

 

$

6.60

 

 

$

7.83

 

Average Production Cost per Mcfe3

 

$

1.45

 

 

$

1.39

 

 

$

1.33

 

 

1

Primarily consists of condensate.

2

Condensate and NGLs are converted at the rate of one BOE to six Mcfe.

3

Excludes ad valorem and severance taxes.

Competition

The oil and gas industry is intensely competitive, particularly with respect to the acquisition of prospective oil and natural gas properties and reserves. Our ability to effectively compete is dependent on our geological, geophysical and engineering expertise and our financial resources. We must compete against a substantial number of major and independent oil and natural gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment and services necessary for drilling and completion of wells. Consequently, equipment and services may be in short supply from time to time. Additionally, it can be difficult to attract and retain employees, particularly those with expertise in high demand areas.

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Employees

As of December 31, 2016, we had 104 full-time employees, 12 of whom were field personnel. No employees are represented by a labor union or covered by any collective bargaining arrangement. We believe that our relations with our employees are good. We regularly utilize independent consultants and contractors to perform various professional services, particularly in the areas of drilling, completion, field services, oil and gas leasing and on-site production operation services.

Marketing and Customers

Our natural gas producing properties are located near existing pipeline systems and processing infrastructure. We have firm commitments for the sale of approximately 110,000 gross MMBTU per day in our Butler County, Pennsylvania operating area for our working interest and that of our working interest partners as of December 31, 2016. Additionally in Butler County, Pennsylvania, we have firm processing commitments with unaffiliated third parties for our liquids-rich gas totaling 285,000 gross MMBTU per day as of December 31, 2016. In Ohio, we have a marketing agreement in place with BP Energy for 14,000 MMBtu per day. In addition to our marketing and processing agreements, we have several transportation agreements in the Appalachian Basin totaling commitments of approximately 260,000 gross MMBTU per day in 2017; 263,000 gross MMBTU per day in 2018; 233,000 gross MMBTU per day in 2019; 198,000 gross MMBTU per day in 2020; and 191,000 gross MMBTU per day in 2021.

In addition to our natural gas transportation and sales agreements, we also have agreements in place to transport and sell our ethane production. We began selling ethane via the ATEX and Mariner West pipelines during 2014. The initial term of the ATEX pipeline agreement expires 15 years from the date that we began to deliver ethane to the ATEX pipeline, with us retaining a unilateral right to extend the initial term for successive periods of not less than one or more than five years so long as the shippers on the ATEX pipeline continue to ship an aggregate of 50,000 barrels per day of ethane. The initial term of the Mariner West pipeline agreement expires on December 31, 2028, but the agreement will automatically extend for successive one year terms thereafter until such time as either party gives 12 months’ notice of intent to terminate. In December 2015, we executed an additional NGL supply agreement INEOS Europe AG for ethane, propane and butane on the Mariner East pipeline. The ethane sales commenced in April 2016 and the propane and butane sales are expected to begin in the first quarter of 2018. The term of the agreement is 10 years and will extend automatically for one year terms thereafter until such time that either party provides twelve months’ notice of intent to terminate.

Prices for oil and natural gas fluctuate widely based on, among other things, supply and demand. Supply and demand are influenced by a number of factors, including weather, foreign policy, industry practices and the U.S. and worldwide economic climate. Oil and natural gas markets have historically been cyclical and volatile in nature as a result of many factors that are beyond our control. There can be no assurance of any price at which we will be able to sell our condensate and natural gas. Prices may be relatively low when our wells are most productive, thereby reducing overall returns.

We enter into derivative transactions with unaffiliated third parties to achieve more predictable cash flows and to reduce our exposure to short-term fluctuations in oil and gas prices. For a more detailed discussion, see the information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

Governmental Regulations

Our oil and natural gas exploration, production, and related operations are subject to extensive statutory and regulatory oversight by federal, state, tribal and local authorities. We must, for example, obtain drilling permits, post bonds for drilling, operating, and reclamation, and submit various reports. The following activities are also subject to regulation: the location of wells, the method of drilling, completion and operating wells, secondary and enhanced oil recovery projects, notice to surface owners and third parties, the surface development, use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, temporary storage tank operations, air emissions from flaring, compression and access roads, the impoundment of water, the manner and extent of earth disturbances, air emissions, sour gas management, the disposal of fluids used in connection with operations, and the calculation and distribution of royalty payments and production taxes. We must also comply with statutes and regulations addressing conservation matters, including the size of drilling and spacing units, or proration units, the number of wells that may be drilled in an area, the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production. Failure to comply with any of these requirements can result in substantial monetary penalties or lease cancellation, and in certain cases, criminal prosecution. Finally, in the past tribal and local authorities have imposed moratoria or other restrictions on exploration and production activities that must be addressed before those activities can proceed. Moreover most states impose a production, ad valorem or severance tax with respect to production and sale of oil or natural gas within its jurisdiction.

The increasing regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our production rates. However, these burdens generally do not affect us differently or to any greater or lesser extent than

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they affect others in our industry with similar types, quantities and locations of production. Additional proposals or proceedings that affect the oil and natural gas industry are regularly considered by Congress, the states, the Federal Energy Regulatory Commission (“FERC”), and the courts. Implementation of such proposals could increase the regulatory burden and potential for financial sanctions for non-compliance. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. We may be required to make significant expenditures to comply with governmental laws and regulations, which could have a material adverse effect on our business, financial condition and results of operations.

Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 (“NGPA”), and the regulations promulgated thereunder by the FERC. In the past, the federal government has regulated the prices at which oil and gas could be sold. Deregulation of wellhead sales in the natural gas industry began with the enactment of the NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted, removing both price and non-price controls from natural gas sold in “first sales” no later than January 1, 1993. While sales by producers of natural gas, and all sales of crude oil, condensate and natural gas liquids currently can be made at uncontrolled market prices, Congress could reenact price controls in the future.

The FERC regulates interstate natural gas transportation rates and service conditions. Its regulations affect the marketing of natural gas produced by us, as well as the revenues that may be received by us for sales of such production. Since the mid-1980s, the FERC has issued a series of orders (collectively, “Order 636”) which significantly altered the marketing and transportation of natural gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other services such pipelines previously performed. One of the FERC’s purposes in issuing Order 636 was to increase competition within the natural gas industry. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines’ traditional role as wholesalers of natural gas in favor of providing only storage and transportation services, and has substantially increased competition and volatility in natural gas markets.

The price we receive from the sale of oil and NGLs will be affected by the cost of transporting products to markets. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, index such rates to inflation, subject to certain conditions and limitations. We are unable to predict the effect, if any, of these regulations on our intended operations. The regulations may, however, increase transportation costs or reduce well head prices for oil and NGLs.

In August 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other matters, the EPAct 2005 amends the Natural Gas Act (“NGA”), to make it unlawful for “any entity,” including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit any such statement necessary to make the statements not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The EPAct 2005 also gives the FERC authority to impose civil penalties for violations of the NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sale or gathering, but does apply to activities or otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to the FERC’s jurisdiction which includes the reporting requirements under Order Nos. 704 and 720. It therefore reflects a significant expansion of the FERC’s enforcement authority. We have not been affected differently than any other producer of natural gas by this act.

Environmental Matters

Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection and the discharge of materials into the environment. These laws and regulations:

 

require the acquisition of permits or other authorizations before construction, drilling and certain other of our activities;

 

limit or prohibit construction, drilling and other activities on specified lands within wetlands, endangered species habitat, wilderness and other protected areas;

 

impose substantial liabilities for pollution that may result from our operations;

 

require the installation of pollution control equipment in connection with operations;

 

place restrictions or regulations upon the use or disposal of the material utilized in our operations;

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restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

 

require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells; and

 

require the expenditure of significant amounts in connection with worker health and safety.

The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce environmental laws and regulations, and violations may result in administrative or civil penalties, injunctions or even criminal penalties. Some states continue to adopt new regulations and permit requirements, which may impede or delay our operations or increase our costs. We believe that we are in substantial compliance with current applicable environmental laws and regulations, and, except for those matters described in “Item 3. Legal Proceedings,” have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, the trend in environmental legislation and regulation generally is toward stricter standards, and we expect that this trend will continue. Changes in existing environmental laws and regulations or in interpretations of these laws and regulations could have a significant impact on us, as well as the oil and natural gas industry as a whole.

The following is a summary of the existing laws and regulations that we believe are most likely to have a material impact on our business operations.

The Resource Conservation and Recovery Act, as amended (“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 federal Environmental Protection Agency, or 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 waters and most of the other wastes associated with the exploration and production of crude oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial condition.

The Comprehensive Environmental, Response, Compensation, and Liability Act, as amended (“CERCLA”), and comparable state statutes impose strict liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at these sites. The definition of “hazardous substances” excludes “petroleum, including crude oil and any fraction thereof.” Nevertheless, non-excluded hazardous substances can be present at sites of oil and gas operations. Liability under CERCLA may be joint and several and includes liability for the costs of 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 release of hazardous substances or other pollutants into the environment.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production, and produced water disposal operations for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been disposed of or released on or under the properties that we own or lease, or on or under other locations, including off-site locations, where these substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial activities to prevent future contamination.

The federal Water Pollution Control Act (the “Clean Water Act”), and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The Environmental Protection Agency (“EPA”) and delegated states have adopted regulations concerning the discharge of storm water runoff. These regulations require covered facilities to obtain individual permits or to seek coverage under a general permit. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the unpermitted discharge of fill material into waters of the United States, including certain wetlands. 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.

Our oil and natural gas exploration and production operations generate produced water as a waste material, which is subject to the disposal requirements of the Clean Water Act, the Safe Drinking Water Act (“SDWA”), or an equivalent state regulatory program.

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This produced water is disposed of by re-injection into the subsurface through disposal wells, treatment and discharge to the surface or in evaporation ponds. Whichever disposal method is used, produced water must be disposed of in compliance with permits issued by regulatory agencies, and in compliance with applicable environmental regulations. This water can sometimes be disposed of by discharging it under discharge permits issued pursuant to the Clean Water Act or an equivalent state program. Another common method of produced water disposal is subsurface injection in disposal wells. Such disposal wells are permitted under the Underground Injection Control program, (“UIC”), which is a program promulgated under the SDWA. The EPA directly administers the UIC in some states and in others it is delegated to the states. To date, we believe that all necessary surface discharge or disposal well permits have been obtained and that the produced water has been discharged into the produced water disposal wells in substantial compliance with such obtained permits and applicable laws and regulations.

