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, 2015
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 Global Select Market |
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
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 x
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 x 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 x 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. x
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 |
| x |
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| |||
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 x
The aggregate market value of the voting and non-voting common equity held by non-affiliates as of June 30, 2015 was $223,365,718. This amount is based on the closing price of the registrant’s common stock on the NASDAQ Global Select Market 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.
56,952,196 common shares, $.001 par value, were outstanding on March 11, 2016.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement for its 2016 Annual Meeting of Stockholders to be held in May 2016, are incorporated by reference herein in Items 10, 11, 12, 13 and 14 of Part III of this report.
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2015
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”). 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.
2
PART I |
| ||
Item 1. |
| 6 | |
Item 1A. |
| 16 | |
Item 1B. |
| 33 | |
Item 2. |
| 33 | |
Item 3. |
| 40 | |
Item 4. |
| 40 | |
PART II |
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Item 5. |
| 41 | |
Item 6. |
| 43 | |
Item 7. |
| Management’s Discussion and Analysis of Financial Condition and Results of Operations | 49 |
Item 7A. |
| 68 | |
Item 8. |
| 71 | |
Item 9. |
| Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 133 |
Item 9A. |
| 133 | |
Item 9B. |
| 135 | |
PART III |
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Item 10. |
| 135 | |
Item 11. |
| 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. |
| 135 | |
PART IV |
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Item 15. |
| 136 | |
GLOSSARY SIGNATURES |
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3
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:
| â—Ź | economic conditions in the United States and globally; |
| ● | domestic and global supply and demand for oil, natural gas liquids (“NGLs”) and natural gas; |
| â—Ź | realized prices for oil, natural gas and NGLs and volatility of those prices; |
| â—Ź | impairments of our natural gas and oil asset values due to declines in commodity prices; |
| â—Ź | conditions in the domestic and global capital and credit markets and their effect on us; |
| â—Ź | the outcome of our pending exchange offer and consent solicitation related to our outstanding senior notes; |
| â—Ź | the adequacy and availability of our 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 meet working capital needs; |
| â—Ź | 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; |
| â—Ź | the geologic quality of our properties with regard to, among other things, the existence of hydrocarbons in economic quantities; |
| â—Ź | uncertainties inherent in the estimates of our oil, NGL and natural gas reserves; |
| â—Ź | our ability to increase oil, NGL and natural gas production and income through exploration and development; |
| â—Ź | drilling and operating risks; |
| â—Ź | counterparty credit risks; |
| â—Ź | the success of our drilling techniques in both conventional and unconventional reservoirs; |
| â—Ź | the success of the secondary and tertiary recovery methods we utilize or plan to employ in the future; |
| â—Ź | the number of potential well locations to be drilled, the cost to drill, and the time frame within which they will be drilled; |
| â—Ź | the ability of contractors to timely and adequately perform their drilling, construction, well stimulation, completion and production services; |
| â—Ź | the availability of equipment, such as drilling rigs, and infrastructure, such as transportation, pipelines, processing and midstream services; |
| â—Ź | the effects of adverse weather or other natural disasters on our operations; |
| â—Ź | competition in the oil and gas industry in general, and specifically in our areas of operations; |
| â—Ź | changes in our drilling plans and related budgets; |
| â—Ź | the success of prospect development and property acquisitions; |
| â—Ź | the success of our business and financial strategies, and hedging strategies; |
| â—Ź | uncertainties related to the legal and regulatory environment for our industry and our own legal proceedings and their outcome; |
4
| â—Ź | our ability to cure the deficiencies with respect to the continued listing standards of the NASDAQ Global Select Market; 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.
5
General
We are an independent oil, NGL and natural gas company operating in the Appalachian and Illinois Basins. In the Appalachian Basin, we are focused on drilling and exploration activities in the Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale. In the Illinois Basin, we are focused on our developmental oil drilling on our properties. 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 regional offices in Bridgeport, Illinois; Cranberry, Pennsylvania; and Carrolton, Ohio.
We were incorporated in the state of Delaware on March 8, 2007. Our common stock currently trades on the NASDAQ Global Select 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, and Water Solutions Holdings, LLC and subsidiaries (“Water Solutions”), which were sold in July 2015, unless otherwise noted, which are classified as Discontinued Operations on our Consolidated Statements of Operations and Assets Held for Sale on our Consolidated Balance Sheets.
At December 31, 2015, our estimated proved reserves had the following characteristics:
| â—Ź | 680.4 Bcfe; |
| â—Ź | 59.7% natural gas, 35.6% NGLs and 4.7% crude oil and condensate; |
| â—Ź | 95.1% proved developed; and |
| â—Ź | a reserve life index of approximately 9.5 years (based upon 2015 production). |
At December 31, 2015, we owned an interest in approximately 1,819 oil and natural gas wells. For the quarter ended December 31, 2015, we produced an average of 195.8 net MMcfe per day, composed of approximately 62.4% natural gas, 9.5% oil and 28.1% NGLs.