The federal Clean Air Act, and comparable state laws, regulates emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. In April 2012, the EPA issued a final rule under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPs, programs. The rule establishes the NSPS for certain wells, storage vessels, pneumatic controllers, compressors, and natural gas processing plants and revises the NESHAP for glycol dehydration units. This rule also requires all new hydraulically fractured wells and wells that are refractured to reduce emissions of Volatile Organic Compounds through “green completions.”  More recently, in May 2016, the EPA finalized a suite of regulations that set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Clean Air Act and associated state laws and regulations.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly reporting, waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. For example, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. While the U.S. Congress has, from time to time, considered climate change-related legislation to reduce greenhouse gas emissions, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal legislation, a number of states have passed laws, adopted regulations or undertaken regulatory initiatives to reduce the emission of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although it is not possible at this time to predict whether or when the U.S. Congress may act on climate change legislation or how federal legislation may be reconciled with state and regional requirements, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the oil, natural gas and NGLs that we produce.

In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gas emissions may be regulated as an “air pollutant” under the federal Clean Air Act. In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes, the EPA adopted regulations that restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. The EPA has issued regulations that, among other things, require a reduction in emissions of greenhouse gases from motor vehicles and that impose greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, in September 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States beginning in 2011 for emissions occurring in 2010. In November 2010 the EPA expanded its greenhouse reporting rule to include onshore petroleum and natural gas production, processing, transmission, storage, and distribution facilities. Under these rules, reporting of greenhouse gas emissions from such facilities is required on an annual basis, and the first reports became due in September 2012 for emissions occurring in 2011.

In addition to federal laws and regulations, the various states where we operate have enacted their own environmental laws and regulations. As an example, in 2012, Pennsylvania enacted Act 13 (“Act 13”), which represented the first comprehensive legislation regarding the development of the Marcellus Shale in Pennsylvania.  Act 13, among other things, (i) enacted stronger environmental standards, (ii) established impact fees, which are set based on a multi-year fee schedule and the average sales price of natural gas, (iii) increased the notice distance for unconventional well permit applications, (iv) extended the setback distance for unconventional wells and (v) increased the distance and duration of presumed liability for water pollution.  In addition, Act 13 imposed spill prevention requirements applicable to well site construction, wastewater transportation, and gathering lines.

Act 13 has been the subject of multiple challenges in Pennsylvania courts.  In 2013, the Pennsylvania Supreme Court invalidated the portions of Act 13 providing for statewide zoning and state waivers of the setback requirements in Pennsylvania's Oil and Gas Act.  In 2014, a Pennsylvania Commonwealth Court invalidated Act 13’s provisions allowing the commonwealth to review local drilling rules. These court decisions have the effect of giving local communities in Pennsylvania more authority to regulate oil and gas operations, which could make it more difficult to develop Marcellus Shale acreage in some municipalities.  We cannot predict

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whether the remaining portions of Act 13 will be amended or replaced, or how or to what extent any additional rules or regulations adopted under Act 13 will affect our operations in Pennsylvania.  

Furthermore, Pennsylvania has finalized new rules for surface operations at oil and gas sites that, among other things, would increase public participation in the permitting process, increase mitigation obligations and require surveys for abandoned wells.  In October 2016, the Pennsylvania Department of Environmental Protection issued final rules amending Pennsylvania Code Chapter 78a, revising requirements for surface activities related to unconventional oil and gas operations.  The final rules increase requirements for permitting, waste handling, water management and restoration, surface reclamation and requirements related to abandoned and orphaned wells.  In November 2016, a Pennsylvania state court issued an opinion requiring the enforcement of certain portions of the new rules while the court considers legal challenges to the rules brought by an industry group.  These regulations may increase operating costs or cause unanticipated delays.

Although it is not possible at this time to predict whether proposed federal or state legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions or other environmental matters could have a material adverse effect on our business, financial condition and results of operation. In addition, these developments could curtail the demand for fossil fuels such as oil and gas in areas of the world where our customers operate and thus adversely affect demand for our products and services, which may in turn adversely affect our future results of operations.

Available Information

We maintain an internet website under the name “www.rexenergy.com.” 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 practicable after providing such reports to the Securities and Exchange Commission (“SEC”). Our Corporate Governance Guidelines, the charters of the Audit Committee, the Compensation Committee and the Nominating and Governance Committee, and the Code of Business Conduct and Ethics for directors, officers, employees and financial officers are also available on our website and in print to any stockholder who provides a written request to the Corporate Secretary at 366 Walker Drive, State College, PA 16801. Information contained on or connected to our website is not incorporated by reference into this report and should not be considered part of this report or any other filing that we make with the SEC.

We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934, as amended. 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, N.E., Washington, D.C. 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 Rex Energy Corporation, that file electronically with the SEC. The public can obtain any document we file with the SEC at www.sec.gov.

 

 

 

 

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ITEM 1A.

RISK FACTORS

In evaluating our company, the risk factors described below should be considered carefully. The occurrence of one or more of these events could significantly and adversely affect our business, prospects, financial condition, results of operations and cash flows. 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 to be immaterial may also materially adversely affect our business, financial condition and results of operations. This Annual Report on Form 10-K also contains forward-looking statements, estimates and projections that involve risks and uncertainties.  Our actual results could differ materially from those anticipated in the forward-looking statements as a result of various factors, including the risks described below

Risks Related to Our Company

Oil, NGL and natural gas prices have been volatile and are currently depressed. If commodity prices remain depressed for a lengthy period of time or experience a further substantial or extended decline, our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments could be materially and adversely affected.

The prices we receive for our condensate, NGL and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include, but are not limited to, the following:

 

changes in global supply and demand for oil, NGLs and natural gas;

 

the condition of the U.S. and global economy impacting the global supply and demand for oil, NGLs and natural gas;

 

the actions of certain foreign states;

 

the price and quantity of imports of foreign oil and natural gas;

 

political conditions in oil, NGL and natural gas producing countries globally, including embargoes, terrorist attacks, threats and escalation of military activity in response to such attacks or acts of war;

 

the level of global oil and natural gas exploration and production activity;

 

the level of global oil and natural gas inventories;

 

production or pricing decisions made by the Organization of Petroleum Exporting Countries and other state-controlled oil companies;

 

weather conditions and the occurrence of natural disasters;

 

availability of limited refining facilities in the Illinois Basin reducing competition and resulting in lower regional oil prices than in other U.S. oil producing regions and other factors that result in differentials to benchmark prices;

 

technological advances affecting energy consumption;

 

effect of energy conservation efforts; and

 

the price and availability of alternative fuels.

Furthermore, oil and natural gas prices continued to be volatile in 2016. For example, the WTI oil spot price in 2016 ranged from a high of $54.01 to a low of $26.19 per Bbl and Henry Hub natural gas spot prices in 2016 ranged from a high of $3.80 to a low of $1.49 per MMBtu.

Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. For example, due to the significant decrease in commodity prices over the latter half of 2014 and the duration of 2015 and 2016, our capital expenditures budget for 2017 is considerably smaller than our actual capital expenditures for 2016.  The amount we will be able to borrow under our revolving credit facility is subject to periodic redetermination based in part on current oil and natural gas prices and on changing expectations of future prices.

Lower oil, NGL and natural gas prices may not only decrease our revenues on a per-unit basis, but also may reduce the amount of oil, NGLs and natural gas that we can produce economically. The higher operating costs associated with many of our oil fields will make our profitability more sensitive to oil price declines. A sustained decline in oil, NGL or natural gas prices, or a further increase

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in our negative differentials, may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We have substantial indebtedness and may incur substantially more debt, which could exacerbate the risks associated with our indebtedness.

As of December 31, 2016, we had approximately $723.0 million of debt outstanding, including $601.2 million related to our senior notes, $117.7 million outstanding on our revolving credit facility and $4.1 million related to other obligations. We and our subsidiaries may be able to incur substantial additional indebtedness in the future, including under our revolving credit facility. At December 31, 2016, our $400.0 million revolving credit facility had a borrowing base of $190.0 million for secured borrowings, subject to periodic borrowing base redeterminations. Effective as of January 11, 2017, we entered into an amendment to our revolving credit facility pursuant to which the borrowing base was maintained at $190.0 million for secured borrowings following our sale of assets in our Warrior South Area (located in Guernsey, Noble and Belmont Counties, OH). The next borrowing base redetermination is scheduled to occur in April 2017. No assurances can be given that our borrowing base will not be lowered upon our next periodic redetermination or any redetermination thereafter. For additional information, see Note 26, Subsequent Events, to our Consolidated Financial Statements.

As a result of our indebtedness, we will need to use a portion of our cash flow to pay interest, which will reduce the amount we will have available to fund our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our revolving credit facility is at a variable interest rate, so a rise in interest rates will generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges. Our aggregate interest expense also will increase when the interest rate applicable to our outstanding senior secured second lien notes increases from 1.00% per annum to 8.00% per annum commencing on October 1, 2017 in accordance with the terms of those notes. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

We may incur substantially more debt in the future. The indentures governing our senior notes contain restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness as that term is defined in the respective indentures.

Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or issue additional equity on terms that we may not find attractive, if it may be done at all. While we have been able to obtain waivers from our lenders in connection with past failures to comply with the current ratio financial covenant in our revolving credit facility, there can be no assurance that we will be able to do so in connection with any future failures to comply with financial covenants in our revolving credit facility. Further, any failure by us to comply with the financial and other restrictive covenants relating to our indebtedness, or to obtain a related waiver from our lenders, could result in a default or event of default under that indebtedness, which could trigger the acceleration of a significant portion of our indebtedness and adversely affect our business, financial condition and results of operations.

Commodity prices have declined substantially from historic highs and may remain depressed for the foreseeable future. If commodity prices continue to remain depressed, we may be required to take additional write-downs of the carrying values of our oil and natural gas properties, some of our undeveloped locations may no longer be economically viable, the value of our estimated proved reserves could be reduced materially, we may need to sell assets or raise capital and we may not be able to pay our expenses or service our indebtedness.

 

During the eight years prior to December 31, 2016, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.49 per MMBtu in 2016. On December 31, 2016, the Henry Hub spot market price of natural gas was $3.71 per MMBtu. The reduction in prices has been caused by many factors, including increases in natural gas production and reserves from unconventional (shale) reservoirs, without an offsetting increase in demand.

 

In addition, oil prices have declined significantly since the second half of 2014. The price of WTI crude oil was $53.75 per barrel on December 31, 2016, which is a significant decline from $106.70 per barrel on June 30, 2014. This environment could cause the commodity prices for oil and natural gas to remain at currently depressed levels or to fall to lower levels.

 

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There is a risk that we will be required to write down the carrying value of our oil and gas properties. We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings.

 

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

 

We review our oil and gas properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the book values associated with oil and gas properties.

 

During 2016, we recorded impairment expense of $74.6 million. Additional write-downs could occur if oil and gas prices continue to decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results, absent other mitigating circumstances. The risk we will be required to write-down the carrying value of our properties increases when oil and gas prices are low or volatile. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. This could have a material adverse effect on our results of operations for the periods in which such charges are taken.

 

In addition, we may be required to sell assets or raise capital by issuing additional debt (including additional priority lien debt) or equity in order pay expenses and service indebtedness. Furthermore, the value of our assets, if sold, may not be sufficient to pay our expenses or service our indebtedness. On January 20, 2016, we suspended payment of our quarterly dividend on shares of our 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001per share (the “Series A Preferred Stock”).

Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil and natural gas reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the exploration for, and development, production and acquisition of, oil and natural gas reserves. To date, we have financed capital expenditures primarily with proceeds from bank borrowings, cash generated by operations, public stock offerings, high-yield bond offerings, sales of non-core assets and joint venture agreements.

We intend to finance our future capital expenditures with proceeds from bank borrowings, the sale of debt or equity securities, asset sales, cash flow from operations and current and new financing arrangements, such as joint ventures; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional equity securities could have a dilutive effect on the value of our common stock, and in some cases, a substantial dilutive effect. Additional borrowings under our credit facility or the issuance of additional debt securities will require that a greater portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. Our borrowing base is subject to scheduled redeterminations semi-annually, and may also be redetermined more often at the discretion of our lenders. Lower oil and natural gas prices may result in a reduction in our borrowing base at the next redetermination. A reduction in our borrowing base could require us immediately to repay any outstanding indebtedness under our revolving credit facility in excess of the borrowing base. In addition, our credit facility imposes certain limitations on our ability to incur additional indebtedness other than indebtedness under our credit facility. If we desire to issue additional debt securities other than as expressly permitted under our credit facility, we will be required to seek the

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consent of the lenders in accordance with the requirements of the credit facility, which consent may be withheld by the lenders at their discretion. If we incur certain additional indebtedness, our borrowing base under our credit facility may be reduced. Also, our revolving credit contains covenants that restrict our ability to, among other things, materially change our business, approve and distribute dividends, enter into transactions with affiliates, create or acquire additional subsidiaries, incur indebtedness, sell assets, make loans to others, make investments, enter into mergers, incur liens, and enter into agreements regarding swap and other derivative transactions.

Our cash on hand, cash flow from operations, ability to borrow funds and access to capital is subject to a number of variables, many of which are beyond our control, including:

 

our estimated proved oil, NGL and natural gas reserves;

 

the level of oil and natural gas we are able to produce from existing wells;

 

our ability to extract NGLs from the natural gas we produce;

 

the prices at which oil, NGLs and natural gas are sold;

 

our ability to acquire, locate and produce new reserves; and

 

prevailing economic and capital markets conditions, especially for oil and gas companies.

If our revenues decrease as a result of lower oil, NGL and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. We may need to seek additional financing in the future. In addition, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. The failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil and natural gas reserves.

We are subject to various contractual limitations that may restrict our business and financing activities.

Our revolving credit facility, the indentures governing our outstanding senior notes and the certificate of designations governing our Series A Preferred Stock contain, and any future indebtedness we incur will likely contain, a number of restrictive covenants and limitations 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;

 

pay distributions on, redeem or repurchase our common stock and, under certain circumstances, our Series A Preferred Stock, or redeem or repurchase our subordinated debt;

 

make investments or loans;

 

incur or guarantee additional indebtedness or issue preferred stock that is senior to our Series A Preferred Stock as to dividends or rights upon liquidation, winding up or dissolution;

 

create or incur certain liens;

 

make certain acquisitions and investments;

 

redeem or prepay other debt;

 

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

 

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

 

engage in transactions with affiliates.

Additionally, if dividends on our Series A Preferred Stock are in arrears and unpaid for six or more quarterly periods, the holders (voting as a single class) of our outstanding Series A Preferred Stock will be entitled to elect two additional directors to our Board of Directors until paid in full.

As a result of these covenants and restrictions, 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.

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Our ability to comply with some of these covenants and restrictions may be affected by events beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants and restrictions may be impaired. A failure to comply with the covenants, ratios or tests in our revolving credit facility, the indentures governing our senior notes or any future indebtedness could result in an event of default under our revolving credit facility, the indentures governing our senior notes or our future indebtedness, 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 thereunder:

 

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.

A payment default or an acceleration under our revolving credit facility could result in an event of default and an acceleration under the indentures for our senior notes.

If the indebtedness under the Senior Notes were to be accelerated, there can be no assurance that we would have, or be able to obtain, sufficient funds to repay such indebtedness in full. In addition, our obligations under our revolving credit facility are collateralized by perfected first priority liens and security interests on substantially all of our assets and if we are unable to repay our indebtedness under the revolving credit facility, the lenders could seek to foreclose on our assets.

The value of our proved reserves as of December 31, 2016, calculated using SEC pricing, may be different than the fair market value of our proved reserves calculated using current market prices.

 

Our estimated proved reserves as of December 31, 2016, Standardized Measure and related PV-10 and were calculated under SEC rules using twelve-month trailing average benchmark prices of $39.25 per barrel of oil (WTI) and $2.481 per MMBtu (Henry Hub spot). The spot prices for oil and natural gas on February 27, 2017, were $54.04 per barrel of oil and $2.481 per MMBtu, respectively, higher than the benchmark prices referenced above. Using these more recent prices in estimating our proved reserves, without giving effect to any acquisitions or development activities we have executed in 2017, would likely result in an increase in proved reserve volumes. If spot prices on February 27, 2017 had been lower than the twelve-month trailing average benchmark prices used to calculate SEC estimated proved reserves, Standardized Measure and related PV-10, then estimates based on the lower spot prices would have resulted in a reduction in proved reserves volumes.  As these illustrations demonstrate, volatility in pricing can have a significant impact on the Standardized Measure and PV-10 of our proved reserves.

Although we have hedged a portion of our estimated 2017 production, our hedging program may be inadequate to protect us against continuing and prolonged declines in the price of oil and natural gas.

 

We have over 65.0% of our 2016 condensate production hedged through 2017, over 75.0% of our 2016 natural gas production hedged through 2017 and over 50.0% of our 2016 NGL production hedged through 2017. Including the effects of derivatives added since December 31, 2016, of our 2016 natural gas production over 80.0% is hedged through 2017 and over 60.0% of our 2016 NGL production hedged through 2017. In addition, we have basis swaps in place for 14.7 Bcf at an average differential to Henry Hub New York Mercantile Exchange (“NYMEX”) of $0.86 per Mcf through 2017.  These hedges may be inadequate to protect us from continuing and prolonged decline in the price of oil and natural gas. To the extent that the price of oil and natural gas remain at current levels or declines further, 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.

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Drilling for and producing oil, NGLs and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations.

Our future success will depend on the success of our exploitation, exploration, development and production activities. Our oil, NGL and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil, NGL or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. Please see below for a discussion of the uncertainties involved in these processes. Our costs of drilling, completing and operating wells are often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures could be materially and adversely affected by any factor that may curtail, delay or cancel drilling, including the following:

 

delays imposed by or resulting from compliance with regulatory requirements;

 

unusual or unexpected geological formations;

 

pressure or irregularities in geological formations;

 

shortages of or delays in obtaining equipment and qualified personnel;

 

equipment malfunctions, failures or accidents;

 

unexpected operational events and drilling conditions;

 

pipe or cement failures;

 

casing collapses;

 

lost or damaged oilfield drilling and service tools;

 

loss of drilling fluid circulation;

 

uncontrollable flows of oil, natural gas and fluids;

 

fires and natural disasters;

 

environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures, discharges of toxic gases or mishandling of fluids (including frac fluids) and underground migration issues;

 

adverse weather conditions;

 

reductions in oil and natural gas prices;

 

oil and natural gas property title problems; and

 

market limitations for oil and natural gas.

If any of these factors were to occur with respect to a particular field, we could lose all or a part of our investment in the field, or we could fail to realize the expected benefits from the field, either of which could materially and adversely affect our revenue and profitability.

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

A substantial portion of our production is sold to purchasers at prices that reflect a discount to other relevant benchmark prices, such as WTI NYMEX. 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.

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Our results of operations and cash flow may be adversely affected by risks associated with our oil, NGL and gas financial derivative activities, and our oil, NGL and gas financial derivative activities may limit potential gains.

We have entered into, and we expect to enter into in the future, oil and gas financial derivative arrangements corresponding to a significant portion of our oil and natural gas production. Many derivative instruments that we employ require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and natural gas prices. We received net payments of $32.6 million related to our commodity derivative instruments for the year ended December 31, 2016.

If our actual production and sales for any period are less than the corresponding volume of derivative contracts for that period (including reductions in production due to operational delays), or if we are unable to perform our activities as planned, we might be forced to satisfy all or a portion of our derivative obligations without the benefit of the cash flow from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. In addition, our oil and gas financial derivative activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a counterparty does not perform its obligations under the applicable derivative arrangement, the arrangement is imperfect or our derivative policies and procedures are not followed or do not work as planned. Under the terms of our revolving credit facility the percentage of our total production volumes with respect to which we will be allowed to enter into derivative contracts is limited, and we therefore retain the risk of a price decrease for our remaining production volume.

The standardized measure and PV-10 of our estimated reserves included in this report should not be considered as the current fair value of the estimated oil and natural gas reserves attributable to our properties.

Standardized Measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Our non-GAAP financial measure, PV-10, is a similar reporting convention that we have disclosed in this report. Both measures require the use of operating and development costs prevailing as of the date of computation. Consequently, they will not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the 10 percent discount factor, which is required by the rules and regulations of the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our company or the oil and natural gas industry in general. Therefore, Standardized Measure or PV-10 included in this report should not be construed as accurate estimates of the current fair value of our proved reserves.