In the Illinois Basin, where our production is 100% oil, we produced an average of 1,998 bopd in 2015, a decrease of 9.5% from 2014, which is primarily attributable to natural decline of our mature assets in this region. As of December 31, 2015, including both developed and undeveloped acreage, we controlled approximately 99,200 gross (79,700 net) acres in Illinois, Indiana and Kentucky that we believe are prospective for conventional and horizontal development.
In the Appalachian Basin during 2015, we averaged net production of approximately 183.8 MMcfe per day of natural gas, NGLs and condensate. As of December 31, 2015, including both developed and undeveloped acreage, we controlled approximately 319,300 gross (267,000 net) acres in Pennsylvania that we believe are prospective for Marcellus Shale exploration and 275,200 gross (250,800 net) acres in Pennsylvania that we believe are prospective for Burkett Shale exploration. In addition, as of December 31, 2015, we controlled approximately 332,000 gross (296,200 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, 2015 was $172.0 million, which was primarily derived from the sale of oil, NGLs and natural gas.
For the year ended December 31, 2015, we drilled or participated in the drilling of 39.0 gross (26.5 net) wells. We placed into sales 36.0 gross (16.1 net) wells and ended the year with 22.0 gross (16.4 net) wells in inventory that are resting or awaiting completion.
The following table sets forth selected data concerning our continuing operations for production, estimated proved reserves and undeveloped acreage in our two operating regions for the periods indicated:
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6
| 2015 Average Daily Mcfe1 |
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| Total Proved Bcfe (as of December 31, 2015) |
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| Percent of Total Proved Bcfe |
|
| PV-10 (as of December 31, 2015)2 (in millions) |
|
| Total Net Undeveloped Acres (as of December 31, 2015)3 |
| ||||||
Illinois Basin |
|
| 11,988 |
|
|
| 20.4 |
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| 3.0 | % |
| $ | 38.0 |
|
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| 47,375 |
|
Appalachian Basin |
|
| 183,834 |
|
|
| 660.0 |
|
|
| 97.0 | % |
| $ | 262.7 |
|
|
| 195,040 |
|
Total |
|
| 195,822 |
|
|
| 680.4 |
|
|
| 100.0 | % |
| $ | 300.7 |
|
|
| 242,415 |
|
1 | Oil 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 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. At December 31, 2015, our standardized measure was $255.6 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. In the Appalachian Basin, 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. In the Illinois Basin, which is 100% oil producing, we are focused on conventional drilling and recompletion projects. A substantial portion of our acreage holdings are in liquids-rich areas that we believe are prospective for oil, condensate and NGL production. As of December 31, 2015, our holdings believed to be prospective for liquids-rich production accounted for approximately 90.8% 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 48.7% between the fourth quarter of 2009 and the fourth quarter of 2015. 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 88.0% 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 lease operating expense per Mcfe has decreased from $1.84 per Mcfe in 2013 to $1.78 per Mcfe in 2014 and $1.66 per Mcfe in 2015. Our general and administrative expense per Mcfe has decreased from $0.98 per Mcfe in 2013 to $0.64 per Mcfe in 2014 and $0.41 per Mcfe in 2015.
7
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 crude oil, NGL and natural gas resources located in the Appalachian and Illinois Basins. We pursue an active, technology-driven drilling program to develop and maximize the value of our existing acreage. We actively allocate capital between our two core basins 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:
| â—Ź | our Marcellus Shale play with approximately 319,300 gross (267,000 net) acres; |
| â—Ź | our Utica Shale play with approximately 332,000 gross (296,200 net) acres; |
| â—Ź | our Burkett Shale play with approximately 275,200 gross (250,800 net) acres; |
| â—Ź | our conventional drilling and recompletion projects in the Illinois Basin. |
Employ Technological Expertise. We intend to utilize and expand the technological expertise that has enabled us to achieve a drilling success rate of approximately 96.0% 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 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 Financial 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, 2015, we had over 45.0% of our 2015 oil production volumes hedged through 2016, over 100.0% of our 2015 natural gas production volumes hedged through 2016 and over 40.0% of our 2015 NGL production volumes hedged through 2016. Including the effects of derivatives added since December 31, 2015, we have over 70.0% of our 2015 oil production hedged through 2016, over 100.0% of our 2015 natural gas production hedged through 2016 and over 45.0% of our 2015 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 oil and gas production.