Based on December 31, 2016 reserve estimates, we project that a 10% decline in the price per barrel of oil, price per barrel of NGLs and the price per Mcf of gas from average 2016 prices would reduce our gross revenues, before the effects of derivatives, for the year ending December 31, 2017 by approximately $4.3 million.

Prospects that we decide to drill may not yield oil, NGLs or natural gas in commercially viable quantities.

Our prospects are in various stages of evaluation. There is no way to predict with certainty in advance of drilling and testing whether any particular prospect will yield oil, NGLs or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable, particularly in light of the current economic environment. The use of seismic data and other technologies, and the study of producing fields in the same area, will not enable us to know conclusively before drilling whether oil, NGLs or natural gas will be present or, if present, whether oil, NGLs or natural gas will be present in commercially viable quantities. Moreover, the analogies we draw from available data from other wells, more fully explored prospects or producing fields may not be applicable to our drilling prospects.

We may be required to take additional write-downs of the carrying values of our oil and natural gas properties, potentially triggering earlier-than-anticipated repayments of any outstanding debt obligations and negatively impacting the trading value of our securities.

There is a risk that we will be required to write down the carrying value of our oil and gas properties. We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future

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cash flows, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and may have a material adverse effect on our ability to pay interest on our senior notes.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

We review our oil and gas properties for impairment annually or whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the book values associated with oil and gas properties.

During 2016, we recorded impairment expense of approximately $74.6 million. Additional write downs could occur if oil and gas prices continue to decline or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results, absent other mitigating circumstances. The risk we will be required to write down the carrying value of our properties increases when oil and gas prices are low or volatile. Because our properties currently serve, and will likely continue to serve, as collateral for advances under our existing and future credit facilities, a write-down in the carrying values of our properties could require us to repay debt earlier than we would otherwise be required. This could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Our estimated proved reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.

Estimates of oil and natural gas reserves are inherently imprecise. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves. To prepare our proved reserve estimates, we must project production rates and the timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, NGL and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil, NGL and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of estimated proved reserves to reflect production history, results of exploration and development, prevailing oil, NGL and natural gas prices and other factors, many of which are beyond our control.

The present value of future net cash flows from our estimated proved reserves is not necessarily the same as the current market value of our estimated oil, NGL and natural gas reserves.

We base the estimated discounted future net cash flows from our estimated proved reserves on prices and costs in effect on the day of estimate. However, actual future net cash flows from our oil and natural gas properties also will be affected by factors such as:

 

actual prices we receive for oil and natural gas;

 

actual cost of development and production expenditures;

 

the amount and timing of actual production;

 

supply of and demand for oil and natural gas; and

 

changes in governmental regulations or taxation.

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The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from estimated proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows 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 natural gas industry in general.

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 utilizing 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, the following:

 

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.

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

 

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.  

Our identified drilling locations are scheduled to be drilled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has identified and scheduled drilling locations as an estimate of our future multi-year drilling activities on our existing acreage. All of our drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations is subject to a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, availability of drilling services and equipment, lease expirations, gathering system, marketing and pipeline transportation constraints, oil and natural gas prices, drilling and production costs, drilling results and other factors. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. Pursuant to SEC rules and guidance, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. The SEC rules and guidance may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program.

Unless we replace our oil, NGL and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil, NGLs and natural gas reservoirs generally are characterized by declining production rates that vary depending on reservoir characteristics and other factors. Our future oil, NGL and natural gas reserves and production, and therefore our cash flow and income, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations.

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If we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules, our ability to produce natural gas, NGLs and condensate commercially and in commercial quantities could be impaired.

We use between four and six million gallons of water per well in our well completion operations in the Appalachian Basin. Our inability to locate sufficient amounts of water, or dispose of water after drilling, could adversely impact our operations. Moreover, the adoption and implementation of new environmental regulations could result in restrictions on our ability to conduct certain operations such as hydraulic fracturing or the imposition of new requirements pertaining to the management and disposal of wastes generated by our operations, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas, NGLs and condensate. Furthermore, new environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may also increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could adversely affect our financial condition and results of operations.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and drilling and completion services could adversely affect our ability to execute on a timely basis our exploration and development plans within our budget.

We may, from time to time, encounter difficulty in obtaining, or an increase in the cost of securing, drilling rigs, equipment, services and supplies. In addition, larger producers may be more likely to secure access to such equipment and services by offering more lucrative terms. If we are unable to acquire access to such resources, or can obtain access only at higher prices, our ability to convert our reserves into cash flow could be delayed and the cost of producing those reserves could increase significantly, which would adversely affect our financial condition and results of operations.

Federal, state and local regulation of hydraulic fracturing could result in increased costs and additional restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We commonly use hydraulic fracturing as part of our operations. Increased regulation of hydraulic fracturing may adversely impact our business, financial condition, and results of operations. The SDWA regulates the underground injection of substances through the UIC. The hydraulic fracturing process is typically regulated by state oil and natural gas commissions; however, the EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving the use of diesel under the SDWA’s UIC program. In February 2014, the EPA released an “interpretative memorandum” providing technical recommendations for implementing UIC requirements for hydraulic fracturing activities using diesel fuels. In this guidance document, the EPA expansively defined the term “diesel” to include hydrocarbons such as kerosene that have not typically been considered to be diesel. In addition, legislation has been introduced in prior sessions of Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of chemicals used in the hydraulic fracturing process. Also, many state governments, including Pennsylvania and Ohio, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, well construction, and operational requirements on hydraulic fracturing operations or otherwise seek to temporarily or permanently ban fracturing activities. In addition to state laws, local land use restrictions, such as city ordinances, zoning laws, and traffic regulations may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater. In June 2015, the EPA published draft results of the study, concluding that hydraulic fracturing activities may adversely impact drinking water resources but finding no widespread impacts. Many observers, including the EPA’s Inspector General have criticized the results of the study. In the interim, however, the EPA has utilized existing statutory authority under the SDWA, the Clean Water Act CERCLA and the Clean Air Act to investigate, order actions, and potentially pursue penalties against some oil and natural gas producers where EPA believes their activities may have impacted the air or groundwater. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities. In April 2012, President Obama issued an executive order creating a task force to coordinate federal oversight over domestic natural gas production and hydraulic fracturing. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, have evaluated or are evaluating various aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms.

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To our knowledge, there have been no citations or contamination of potable drinking water arising from our fracturing operations. We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our general liability, excess liability, and pollution insurance policies would cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies.

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell our oil, NGLs, and natural gas (including ethane) and/or receive market prices for our oil, NGLs and natural gas may be adversely affected by pipeline and gathering system capacity constraints.

Market conditions or the unavailability of satisfactory oil, NGL and natural gas transportation arrangements may hinder our access to oil, NGL and natural gas markets or delay our production. The availability of a ready market for our oil, NGL and natural gas production depends on a number of factors, including the demand for and supply of oil, NGLs and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil, NGLs or natural gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production.

If drilling in the Marcellus Shale and other areas of the Appalachian Basin continues to be successful, the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for these areas may not occur. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those quoted on NYMEX or than we currently project, which would adversely affect our results of operations.

A portion of our natural gas, NGL and oil production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

We cannot control activities on properties that we do not operate and are unable to control their proper operation and profitability.

We do not operate all of the properties in which we own an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operations of these properties. The failure of an operator of our wells to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interests could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others therefore depend upon a number of factors outside of our control, including the operator’s:

 

nature and timing of drilling and operational activities;

 

timing and amount of capital expenditures;

 

expertise and financial resources;

 

the approval of other participants in drilling wells; and

 

selection of suitable technology.

All of the value of our production and reserves is concentrated in the Appalachian Basin. Because of this concentration, any production problems or changes in assumptions affecting our proved reserve estimates or other risks related to this area could have a material adverse impact to our business.

For the year ended December 31, 2016, 100.0% of our estimated proved reserves and net production came from the Appalachian Basin. If mechanical problems, weather conditions or other events impacting the region were to curtail a substantial portion of the production in the Appalachian Basin or otherwise adversely impact regional processing, transportation, governmental regulation or labor matters, our results of operation would be adversely affected. Also, if ultimate production associated with our properties in the Appalachian Basin is less than our estimated reserves, or changes in pricing, cost or recovery assumptions in the area results in a

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downward revision of any estimated reserves in these properties, our business, financial condition and results of operations could be adversely affected.

Competition in the oil, NGL and natural gas industry is intense, which may adversely affect our ability to compete.

We operate in a highly competitive environment for acquiring properties, marketing oil, NGLs and natural gas and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital.

We are a party to several transportation, marketing and processing agreements which commit us to payment obligations over the next five years. We may incur substantial shortfall costs if we are unable to meet our volume commitments or otherwise sell this capacity rights to third parties.

In the normal course of business we enter in to transportation, marketing and processing agreements to ensure future market outlets for our oil, NGLs and natural gas. These agreements commit us to future obligations to be paid regardless of volumes produced. As of December 31, 2016, we were a party to several transportation, marketing and processing agreements which commit us to approximately $227.5 million over the next five years. If we are unable to meet our volume commitments or otherwise convey our capacity rights to third parties we may incur substantial costs associated with these contracts without corresponding oil, NGL and natural gas sales.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil, NGL and natural gas operations, and we may not have enough insurance to cover all of the risks that we face.

We maintain insurance coverage against some, but not all, potential losses to protect against the risks we face. We do not carry business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, it is not possible to insure fully against pollution and environmental risks.

Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition and results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil, NGLs and natural gas, including the possibility of:

 

environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination and soil contamination;

 

abnormally pressured formations;

 

mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses;

 

fires and explosions;

 

personal injuries and death; and

 

natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us. If a significant accident or other event occurs and is not fully covered by insurance, then that accident or other event could adversely affect our financial condition, results of operations and cash flows.

We are subject to complex laws and regulations that can adversely affect the cost, manner or feasibility of doing business.

The exploration, development, production and sale of oil, NGLs and natural gas are subject to extensive federal, state, and local laws and regulations. Such regulation includes requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds) covering drilling and well operations. Other activities subject to regulation are:

 

the location and spacing of wells;

 

the unitization and pooling of properties;

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the method of drilling and completing wells;

 

the surface use and restoration of properties upon which wells are drilled;

 

the plugging and abandoning of wells;

 

the disposal of fluids used or other wastes generated in connection with our drilling operations;

 

the marketing, transportation and reporting of production; and

 

the valuation and payment of royalties.