Significant Accomplishments in 2015
We have described certain of our significant accomplishments in 2015 below.
| â—Ź | Completed the divestiture of Water Solutions. In July 2015, we sold Water Solutions, an entity of which we owned a 60% interest, to American Water Works Company, Inc. for total consideration of approximately $130.0 million, inclusive of cash and debt. We received approximately $66.8 million in net proceeds, resulting in a gain of approximately $57.8 million. |
| ● | Entered into a joint venture to develop properties in our Butler County, Pennsylvania core area. In March 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. We expect to receive consideration for the transaction of approximately $67.0 million, with $16.6 million received at closing. As of December 31, 2015, ArcLight had paid approximately $42.9 million for their interest in wells that have been drilled or are in the process of being drilled. |
8
| â—Ź | Decreased lease operating expenses. We have decreased our lease operating expenses, on a per-unit of production basis, for seven consecutive years, from $4.66 per Mcfe in 2008 to $1.66 per Mcfe in 2015. |
| â—Ź | Realized production growth. Due to the success of our development programs in the Appalachian Basin, we increased our total production by 26.8% in 2015. Specifically, our oil production decreased 0.8%, NGL production increased 60.7% and natural gas production increased 20.5%. |
| â—Ź | Grew liquids-rich production. For the year ended December 31, 2015, our production related to oil and NGLs comprised approximately 37.6% of our total production as compared to the year ended December 31, 2014, where our production related to oil and NGLs comprised approximately 34.3% of our total production. |
Plans for 2016
We are currently in the process of developing our 2016 capital expenditure budget, which we expect to be between $15.0 and $25.0 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 further curtail our capital spending.
The following table summarizes our actual 2015 capital expenditures:
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| For the Year Ended December 31, 2015 (Actual) (in thousands) |
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Capital Expenditures |
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Illinois Basin Drilling & Completion |
| $ | 14,523 |
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Illinois Basin Other |
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| 732 |
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Appalachian Basin Drilling & Completion |
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| 172,261 |
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Appalachian Basin Midstream |
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| 8,127 |
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Appalachian Basin Other |
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| 8,614 |
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Other Corporate Expenditures |
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| 231 |
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Total Capital Expenditures1 |
| $ | 204,488 |
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1 | Does not reflect acquisitions of proved and unproved oil and gas properties or capitalized interest. Capital expenditures for the acquisition of unproved properties and capitalized interest for the year ended December 31, 2015 totaled approximately $28.2 million and $7.7 million, respectively. |
9
Production, Revenues and Price History
The following table sets forth information regarding oil and gas production and revenues from continuing operations for the last three years:
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| Production and Revenue by Region For the Years Ended December 31, ($ in thousands) |
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| 2015 |
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| 2014 |
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| 2013 |
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Appalachian Region: |
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Revenue |
| $ | 138,707 |
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| $ | 225,511 |
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| $ | 139,542 |
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Oil Production (Bbls)1 |
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| 402,867 |
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| 334,944 |
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| 139,947 |
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Natural Gas Production (Mcf) |
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| 44,606,753 |
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| 37,011,177 |
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| 23,446,755 |
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C3+ NGL Production (Bbls) |
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| 2,026,321 |
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| 1,531,131 |
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| 819,670 |
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Ethane (Bbls) |
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| 1,319,582 |
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| 551,315 |
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|
| — |
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Total Production (Mcfe)2 |
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| 67,099,373 |
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| 51,515,517 |
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| 29,204,457 |
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Oil Average Sales Price |
| $ | 34.92 |
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| $ | 74.84 |
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| $ | 89.91 |
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Natural Gas Average Sales Price |
| $ | 1.86 |
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| $ | 3.42 |
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| $ | 3.71 |
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C3+ NGL Average Sales Price |
| $ | 16.18 |
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| $ | 45.47 |
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| $ | 48.66 |
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Ethane Average Sales Price |
| $ | 6.60 |
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| $ | 7.83 |
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| $ | — |
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Average Production Cost per Mcfe3 |
| $ | 1.39 |
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| $ | 1.33 |
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| $ | 1.25 |
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Illinois Region |
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Revenue |
| $ | 33,244 |
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| $ | 72,358 |
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| $ | 74,377 |
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Oil Production (Bbls) |
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| 729,251 |
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| 806,162 |
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| 774,285 |
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Total Production (Bbls) |
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| 729,251 |
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| 806,162 |
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| 774,285 |
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Oil Average Sales Price |
| $ | 45.59 |
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| $ | 89.76 |
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| $ | 96.06 |
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Average Production Cost per Bbl3 |
| $ | 33.63 |
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| $ | 37.34 |
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| $ | 31.21 |
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Total Company2 |
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Revenue |
| $ | 171,951 |
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| $ | 297,869 |
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| $ | 213,919 |
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Oil Production (Bbls)1 |
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| 1,132,118 |
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| 1,141,106 |
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|
| 914,232 |
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Natural Gas Production (Mcf) |
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| 44,606,753 |
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| 37,011,177 |
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| 23,446,755 |
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C3+ NGL Production (Bbls) |
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| 2,026,321 |
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| 1,531,131 |
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| 819,670 |
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Ethane Production (Bbls) |
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| 1,319,582 |
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| 551,315 |
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|
| — |
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Total Production (Mcfe)2 |
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| 71,474,879 |
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| 56,352,489 |
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| 33,850,167 |
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Oil Average Sales Price |
| $ | 41.79 |
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| $ | 85.38 |
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| $ | 95.12 |
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Natural Gas Average Sales Price |
| $ | 1.86 |
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| $ | 3.42 |
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| $ | 3.71 |
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C3+ NGL Average Sales Price |
| $ | 16.18 |
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| $ | 45.47 |
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| $ | 48.66 |
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Ethane Average Sales Price |
| $ | 6.60 |
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| $ | 7.83 |
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| $ | — |
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Average Production Cost per Mcfe3 |
| $ | 1.65 |
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| $ | 1.75 |
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| $ | 1.81 |
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1 | Primarily consists of condensate. |
2 | Oil 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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As of December 31, 2015, we had 274 full-time employees, 145 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
We market nearly all of our oil production from the properties that we operate in the Illinois Basin for both our interest and that of the other working interest owners and royalty owners. The majority of our oil is stored at well site tanks and sold to CountryMark Cooperative, LLP (“CountryMark”), a local refinery. Purchasers, including CountryMark, purchase our oil at our tank facilities and truck the oil to their refinery facilities. Our accounts receivable due from CountryMark constituted approximately 18.1% of our oil, NGL and natural gas accounts receivable at December 31, 2015. As such, we are currently significantly dependent on the creditworthiness of CountryMark. We have taken steps to monitor the creditworthiness of CountryMark, including obtaining a letter of credit corresponding to a significant portion of its projected monthly revenue.
In December 2009, we entered into a Master Crude Purchase Agreement (the “Master Crude Purchase Agreement”) with CountryMark that became effective as of January 1, 2010. Under the terms of the agreement, we agreed to sell, supply and deliver to CountryMark, and CountryMark agreed to receive and purchase from us, crude oil pursuant to purchase and sale order confirmations that we and CountryMark may enter into from time to time. Under the agreement, until we enter into a confirmation with CountryMark, neither party is under an obligation to purchase or sell any crude oil. The Master Crude Purchase Agreement provides that the term will automatically be extended for additional one-year periods unless, prior to October 1 of each year, either party gives written notice to the other. We have historically entered into confirmations for approximately one-year periods, although the terms of the confirmations have varied. In December 2015, we entered into a confirmation with CountryMark that extends purchases through November 2018. The confirmation does not obligate us to provide a specific volume of crude oil, and as of December 31, 2015, we were not committed to any delivery levels with CountryMark or any other party. In addition to the arrangements with CountryMark, we also have an offload facility at a nearby crude oil pipeline that Marathon Oil Corp. (“Marathon”) operates that has enabled us to diversify our purchasers in the Illinois Basin.
In the Appalachian Basin, 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, 2015. Additionally in Butler County, Pennsylvania, we have firm processing commitments with unaffiliated third parties for our liquids-rich gas totaling 245,000 gross MMBTU per day as of December 31, 2015, and increasing to 285,000 gross MMBTU per day by December 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 231,000 gross MMBTU per day in 2016; 390,000 gross MMBTU per day in 2017; 393,000 gross MMBTU per day in 2018; 371,000 gross MMBTU per day in 2019; and 356,000 gross MMBTU per day in 2020.
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 are scheduled to commence in March 2016 and the propane and butane sales are expected to begin in the first quarter of 2017. 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 what price we will be able to sell our oil and natural gas. Prices may be low when our wells are most productive, thereby reducing overall returns.
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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 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, 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 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, 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,
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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 FERC, or the purchase or sale of transportation services subject to the jurisdiction of 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. 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 FERC jurisdiction which includes the reporting requirements under Order Nos. 704 and 720. It therefore reflects a significant expansion of 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:
| â—Ź | require the acquisition of permits or other authorizations before construction, drilling and certain other of our activities; |
| â—Ź | limit or prohibit construction, drilling and other activities on specified lands within wetlands, endangered species habitat, wilderness and other protected areas; |
| â—Ź | impose substantial liabilities for pollution that may result from our operations; |
| â—Ź | require the installation of pollution control equipment in connection with operations; |
| â—Ź | place restrictions or regulations upon the use or disposal of the material utilized in our operations; |
| â—Ź | 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; |
| â—Ź | require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells; and |
| â—Ź | 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 could 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
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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 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. 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. 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 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 August 2015, the EPA proposed a suite of regulations that would set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities. These regulations are expected to be finalized in 2016. 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.