Under these laws, we could be subject to claims for personal injury or property damages, including natural resource damages, which may result from the impacts of our operations. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs of compliance. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition and results of operations.

We must obtain governmental permits and approvals for our drilling and midstream operations, which can be a costly and time consuming process, which may result in delays and restrictions on our operations.

Regulatory authorities exercise considerable discretion in the timing and scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of natural gas or oil may have on the environment. Further, the public may comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our operations or to do so profitably.

Our operations expose us to substantial costs and liabilities with respect to environmental matters.

Our oil, NGL and natural gas operations are subject to stringent federal, state and local laws and regulations governing the release of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with our drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, including the habitat of threatened and endangered species, and impose substantial liabilities for pollution that may result from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory or remedial obligations or the issuance of injunctions restricting or prohibiting certain activities. Under existing environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether the release resulted from our operations, or whether our operations were in compliance with all applicable laws at the time they were performed.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our competitive position, financial condition and results of operations.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil, NGLs and natural gas that we produce.

In December 2009, the EPA published its findings that emissions of greenhouse gases (“GHGs”) present a danger to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic conditions. Based on these findings, in 2010, the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. The stationary source final rule addresses the permitting of GHG emissions from stationary sources under the Clean Air Act Prevention of Significant Deterioration, or PSD, construction and Title V operating permit programs, pursuant to which these permit programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In June 2014, the United States Supreme Court, in Utility Air Regulatory Group v. Environmental Protection Agency, struck down the EPA’s “tailoring” rule but affirmed the agency’s authority to regulate

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GHG emissions from facilities already subject to permitting requirements on the basis of their emission of conventional pollutants. In addition, in November 2010, the EPA issued a final rule requiring companies to report certain greenhouse gas emissions from oil and natural gas facilities. In July 2011, the EPA amended the oil and natural gas facility greenhouse gas reporting rule to require reporting. Under this rule, initial reports became due in September 2012. We believe that we are in substantial compliance with these reporting obligations. The EPA has indicated that it will use GHG reporting data in considering whether to initiate further rulemaking to establish GHG emissions limits. Further, in April 2012 the EPA issued final New Source Performance Standards and National Emission Standards for Air Pollutants. This rule requires all new hydraulically-fractured wells to reduce emissions of Volatile Organic Compounds through “green completions.” The rule is designed to reduce GHG emissions during well completions. More recently, in August 2015, the EPA proposed a suite of regulations that would set emission standards for methane, a GHG, for new and modified oil and gas production and natural gas processing and transmission facilities. These regulations were finalized in 2016. Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states already have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from our equipment and operations could require us to incur significant added costs to reduce emissions of GHGs or could adversely affect demand for the oil, natural gas and NGLs we produce. Finally, some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate change that could have significant physical effect, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse effect on our assets and operations.

The adoption of derivatives legislation by Congress and related regulations could have an adverse impact on our ability to use derivative instruments, particularly swaps, to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Act, was enacted in 2010. The Act provides for new statutory and regulatory requirements for derivative transactions, including certain oil and gas hedging transactions involving swaps. In particular, the Act includes a requirement that certain hedging transactions involving swaps be cleared and exchange-traded and a requirement to post cash collateral for non-cleared swap transactions, although, at this time, it is unclear which transactions will ultimately be required to be cleared and exchange-traded or which counterparties will be required to post cash collateral with respect to non-cleared swap transactions. The Act provides for a potential exception from the clearing and exchange-trading requirement for hedging transactions by commercial end-users, a category of non-financial entities in which we may be included. While the Commodity Futures Trading Commission, or CFTC, and other federal agencies have adopted, and continue to adopt, numerous regulations pursuant to the Act, many of the key concepts and defined terms under the Act have not yet been delineated by rules and regulations to be adopted by the CFTC and other applicable regulatory agencies. In February 2017, President Trump signed an executive order directing the Secretary of the Treasury to meet with various agencies that oversee and implement the Act’s regulations to find areas to be amended.  That review is to occur within 120 days, but there is little guidance on what regulations or parts of the Act will be most likely to change, if any. As a consequence, it is difficult to predict the aggregate effect the Act and the regulations promulgated thereunder may have on our hedging activities. Whether we are required to submit our swap transactions for clearing or post cash collateral with respect to such transaction will depend on the final rules and definitions adopted by the CFTC. If we are subject to such requirements, significant liquidity issues could result by reducing our ability to use cash posted as collateral for investment or other corporate purposes. A requirement to post cash collateral could also limit our ability to execute strategic hedges, which would result in increased commodity price uncertainty and volatility in our future cash flows. The Act and related regulations currently also would require us to comply with certain futures and swaps position limits and new recordkeeping and reporting requirements, and also could require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The Act and related regulations could also materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Enactment of a Pennsylvania impact fee and severance tax on natural gas could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in Pennsylvania.

While Pennsylvania has historically not imposed a severance tax (relating to the extraction of natural gas), with a focus on its budget deficit and the increasing exploration of the Marcellus Shale, various legislation has been proposed since 2008. In February 2012, Pennsylvania implemented an impact fee. This law imposes an impact fee on all unconventional wells drilled in the Commonwealth of Pennsylvania in counties that elected to impose the fee. The fee, which changes from year to year, is based on the average annual price of natural gas as determined by the NYMEX price, as reported by the Wall Street Journal for the last trading day of each calendar month. The impact fee is initially imposed for the year after an unconventional well is spudded and is imposed

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annually for 15 years for a horizontal well and 10 years for a vertical well. There can be no assurance that the impact fee will remain as currently structured or that new or additional taxes will not be imposed.

In 2015, 2016 and 2017, the Pennsylvania governor proposed budgets that included proposals for a new 6.5% severance tax in addition to the impact tax.  Although no such proposals have yet been enacted into law, there can be no assurance that we will not be subject to additional severance or similar taxes in the future. Changes to the current impact fee, or the imposition of a new severance tax, could negatively affect our future cash flows and financial condition.

Future economic conditions in the U.S. and global markets may have a material adverse impact on our business and financial condition that we currently cannot predict.

The U.S. and other world economies continue to experience the after-effects of a global recession and credit market crisis. More volatility may occur before a sustainable growth rate is achieved either domestically or globally. Even if such growth rate is achieved, such a rate may be lower than the U.S. and international economies have experienced in the past. Global economic growth drives demand for energy from all sources, including for oil and natural gas. A lower future economic growth rate will result in decreased demand for our crude oil, NGL and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

We depend on a relatively small number of purchasers for a substantial portion of our revenue. The inability of one or more of our purchasers to meet their obligations may adversely affect our financial results.

We derive a significant amount of our revenue from sales to a relatively small number of purchasers. Approximately 78.8% of our commodity sales from continuing operations for the year ended December 31, 2016 were to three customers, BP Energy Company, MarkWest Liberty Midstream Resources, LLC, and Shell Trading (US) Company, with BP Energy Company, our largest single customer, accounting for 45.6%. with the largest single customer accounting for 45.6%. If we were unable to continue to sell our oil, NGLs, or natural gas to these key customers, or to offset any reduction in sales to these customers by additional sales to our other customers, it could adversely affect our financial condition and results of operations. These companies may not provide the same level of our revenue in the future for a variety of reasons, including their lack of funding, a strategic shift on their part in moving to different geographic areas in which we do not operate or our failure to meet their performance criteria. We also are subject to risk from loss resulting from non-performance or non-payment by these significant customers. The loss of all or a significant part of our revenue from our significant customers would adversely affect our financial condition and results of operations.

Our business may suffer if we lose key personnel.

Our operations depend on the continuing efforts of our executive officers and senior management. Our business or prospects could be adversely affected if any of these persons do not continue in their management role with us and we are unable to attract and retain qualified replacements. Additionally, we do not carry key person insurance for any of our executive officers or senior management.

Our future acquisitions may yield revenue or production that varies significantly from our projections.

In pursuing potential acquisition of oil and natural gas properties, we will assess the potential recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact, and their accuracy is inherently uncertain. Our review of a subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations.

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

The administration of President Obama made budget proposals which, if enacted into law by Congress, would potentially have increased and accelerated the payment of U.S. federal income taxes by independent producers of oil and natural gas. Proposals have included, but have not been limited to, repealing the enhanced oil recovery credit, repealing the credit for oil and natural gas produced from marginal wells, repealing the expensing of intangible drilling costs (“IDCs”), repealing the deduction for the cost of qualified tertiary expenses, repealing the exception to the passive loss limitation for working interests in oil and natural gas properties, repealing the percentage depletion allowance, repealing the manufacturing tax deduction for oil and natural gas companies, and increasing the

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amortization period of geological and geophysical expenses. Legislation which would have implemented the proposed changes was introduced but not enacted. It is unclear whether legislation supporting any of the above described proposals, or designed to accomplish similar objectives, will be introduced or, if introduced, would be enacted into law, or, if enacted, how soon resulting changes would become effective. However, the passage of any legislation designed to implement changes in the U.S. federal income tax laws similar to the changes included in the budget proposals offered by the Obama administration could eliminate certain tax deductions currently available with respect to oil and natural gas exploration and development, and any such changes (i) could make it more costly for us to explore for and develop our oil and natural gas resources and (ii) could negatively affect our financial condition and results of operations.

New technologies may cause our current exploration and drilling methods to become obsolete.

The oil and gas industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies. As competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. One or more of the technologies that we currently use or that we may implement in the future may become obsolete. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. If we are unable to maintain technological advancements consistent with industry standards, our operations and financial condition may be adversely affected.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The outcome of litigation in which we have been named as a defendant is unpredictable and an adverse decision in any such matter could have a material adverse effect on our financial position.

We are defendants in a number of litigation matters and are subject to various other claims, demands and investigations. These matters may divert financial and management resources that would otherwise be used to benefit our operations. No assurances can be given that the results of these matters will be favorable to us. An adverse resolution or outcome of any of these lawsuits, claims, demands or investigations could have a negative impact on our financial condition, results of operations and liquidity.