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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, on September 22, 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. On November 9, 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 legislation, known as Act 13, which established more stringent environmental standards. Among other changes, Act 13 required disclosure of chemicals used in hydraulic fracturing, extended the setback requirements for unconventional wells, restricted well site locations in certain areas such as floodplains, established new spill containment requirements, and authorized local governments to adopt impact fees. Certain provisions of Act 13 have been challenged in court and struck down, and we cannot predict whether it 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.
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 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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In evaluating our company, the 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.
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 oil, 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:
| â—Ź | changes in global supply and demand for oil, NGLs and natural gas; |
| â—Ź | the condition of the U.S. and global economy impacting the global supply and demand for oil, NGLs and natural gas; |
| â—Ź | the actions of certain foreign states; |
| â—Ź | the price and quantity of imports of foreign oil and natural gas; |
| â—Ź | political conditions, including embargoes, in or affecting other oil producing activities; |
| â—Ź | the level of global oil and natural gas exploration and production activity; |
| â—Ź | the level of global oil and natural gas inventories; |
| â—Ź | production or pricing decisions made by the Organization of Petroleum Exporting Countries; |
| â—Ź | weather conditions; |
| â—Ź | 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; |
| â—Ź | technological advances affecting energy consumption; |
| â—Ź | effect of energy conservation efforts; and |
| â—Ź | the price and availability of alternative fuels. |
Furthermore, oil and natural gas prices continued to be volatile in 2015. For example, the WTI oil spot price in 2015 ranged from a high of $61.36 to a low of $34.55 per Bbl and Henry Hub natural gas spot prices in 2015 ranged from a high of $3.32 to a low of $1.63 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, our capital expenditures budget for 2016 is considerably smaller than our actual capital expenditures for 2015. 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 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.
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We have substantial indebtedness and may incur substantially more debt, which could exacerbate the risks associated with our indebtedness.
As of December 31, 2015, we had approximately $787.1 million of debt outstanding, including $675.0 million related to our senior notes, $111.5 million outstanding on our revolving credit facility and $0.6 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, 2015, our $500 million revolving credit facility had a borrowing base of $350.0 million for secured borrowings, subject to periodic borrowing base redeterminations. On February 3, 2016, the borrowing base under our revolving credit facility was reduced to $200.0 million and was further reduced to $190.0 million on March 14, 2016 effective April 1, 2016. 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, and so a rise in interest rates will generate greater interest expense to the extent we do not have applicable interest rate fluctuation hedges. 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 indenture.
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. Further, any failure by us to comply with the financial and other restrictive covenants relating to our indebtedness could result in a default or event of default under that indebtedness, which could 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, 2015, natural gas prices at Henry Hub have ranged from a high of $13.31 per MMBtu in 2008 to a low of $1.63 per MMBtu in 2015. On December 31, 2015, the Henry Hub spot market price of natural gas was $2.28 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 $37.13 per barrel on December 31, 2015, 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.
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
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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 2015, we expect to record impairment expense of $345.8 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 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. 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 determined semi-annually, and may also be redetermined periodically 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 to repay any indebtedness 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 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 flow from operations and access to capital is subject to a number of variables, including:
| â—Ź | our estimated proved reserves; |
| â—Ź | the level of oil and natural gas we are able to produce from existing wells; |
| â—Ź | our ability to extract NGLs from the natural gas we produce; |
| â—Ź | the prices at which oil, NGLs and natural gas are sold; and |
| â—Ź | our ability to acquire, locate and produce new reserves. |
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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 Senior Notes and the certificate of designations governing our Series A Preferred Stock contain, and any future indebtedness we incur may 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; |
| · | 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.
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.
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The value of our proved reserves as of December 31, 2015, calculated using SEC pricing may be higher than the fair market value of our proved reserves calculated using current market prices.
Our estimated proved reserves as of December 31, 2015 and related PV-10 and Standardized Measure were calculated under SEC rules using twelve-month trailing average benchmark prices of $46.79 per barrel of oil (WTI) and $2.587 per MMBtu (Henry Hub spot). The spot prices for oil and natural gas on March 11, 2016, were $38.57 per barrel and $1.81 per MMBtu, respectively. Using more recent prices in estimating our proved reserves, without giving effect to any acquisitions or development activities we have executed in 2016, would likely result in a reduction in proved reserve volumes due to economic limits. Furthermore, any such reduction in proved reserve volumes combined with lower commodity prices would substantially reduce the PV-10 and Standardized Measure of our proved reserves.
Although we have hedged a portion of our estimated 2016 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 70.0% of our annualized oil production hedged through 2016, over 100.0% of our annualized natural gas production hedged through 2016 and over 45.0% of our annualized NGL production hedged through 2016. In addition, we have basis swaps in place for 16,630 MMcf at an average differential to Henry Hub NYMEX of $0.94 per Mcf through 2016. 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.
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:
| â—Ź | delays imposed by or resulting from compliance with regulatory requirements; |
| â—Ź | unusual or unexpected geological formations; |
| â—Ź | pressure or irregularities in geological formations; |
| â—Ź | shortages of or delays in obtaining equipment and qualified personnel; |
| â—Ź | equipment malfunctions, failures or accidents; |
| â—Ź | unexpected operational events and drilling conditions; |
| â—Ź | pipe or cement failures; |
| â—Ź | casing collapses; |
| â—Ź | lost or damaged oilfield drilling and service tools; |
| â—Ź | loss of drilling fluid circulation; |
| â—Ź | uncontrollable flows of oil, natural gas and fluids; |
| â—Ź | fires and natural disasters; |
| â—Ź | 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; |
| â—Ź | adverse weather conditions; |
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| â—Ź | oil and natural gas property title problems; and |
| â—Ź | 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.
In addition, substantially all 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.
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 $54.9 million related to our commodity derivative instruments for the year ended December 31, 2015.
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, 2015 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 2015 prices would reduce our gross revenues, before the effects of derivatives, for the year ending December 31, 2016 by approximately $18.3 million.
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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 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 2015, we recorded impairment expense of approximately $345.8 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.
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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:
| â—Ź | actual prices we receive for oil and natural gas; |
| â—Ź | actual cost of development and production expenditures; |
| â—Ź | the amount and timing of actual production; |
| â—Ź | supply of and demand for oil and natural gas; and |
| â—Ź | changes in governmental regulations or taxation. |
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:
| â—Ź | landing our wellbore in the desired drilling zone; |
| â—Ź | staying in the desired drilling zone while drilling horizontally through the formation; |
| â—Ź | running our casing the entire length of the wellbore; and |
| â—Ź | 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:
| â—Ź | the ability to fracture stimulate the planned number of stages; |
| â—Ź | the ability to run tools the entire length of the wellbore during completion operations; and |
| â—Ź | 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.
The development of our proved undeveloped reserves in our areas of operation may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our undeveloped reserves may not be ultimately developed or produced.
Approximately 4.9% of our total estimated proved reserves were classified as proved undeveloped as of December 31, 2015. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. We estimate that approximately $19.0 million in capital expenditures will be required over the next five years to develop our total
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proved undeveloped reserves. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the PV-10 of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic, potentially resulting in impairment. In addition, delays in the development of reserves could cause us to have to reclassify our estimated proved reserves as unproved reserves. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our securities.
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.
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.
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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 federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control Program (“UIC”). The hydraulic fracturing process is typically regulated by state oil and natural gas commissions; however, the Environmental Protection Agency (“EPA”) has asserted federal regulatory authority over certain hydraulic fracturing activities involving the use of diesel under the SDWA’s UIC program. On February 12, 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 (“CWA”), Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and the Clean Air Act (“CAA”) 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 and plans to propose these standards in 2016. 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.
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.
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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:
| â—Ź | nature and timing of drilling and operational activities; |
| â—Ź | timing and amount of capital expenditures; |
| â—Ź | expertise and financial resources; |
| â—Ź | the approval of other participants in drilling wells; and |
| â—Ź | selection of suitable technology. |
All of the value of our production and reserves is concentrated in the Appalachian Basin and Illinois Basin. Because of this concentration, any production problems or changes in assumptions affecting our proved reserve estimates related to these areas could have a material adverse impact to our business.
For the year ended December 31, 2015, approximately 93.9% of our net production came from the Appalachian Basin and 6.1% came from the Illinois Basin. As of December 31, 2015, approximately 97.0% of our estimated proved reserves were located in the fields that comprise the Appalachian Basin and 3.0% of our estimated proved reserves were located in fields that comprise the Illinois Basin. If mechanical problems, weather conditions or other events were to curtail a substantial portion of the production in one or both of these regions, our cash flow would be adversely affected. If ultimate production associated with these properties is less than our estimated reserves, or changes in pricing, cost or recovery assumptions in the area results in a 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.
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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, 2015, we were a party to several transportation, marketing and processing agreements which commit us to approximately $179.0 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 volumes.