 

We are subject to cyber security risks. A cyber incident could occur and result in information theft, data corruption, operational disruption and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities. For example, we depend on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our technologies, systems, networks, and those of its vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of its business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems and insurance coverage for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We do not maintain specialized insurance for possible liability resulting from a cyberattack on our assets that may shut down all or part of our business.

Risks Related to Our Common Stock

 

Our stock price could be volatile, which could cause you to lose part or all of your investment.

 

The stock market has from time to time experienced significant price and volume fluctuations that may be unrelated to the operating performance of particular companies. In particular, the market price of our common stock, like that of the securities of other energy companies, has been and may continue to be highly volatile. During 2016, the sales price of our stock ranged from a low of

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$0.23 per share (on November 15, 2016) to a high of $2.43 per share (on March 7, 2016). Factors such as announcements concerning changes in prices of oil and natural gas, the success of our acquisition, exploration and development activities, the availability of capital, and economic and other external factors, as well as period-to-period fluctuations and our financial results, may have a significant effect on the market price of our common stock.

We are no longer eligible to use registration statements on Form S-3, which could impair our ability to raise capital.

 

As a result of our not declaring and paying regular quarterly dividends on our Series A Preferred Stock, as of the date of this report, we are not eligible to use registration statements on Form S-3. As a result, we cannot use registration statements on Form S-3 to register resales of our securities until we have filed an annual report on Form 10-K including audited financial statements covering the period in which the failure to pay preferred dividends is rectified. In addition, we may be limited in our ability to offer and sell securities while utilizing shelf registration statements on Form S-3 if our public float is below $75 million. As a result, we may not be eligible during any 12-month period to use registration statements on Form S-3 for primary offerings of securities having an aggregate market value of more than one-third of our public float, even though we otherwise would regain the ability to use the form for resale registration statements. Any limitations on our ability to use shelf registration statements may harm our ability to raise the capital we need in an efficient manner or on acceptable terms. Under these circumstances, until we are again eligible to use Form S-3, we will be required to use a registration statement on Form S-1 to register securities with the SEC or issue such securities in a private placement, which could increase the cost of raising capital in the event that we do so.

 

We may issue additional common stock in the future, which would dilute our existing stockholders.

In the future we may issue our previously authorized and unissued securities, including shares of our common stock or securities convertible into or exchangeable for our common stock, resulting in the dilution of the ownership interests of our stockholders. We are authorized under our certificate of incorporation to issue up to 200,000,000 shares of common stock and up to 100,000 shares of preferred stock with such designations, preferences, and rights as may be determined by our board of directors. In the future, we may seek stockholder approval to increase our authorized capital. As of March 2, 2017, there were 98,013,126 shares of our common stock issued and outstanding and 3,987 shares of our 6.0% Convertible Preferred Stock, Series A, issued and outstanding.

In the future, we may issue additional shares of our common stock or securities convertible into or exchangeable for our common stock in connection with public offerings, private placements, the hiring of personnel, acquisitions, for capital raising purposes, to pay accrued dividends on our Series A Preferred Stock in accordance with the terms of our Series A Preferred Stock or for other business purposes. Future issuances of our common stock, or the perception that such issuances could occur, could have a material adverse effect on the price of our common stock.

Our certificate of incorporation, bylaws, and Delaware law contain provisions that could make it more difficult for a third party to acquire us without the consent of our board of directors and our Chairman and other executive officers, who collectively beneficially own approximately 7.5% of the outstanding shares of our common stock as of March 2, 2017.

Provisions in our certificate of incorporation and bylaws, as currently in effect, could have the effect of delaying or preventing a change of control of us and changes in our management. These provisions include the following:

 

the ability of our board of directors to issue shares of our common stock and preferred stock without stockholder approval;

 

the ability of our board of directors to make, alter, or repeal our bylaws without further stockholder approval;

 

the requirement for advance notice of director nominations to our board of directors and for proposing other matters to be acted upon at stockholder meetings;

 

requiring that special meetings of stockholders be called only by our Chairman, by a majority of our board of directors, by our Chief Executive Officer or by our President; and

 

allowing our directors, and not our stockholders, to fill vacancies on the board of directors, including vacancies resulting from removal or enlargement of the board of directors.

In addition, we are subject to the provisions of Section 203 of the Delaware General Corporation Law. These provisions may prohibit large stockholders, in particular those owning 15% or more of our outstanding voting stock, from engaging in business combinations, such as mergers or consolidations, with us.

As of March 2, 2017, our board of directors, including Lance T. Shaner, our Chairman, and our other executive officers collectively own approximately 7.5% of the outstanding shares of our common stock.

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The provisions in our certificate of incorporation and bylaws and under Delaware law, and the ownership of our common stock by our Chairman and other executive officers, could discourage potential takeover attempts and could reduce the price that investors might be willing to pay for shares of our common stock.

Because we have no plans to pay dividends on our common stock, stockholders must look solely to appreciation of our common stock to realize a gain on their investments.

We do not anticipate paying any dividends on our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the expansion of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements and investment opportunities. In addition, our revolving credit facility limits the payment of dividends without the prior written consent of the lenders. Accordingly, stockholders must look solely to appreciation of our common stock to realize a gain on their investment. This appreciation may not occur. In addition, the ability of stockholders to realize any appreciation that may occur is subject to the liquidity of our common stock at a given time.

We are able to issue shares of preferred stock with greater rights than our common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from our stockholders. Any preferred stock that is issued may rank ahead of our common stock in terms of dividends, liquidation rights, or voting rights. If we issue additional preferred stock, it may adversely affect the market price of our common stock.

Substantial sales of our common stock could cause our stock price to decline.

If our stockholders sell a substantial number of shares of our common stock, or the public market perceives that our stockholders might sell shares of our common stock, the market price of our common stock could decline significantly. We cannot predict the effect that future sales of our common stock or other equity-related securities by our stockholders would have on the market price of our common stock.

 

If we cannot meet The NASDAQ Capital Market continued listing standards, our common stock may be subject to delisting.

 

Our common stock is currently listed on The NASDAQ Capital Market, where it has been listed since December 2016 after previously being listed on The NASDAQ Global Select Market. NASDAQ’s continued listing standards require, among other things, that the average closing price of our common stock not fall below $1.00 per share over a consecutive thirty trading day period. On June 14, 2016, we received a letter from the Listing Qualifications Department of NASDAQ stating that we were not in compliance with NASDAQ Listing Rule 5450(a)(1) because our common stock failed to maintain a minimum closing bid price of $1.00 for 30 consecutive trading days.  We then had a period of 180 calendar days, or until December 12, 2016, to achieve compliance with the Rule 5450(a)(1).  On December 13, 2016, we announced that NASDAQ approved our continued listing on the Nasdaq Capital Market and granted us an additional 180-day period (until June 12, 2017) in which to regain full compliance with the minimum bid requirement.  In accordance with NASDAQ Listing Rule 5810(c)(3)(A) we need to have the closing price of our common stock at or above $1.00 per share for a minimum of ten consecutive trading days on or prior to June 12, 2017, or NASDAQ may, at its discretion, commence suspension and delisting procedures. Our closing share price on March 2, 2017, was $0.62.

 

Such a delisting could negatively impact us by (i) reducing the liquidity and market price of our common stock; (ii) reducing the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing; (iii) limiting our ability to use a registration statement to offer and sell freely tradable securities, thereby preventing or limiting our access to public capital markets; and (iv) impairing our ability to provide equity incentives to effectively attract, motivate and retain our employees.

 

ITEM 1B.

UNRESOLVED STAFF COMMENTS

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

 

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ITEM 2.

PROPERTIES

The table below summarizes certain data for our core operating areas at December 31, 2016:  

 

Average Daily

Production

(Mcfe per day)

 

 

Total Production

(MMcfe)

 

 

Total Estimated

Proved

Reserves (Bcfe)

 

 

195,331

 

 

 

71,491

 

 

 

647.8

 

 

Segment reporting is not applicable to our exploration and production operations, as we have a single company-wide management team that administers all properties as a whole rather than by discrete operating segments. We track only basic operational data by area. We do not maintain complete separate financial statement information by area. We measure financial performance as a single enterprise and not on an area-by-area basis.

As of December 31, 2016, we owned an interest in approximately 559.0 producing natural gas wells located predominantly in Pennsylvania and Ohio. In addition to our producing wells, we own one gross location with proved developed non-producing reserves totaling 3.6 Bcfe. At December 31, 2016, we had approximately 259,600 gross (193,500 net) acres under lease, of which 83,700 gross (75,600 net) acres were undeveloped. Of our total acreage holdings, we believe that approximately 174,400 gross (147,700 net) acres are prospective for three producing horizons, including the Marcellus, Utica and Burkett. Reserves at December 31, 2016 decreased 32.7 Bcfe, or 4.8%, from 2015 due primarily to the sale of our Illinois Basin assets and the continued depressed commodity price environment.

Capital expenditures in 2016 for drilling and facility development totaled $27.9 million, net of credits from our joint venture partners, which funded the drilling of 20.0 gross (8.4 net) wells. During the year, we placed into service 34.0 gross (16.2 net) wells and had an inventory of 9.0 gross (3.8 net) wells awaiting completion.

Marcellus Shale

As of December 31, 2016, we had interests in approximately 214,600 gross (160,700 net) Marcellus Shale prospective acres in areas of Pennsylvania, and we continue to expand our position by strategically filling in key pieces of acreage to complete drilling units. Our total acreage holdings include approximately 174,400 gross (147,700 net) acres that we believe to be prospective for liquid-rich Marcellus production. During 2016, we drilled, or participated in the drilling of 10.0 gross (4.9 net) Marcellus Shale wells and placed into service 20.0 gross (10.8 net) Marcellus Shale wells. Our estimated proved reserves related to the Marcellus Shale as of December 31, 2016, totaled approximately 496.8 Bcfe, including one proved non-producing locations with estimated proved reserves of 3.6 Bcfe.