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:
| â—Ź | 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; |
| â—Ź | abnormally pressured formations; |
| â—Ź | mechanical difficulties, such as stuck oil field drilling and service tools and casing collapses; |
| â—Ź | fires and explosions; |
| â—Ź | personal injuries and death; and |
| â—Ź | 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:
| â—Ź | the location and spacing of wells; |
| â—Ź | the unitization and pooling of properties; |
| â—Ź | the method of drilling and completing wells; |
| â—Ź | the surface use and restoration of properties upon which wells are drilled; |
| â—Ź | the plugging and abandoning of wells; |
| â—Ź | the disposal of fluids used or other wastes generated in connection with our drilling operations; |
| â—Ź | the marketing, transportation and reporting of production; and |
| â—Ź | 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.
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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 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. On July 19, 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 are expected to be 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
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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. 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 will also require us to comply with certain futures and swaps position limits and new recordkeeping and reporting requirements, and may also 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 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.
Most recently, in February 2015, the Pennsylvania governor proposed the Pennsylvania Education Reinvestment Act, a new severance tax targeting proceeds from production of unconventional natural gas wells within the Commonwealth of Pennsylvania. The proposal includes a 5% tax on the value of the gas at the wellhead plus a 4.7 cents per thousand cubic feet of volume severed. Additionally, no portion of the tax imposed in this legislation would be allowed to be deducted from royalty payments. The Governor’s office has stated that this proposal would replace the existing impact fee. There is no assurance as to the final form of the proposal, or whether the proposal will be adopted. 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.
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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 95.5% of our commodity sales from continuing operations for the year ended December 31, 2015 were due from five customers, with the largest single customer accounting for 44.2%. 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. The loss of all or a significant part of this revenue 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 has made budget proposals which, if enacted into law by Congress, would potentially increase and accelerate 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 amortization period of geological and geophysical expenses. Legislation which would have implemented the proposed changes has been 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.
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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 have experienced a recent ratings downgrade, and if commodity prices do not improve or worsen or if we are unable to increase our liquidity, we could experience further downgrades.
On January 8, 2016, Standard & Poor’s Ratings Services downgraded our corporate credit rating to “CCC-” from “B-”. On January 25, 2016, Moody’s downgraded our family rating to Caa3 from Caa1 and our probability of default rating to Caa3-PD from Caa1-PD. The SGL-4 speculative grade liquidity rating was affirmed and the rating outlook remained negative. The downgrades were primarily the result of the impact of rapid deterioration of the commodity price environment and our credit metrics. S&P and Moody’s each also noted the increased likelihood of the Company purchasing or exchanging debt at a steep discount to the face value.
If commodity prices do not improve or worsen or if we are unable to increase our liquidity, we could experience further downgrades. Credit rating agencies continually review their ratings for the companies and for the securities they follow. We cannot assure that one or more rating agencies would not take action to downgrade or negatively comment upon their respective ratings on the Company. A negative change in our ratings or the perception that such a change could occur may adversely affect the market price of our securities. If commodity prices do not improve or worsen or if we are unable to increase our liquidity, we could experience further downgrades.
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 2015, the sales price of our stock ranged from a low of $0.89 per share (on December 14, 2015) to a high of $5.74 per share (on May 13, 2015). 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 financial results, may have a significant effect on the market price of our common stock.
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We are no longer eligible to use Form S-3, which could impair our ability to raise capital.
As a result of our not declaring the first quarter dividend on our Series A Preferred Stock, as of the date of this report, we are not eligible to use Form S-3. As a result, we cannot use 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 occurred. In addition, we may be limited in our ability to file shelf registration statements on SEC Form S-3 if our public float is below $75 million. As a result, we may not be eligible to use Form S-3 for primary offerings 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. 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.
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 100,000,000 shares of common stock and 100,000 shares of preferred stock with such designations, preferences, and rights as may be determined by our board of directors. As of March 11, 2016, there were 56,952,196 shares of our common stock issued and outstanding and 13,753 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 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 13% of the outstanding shares of our common stock as of March 11, 2016.
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:
| â—Ź | the ability of our board of directors to issue shares of our common stock and preferred stock without stockholder approval; |
| â—Ź | the ability of our board of directors to make, alter, or repeal our bylaws without further stockholder approval; |
| â—Ź | 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; |
| â—Ź | 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 |
| â—Ź | 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 11, 2016, our board of directors, including Lance T. Shaner, our Chairman, and our other executive officers collectively own approximately 13% of the outstanding shares of our common stock. Although this is not a majority of our outstanding common stock, these stockholders, acting together, will have the ability to exert influence over all matters requiring stockholder approval, including the election and removal of directors, any proposed merger, consolidation, or sale of all or substantially all of our assets and other corporate transactions.
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.
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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.
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 Global Select Market continued listing standards, our common stock may be subject to delisting.