We are a party to four joint ventures in Pennsylvania that represent our primary source for Marcellus production. The first joint venture, for which we serve as the operator, in our Butler County, Pennsylvania operating area is with Summit Discovery Resources II, LLC and Sumitomo Corporation (collectively “Sumitomo”). This joint venture covers an area of mutual interest in Butler, Beaver and Lawrence Counties, Pennsylvania. Our working interest in the area of mutual interest is approximately 70.0%. The second joint venture in our Westmoreland, Centre and Clearfield Counties, Pennsylvania project areas is with WPX Energy Production, LLC          (“WPX”), with WPX serving as the operator. Our working interest in this area of mutual interest is approximately 40.0%. The third joint venture covers 32 specifically identified wells in our Butler County, Pennsylvania operated area between us and AL Marcellus Holdings, LLC (“ArcLight”). ArcLight is participating in these wells at a 35.0% non-operated working interest and does not participate in any of the acreage in the area. Upon the attainment of certain return on investment and internal rate of return thresholds, 50.0% of ArcLight’s 35.0% working interest will revert back to us. The fourth joint venture covers 30 specifically identified units in our Butler County, Pennsylvania operated area between us and BSP. BSP is participating in these wells at up to a 65.0% non-operated working interest.

Utica Shale

As of December 31, 2016, we had under lease approximately 219,000 gross (180,100 net) acres that we believe are prospective for the Utica Shale in Ohio and Pennsylvania. In Ohio, our holdings comprise approximately 20,400 gross (17,000 net) acres which we believe to be prospective for liquids-rich production. In Pennsylvania, we estimate that much of our acreage in Butler County is prospective for dry gas Utica Shale production as well as acreage in some other non-core areas of the state. As of December 31, 2016, we estimate Utica Shale acreage holdings in Pennsylvania of approximately 198,300 gross (162,900 net) acres. During 2016, we drilled seven gross (2.5 net) Utica Shale wells and placed into service 13.0 gross (5.1 net) Utica Shale wells. Our estimated proved reserves related to the Utica Shale as of December 31, 2016, totaled approximately 96.1 Bcfe.

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We are a party to two joint ventures in Ohio that represent our primary source for Utica Shale production. The first joint venture, for which we serve as the operator, is with MFC Drilling, Inc. and ABARTA Oil & Gas Co., Inc. and covers an area of mutual interest in Belmont, Guernsey and Noble Counties, Ohio. Our average working interest in these areas is approximately 64%. The second joint venture covers 12 specifically identified units in our Carroll County, Ohio operated area between us and BSP. BSP is participating in these wells at up to a 65.0% working interest. Our average working interest in Carroll County production is approximately 60%.

In January 2017, we sold our interests in 14.0 gross (nine net) wells and 6,300 gross (4,100 net) acres in Belmont, Guernsey and Noble Counties, Ohio, which were part of our joint venture with MFC Drilling, Inc. and ABARTA Oil & Gas Co., Inc., for an expected $29.0 million in net proceeds, subject to customary post-closing adjustments. Our estimated proved reserves related to these properties as of December 31, 2016, totaled approximately 21.6 Bcfe.

Burkett Shale

As of December 31, 2016, we had under lease approximately 174,400 gross (147,700 Net) acres prospective for the liquids-rich Burkett Shale in Pennsylvania. During 2016, we drilled three gross (1.1 net) Burkett Shale wells and placed into service one gross (0.4 net) wells. Our estimated proved reserves related to the Burkett Shale as of December 31, 2016 totaled approximately 41.8 Bcfe.

Estimated Proved Reserves

For estimated proved reserves as of December 31, 2016, proved locations were identified, assessed and justified using the evaluation methods of performance analysis, volumetric analysis and analogy. In addition, reliable technologies were used to support a select number of undeveloped locations in the Marcellus and Utica Shale Regions. Within the Marcellus and Utica Shale Regions, we used both public and proprietary geologic data to establish continuity of the formation and its producing properties. This data included performance data, seismic data, micro-seismic analysis, open hole log information and petro-physical analysis of the log data, mud logs, log cross-sections, gas sample analysis, drill cutting samples, measurements of total organic content, thermal maturity and statistical analysis. In our development area, this data demonstrated consistent and continuous reservoir characteristics.

The following table sets forth our estimated proved reserves as defined in Rule 4.10(a) of Regulation S-X and Item 1200 of Regulation S-K. The information in this table is not intended to represent the current market value of our proved reserves nor does it give any effect to our commodity derivatives or current commodity prices.

 

 

 

Net Reserves

 

Category

 

Condensate (Barrels)

 

 

NGL (Barrels)

 

 

Gas (Mcf)

 

Proved Developed

 

 

1,859,200

 

 

 

44,527,300

 

 

 

365,909,000

 

Proved Developed Non-Producing

 

 

6,700

 

 

 

297,100

 

 

 

1,732,300

 

Proved Undeveloped

 

 

 

 

 

 

 

 

 

Total Proved

 

 

1,865,900

 

 

 

44,824,400

 

 

 

367,641,300

 

 

All of our reserves are located within the continental United States. Reserve estimates are inherently imprecise and remain subject to revisions based on production history, results of additional exploration and development, prices of oil and natural gas and other factors. Please read “Item 1A.—Risk Factors—Risks Relating to Our Company—Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.” You should also read the notes following the table below and our Consolidated Financial Statements for the year ended December 31, 2016 in conjunction with our reserve estimates.

34


 

The following table sets forth our estimated proved reserves at the end of each of the past three years:

 

    

 

 

2016

 

 

2015

 

 

2014

 

Description

 

 

 

 

 

 

 

 

 

 

 

 

Proved Developed Reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil and Condensate (Bbls)

 

 

1,865,900

 

 

 

1,544,000

 

 

 

1,310,000

 

Natural Gas (Mcf)

 

 

367,641,300

 

 

 

389,754,400

 

 

 

365,673,300

 

NGLs (Bbls)

 

 

44,824,400

 

 

 

37,941,900

 

 

 

29,215,000

 

Proved Undeveloped Reserves

 

 

 

 

 

 

 

 

 

 

 

 

Oil and Condensate (Bbls)

 

 

 

 

 

372,500

 

 

 

1,314,900

 

Natural Gas (Mcf)

 

 

 

 

 

16,708,400

 

 

 

473,511,800

 

NGLs (Bbls)

 

 

 

 

 

2,404,700

 

 

 

44,037,500

 

Total Estimated Proved Reserves (Mcfe)1, 2

 

 

647,783,100

 

 

 

660,041,400

 

 

 

1,294,449,500

 

Standardized Measure (millions)3

 

$

165.6

 

 

$

255.6

 

 

$

1,025.4

 

PV-10 Value (millions)3

 

$

175.5

 

 

$

272.7

 

 

$

1,039.4

 

 

1

The estimates of reserves in the table above conform to the guidelines of the SEC. Estimated recoverable proved reserves have been determined without regard to any economic impact that may result from our financial derivative activities. These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry. The reserve information shown is estimated. The certainty of any reserve estimate is a function of the quality of available geological, geophysical, engineering and economic data, the precision of the engineering and geological interpretation and judgment. The estimates of reserves, future cash flows and present value are based on various assumptions, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.  

2

We converted crude oil, condensate and NGLs to Mcf equivalent at a ratio of one barrel to six Mcfe.

3

PV-10, a non-GAAP measure, represents the present value, discounted at 10% per annum of estimated future cash flows of our estimated proved reserves before income tax and asset retirement obligations. The estimated future cash flows set forth above were determined by using reserve quantities of estimated proved reserves and the periods in which they are expected to be developed and produced based on prevailing economic conditions. The estimated future production is priced based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December 2016 of $39.25 per barrel of condensate and $2.481 per Mcfe of natural gas. These prices are adjusted for transportation fees, quality and regional price differentials resulting in $36.68 per barrel of oil, $10.50 per barrel of NGLs and $2.264 per Mcf of natural gas. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. For an explanation of why we show PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flow, please read “Item 6. Selected Financial Data – Non-GAAP Financial Measures.” Please also read “Item 1A. Risk Factors–Risks Related to Our Company–Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any significant inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves.”

Proved Undeveloped Reserves (PUDs)

We did not recognize estimated proved reserves associated with PUD locations as of December 31, 2016. Changes in PUDs that occurred during the year were due to a conversion of 33.4 Bcfe attributable to PUDs into proved developed reserves. Costs incurred relating to the development of seven gross (5.2 net) PUD locations converted to proved developed were approximately $7.2 million in 2016.

The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2016:

 

Proved Undeveloped Reserves (Mcfe)

 

For the Year Ended December 31, 2016

 

Beginning proved undeveloped reserves

 

 

33,371,600

 

Sales of Reserves in Place

 

 

 

Undeveloped reserves converted to developed

 

 

(33,371,600

)

Revisions

 

 

 

Extensions and discoveries

 

 

 

Ending proved undeveloped reserves

 

 

 

 

In our 2015 reserve report, we had seven gross proved undeveloped locations all of which were scheduled for development in 2016. During 2016, all seven of the PUD locations were completed and converted to proved developed producing reserves. This equated to a conversion of 100.0% of our proved undeveloped locations to proved developed producing reserves. The depressed commodity price environment has significantly impacted our development plans, leading to the removal of proved undeveloped locations from the 2016 reserves report. At all times, development plans and changes thereto are based on a comprehensive analysis of what we believe to be the most relevant factors in determining such plans. While we do take into consideration NYMEX strip pricing at year end when scheduling future development, for the December 31, 2016 reserve report, we also evaluated additional factors, including but not limited to, the timing of acreage expirations, the need to hold acreage by production, lease commitments, availability

35


 

and cost of capital, availability of operational resources such as drilling rigs and other services, costs of drilling and related services, infrastructure and takeaway capacity, firm capacity commitments, and overall projected returns. Based on a comprehensive evaluation of these and other relevant factors, we made decisions about initial scheduling and subsequent rescheduling of our development plans. The ultimate objective for every such evaluation and analysis is to align our development and capital expenditures plans to focus on projects that management believes will provide the greatest returns.

The reduction in expected capital expenditures on proved undeveloped locations is largely due to the current commodity price environment and the related impact on the economic viability of our proved undeveloped locations from 2015 and prior years, as described above, in addition to our current drilling program that is focused on holding acreage by production.

Reserve Estimation

The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies.  NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.  Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Steven W. Jansen and Mr. Edward C. Roy III.  Mr. Jansen has been practicing consulting petroleum engineering at NSAI since 2011.  Mr. Jansen is a Licensed Professional Engineer in the State of Texas and has over four years of prior industry experience.  Mr. Roy has been practicing consulting petroleum geology at NSAI since 2008.  Mr. Roy is a Licensed Professional Geoscientist in the State of Texas and has over 10 years of prior industry experience. Both technical principals meet or exceed the qualifications, independence, objectivity and confidentiality requirements set forth in the SPE standards; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our estimated proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process. We provide historical information to NSAI for our properties such as ownership interest; oil and gas production; well test data; commodity prices and operating and development costs. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include documented process workflows, the verification of input data used by NSAI, as well as management review and approval.

All of our reserve estimates are reviewed and approved by our Chief Operating Officer. Our Chief Operating Officer holds a Bachelor of Science degree in Petroleum Engineering from Marietta University, as well as a Masters of Business Administration from the University of Denver. He has more than 30 years of experience, most recently with Noble Energy, managing their Appalachian Basin assets. In addition to his extensive working experience, our Chief Operating Officer has served as a board member for the Marcellus Shale Coalition and the West Virginia Oil and Natural Gas Association.

Acreage and Productive Wells Summary

The following table sets forth, for our continuing operations, our gross and net acreage of developed and undeveloped oil and natural gas leases and our gross and net productive oil and natural gas wells as of December 31, 2016:

 

 

 

Undeveloped Acreage1

 

 

Developed Acreage2

 

 

Total Acreage

 

 

Producing

Gas Wells

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Appalachian Basin

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pennsylvania

 

 

80,161

 

 

 

72,468

 

 

 

158,258

 

 

 

103,324

 

 

 

238,419

 

 

 

175,792

 

 

 

515

 

 

 

187

 

Ohio

 

 

3,538

 

 

 

3,100

 

 

 

17,677

 

 

 

14,655

 

 

 

21,215

 

 

 

17,755

 

 

 

44

 

 

 

32

 

Total

 

 

83,699

 

 

 

75,568

 

 

 

175,935

 

 

 

117,979

 

 

 

259,634

 

 

 

193,547

 

 

 

559

 

 

 

219

 

 

 

(1)

Undeveloped acreage is lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas, regardless of whether such acreage includes estimated proved reserves.

(2)

Developed acreage is the number of acres allocated or assignable to producing wells or wells capable of production.

Substantially all of the undeveloped leases summarized in the preceding table will expire at the end of their respective primary terms unless the existing lease is renewed, we have commenced the necessary operations required by the terms of the lease, or we

36


 

have obtained actual production from acreage subject to the lease, in which event, the lease will remain in effect until the cessation of production.

The following table sets forth, for our continuing operations, the gross and net acres of undeveloped leases that may expire during the periods indicated:

 

 

 

Expiring Acreage

 

 

 

Gross

 

 

Net

 

Year Ending December 31,

 

 

 

 

 

 

 

 

2017

 

 

55,394

 

 

 

44,905

 

2018

 

 

26,671

 

 

 

18,978

 

2019

 

 

13,733

 

 

 

9,113

 

2020

 

 

819

 

 

 

607

 

2021

 

 

1,845

 

 

 

218

 

Thereafter

 

 

382

 

 

 

323

 

Total

 

 

98,844

 

 

 

74,144

 

 

The expiring acreage set forth in the table above accounts for 38.3% of our total net acreage. As of December 31, 2016, we have not assigned any estimated proved reserves to locations which are currently schedule to be drilled after lease expiration. We are continually engaged in a combination of drilling and development and discussions with mineral lessors for lease extensions, renewals, new drilling and development units and new leases to address the expiration of undeveloped acreage that occurs in the normal course of our business.

Drilling Results

The following table summarizes our drilling activity for continuing operations for the past three years. Gross wells reflect the sum of all wells in which we own an interest. Net wells reflect the sum of our working interests in gross wells. All of our drilling activities are conducted on a contract basis by independent drilling contractors. We do not own any drilling equipment.

 

 

 

2016

 

 

2015

 

 

2014

 

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

 

Gross

 

 

Net

 

Development:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Appalachian Basin

 

 

9.0

 

 

 

3.9

 

 

 

22.0

 

 

 

11.3

 

 

 

24.0

 

 

 

16.2

 

Non-Productive

 

 

 

 

 

 

 

 

 

 

 

 

 

 

-

 

 

 

-

 

Total Developmental Wells

 

 

9.0

 

 

 

3.9

 

 

 

22.0

 

 

 

11.3

 

 

 

24.0

 

 

 

16.2

 

Exploratory:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Appalachian Basin

 

 

11.0

 

 

 

4.5

 

 

 

12.0

 

 

 

11.7

 

 

 

27.0

 

 

 

21.4

 

Non-Productive

 

 

 

 

 

 

 

 

2.0

 

 

 

1.0

 

 

 

3.0

 

 

 

2.0

 

Total Exploratory Wells

 

 

11.0

 

 

 

4.5

 

 

 

14.0

 

 

 

12.7

 

 

 

30.0

 

 

 

23.4

 

Total Wells

 

 

20.0

 

 

 

8.4

 

 

 

36.0

 

 

 

24.0

 

 

 

54.0

 

 

 

39.6

 

Success Ratio1

 

 

100.0

%

 

 

100.0

%

 

 

94.4

%

 

 

95.8

%

 

 

94.4

%

 

 

94.9

%

 

1

Success ratio is calculated by dividing the total successful wells drilled divided by the total wells drilled.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, in the case of undeveloped properties, we often conduct a preliminary investigation of record title and related matters at the time of lease acquisition. We conduct more comprehensive mineral title opinion reviews, detailed topographic evaluations and infrastructure investigations before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. Burdens on properties may include:

 

customary royalty interests;

 

liens incident to operating agreements and for current taxes;

 

obligations or duties under applicable laws;

 

development obligations under oil and gas leases;

37


 

 

net profit interests;

 

overriding royalty interests;

 

non-surface occupancy leases; and

 

lessor consents to placement of wells.

 

ITEM 3.

LEGAL PROCEEDINGS

The information set forth in Note 23, Litigation, in the notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” is incorporated herein by reference.

 

ITEM 4.

MINE SAFETY DISCLOSURES

Not applicable.

 

 

 

38


 

PART II

ITEM 5.

MARKET FOR COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is traded on The NASDAQ Capital Market under the symbol “REXX”, where it has traded since December 2016. Our common stock previously traded on The NASDAQ Global Select Market. As of March 2, 2017, there were approximately 161 holders of record of our common stock.

The following table sets forth, for the periods indicated, the range of the daily high and low sale prices for our common stock as reported by NASDAQ.

 

2016

 

High

 

 

Low

 

First Quarter

 

$

2.43

 

 

$

0.49

 

Second Quarter

 

$

1.44

 

 

$

0.54

 

Third Quarter

 

$

0.74

 

 

$

0.45

 

Fourth Quarter

 

$

0.64

 

 

$

0.23

 

 

 

 

 

 

 

 

 

 

2015

 

High

 

 

Low

 

First Quarter

 

$

5.27

 

 

$

2.47

 

Second Quarter

 

$

5.74

 

 

$

3.62

 

Third Quarter

 

$

5.60

 

 

$

1.85

 

Fourth Quarter

 

$

3.34

 

 

$

0.89

 

The closing price of our common stock on March 2, 2017 was $0.62.

Dividends

We have not paid cash dividends on our common stock since our inception in March 2007. We do not anticipate paying any dividends on the shares of our common stock in the foreseeable future. We currently intend to retain all future earnings to finance the development of our business. In addition, the terms of our revolving credit facility and the indentures governing our senior notes generally prohibit the payment of cash dividends to holders of our common stock.

Securities Authorized for Issuance under Equity Compensation Plans

 

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))
(c)

 

Equity compensation plans approved by stockholders

  

 

1,181,100

  

  

$

4.14

  

  

 

2,385,791

  

Equity compensation plans not approved by stockholders

  

 

  

  

$

  

  

 

  

Issuer Purchases of Equity Securities

We do not have a stock repurchase program for our common stock.

39


 

Performance Graph

The following graph presents a comparison of the yearly percentage change in the cumulative total return on our common stock over the period from January 1, 2012 to December 31, 2016, with the cumulative total return of the S&P 500 index and the Dow Jones U.S. Oil and Gas Exploration and Production Index over the same period. The graph assumes that $100 was invested on January 1, 2012 in our common stock at the closing market price at the beginning of this period and in each of the other two indices, and the reinvestment of all dividends, if any. This historic stock price performance is not necessarily indicative of future stock performance.

 

 

 

 

Rex Energy

 

 

DJ U.S. E&P Index

 

 

S&P

 

December 31, 2011

 

$

100

 

 

$

100

 

 

$

100

 

December 31, 2012

 

$

88

 

 

$

105

 

 

$

113

 

December 31, 2013

 

$

134

 

 

$

136

 

 

$

147

 

December 31, 2014

 

$

35

 

 

$

120

 

 

$

164

 

December 31, 2015

 

$

7

 

 

$

90

 

 

$

163

 

December 31, 2016

 

$

3

 

 

$

110

 

 

$

178

 

 

 

*

The performance graph and the information contained in this section is not “soliciting material,” is being “furnished,” not “filed” with the SEC and is not to be incorporated by reference into 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 contained in such filing.

 

40


 

ITEM 6.

SELECTED FINANCIAL DATA

Summary Financial Data

The following table shows selected consolidated financial data of Rex Energy Corporation. The historical consolidated financial data has been prepared for Rex Energy Corporation for the years ended December 31, 2016, 2015, 2014, 2013 and 2012. The historical consolidated financial statements for all years presented are derived from the historical audited financial data of Rex Energy Corporation. All material intercompany balances and transactions have been eliminated. This information should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and our Consolidated Financial Statements and related notes as of December 31, 2016 and 2015 and for each of the years ended December 31, 2016, 2015 and 2014, included elsewhere in this report. These selected combined historical financial results may not be indicative of our future financial or operating results.

41


 

The following tables include the non-GAAP financial measure of EBITDAX. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures.”

 

 

 

Rex Energy Corporation Consolidated

 

 

 

Year Ended December 31,

($ in Thousands, Except per Share Data)

 

 

 

2016

 

 

2015

 

 

2014

 

 

2013

 

 

2012

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating Revenue:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas, NGL and Condensate Sales

 

$

139,000

 

 

$

138,707

 

 

$

225,511

 

 

$

139,542

 

 

$

69,260

 

Other Revenue

 

 

17

 

 

 

42

 

 

 

118

 

 

 

200

 

 

 

218

 

Total Operating Revenue

 

 

139,017

 

 

 

138,749

 

 

 

225,629

 

 

 

139,742

 

 

 

69,478

 

Operating Expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and Lease Operating Expense