Our common stock is currently 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 February 25, 2016, we received a deficiency letter from the Listing Qualifications Department of NASDAQ of non-compliance with this listing standard. In accordance with NASDAQ Listing Rule 5810(c)(3)(A), we need to bring our share price back above $1.00 per share for a minimum of 10 consecutive business days within six months or NASDAQ may, at its discretion, commence suspension and delisting procedures, or require us to move our listing to the NASDAQ Capital Market in order to obtain a grace period of an additional six additional months to re-attain compliance. Our closing share price on March 11, 2016, was $1.54.
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 us from accessing the public capital markets; and (iv) impairing our ability to provide equity incentives to our employees.
As of the date of this filing, we have no unresolved comments from the staff of the SEC.
The table below summarizes certain data for our core operating areas at December 31, 2015:
|
| Average Daily Production (Mcfe per day) |
|
| Total Production (MMcfe) |
|
| Percent of Total Production |
|
| Total Estimated Proved Reserves (Bcfe) |
|
| Percent of Total Estimated Proved Reserves |
| |||||
Appalachian Basin |
|
| 183,834 |
|
|
| 67,099 |
|
|
| 93.9 | % |
|
| 660.0 |
|
|
| 97.0 | % |
Illinois Basin |
|
| 11,988 |
|
|
| 4,376 |
|
|
| 6.1 | % |
|
| 20.4 |
|
|
| 3.0 | % |
Total |
|
| 195,822 |
|
|
| 71,475 |
|
|
| 100.0 | % |
|
| 680.4 |
|
|
| 100.0 | % |
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.
33
As of December 31, 2015, we owned an interest in approximately 639 producing natural gas wells in the Appalachian Basin, located predominantly in Pennsylvania and Ohio. In addition to our producing wells in the basin, we own seven gross PUD drilling locations with total reserves of 33.4 Bcfe, and 29.0 gross locations with proved developed non-producing reserves totaling 103.3 Bcfe. At December 31, 2015, we had approximately 383,500 gross (319,700 net) acres in the Appalachian Basin under lease, of which 205,800 gross (195,000 net) acres were undeveloped. Of our total acreage holdings in the Appalachian Basin, we believe that approximately 275,200 gross (250,800 net) acres are prospective for three producing horizons, including the Marcellus, Utica and Burkett. Reserves at December 31, 2015 decreased 634.4 Bcfe, or 49.0%, from 2014 due primarily to the continued depressed commodity price environment.
Capital expenditures in 2015 for drilling and facility development totaled $189.0 million, which funded the drilling of 34.0 gross (23.0 net) wells. During the year, we placed into service 33.0 gross (13.6 net) wells and had an inventory of 22.0 gross (16.4 net) wells resting or awaiting completion.
Marcellus Shale
As of December 31, 2015, we had interests in approximately 319,300 gross (267,000 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 286,400 gross (251,400 net) acres that we believe to be prospective for liquid-rich Marcellus production. During 2015, we drilled, or participated in the drilling of 27.0 gross (16.0 net) Marcellus Shale wells and placed into service 31.0 gross (16.2 net) Marcellus Shale wells. Our estimated proved reserves related to the Marcellus Shale as of December 31, 2015, totaled approximately 491.0 Bcfe, including three PUD locations with estimated proved reserves of 15.4 Bcfe and 15.0 proved non-producing locations with estimated proved reserves of 62.8 Bcfe.
We are a party to three joint ventures in Pennsylvania, 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 and Clearfield Counties, Pennsylvania project areas is with WPX Energy San Juan, LLC and Williams Production Appalachia, LLC (collectively “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 ArcLight. ArcLight is participating in these wells at a 35.0% 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.
Utica Shale
As of December 31, 2015, we had under lease approximately 332,000 gross (296,200 net) acres that we believe are prospective for the Utica Shale in Ohio and Pennsylvania. In Ohio, our holdings comprise approximately 28,500 gross (26,000 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, 2015, we estimate Utica Shale acreage holdings in Pennsylvania of approximately 303,500 gross (270,200 net) acres. During 2015, we drilled seven gross (seven net) Utica Shale wells and placed into service four gross (four net) Utica Shale wells. Our estimated proved reserves related to the Utica Shale as of December 31, 2015, totaled approximately 123.0 Bcfe, including three PUD locations with estimated proved reserves of 12.8 Bcfe and 11.0 proved non-producing locations with estimated proved reserves of 33.4 Bcfe.
We are a party to one joint venture in Ohio related to our Utica Shale development. This joint venture, for which we serve as the operator, is with MFC Drilling, Inc. and covers an area of mutual interest in Belmont, Guernsey and Noble Counties, Ohio. Our average working interest in these areas is approximately 62.5%.
Burkett Shale
As of December 31, 2015, we had under lease approximately 275,200 gross (250,800 Net) acres prospective for the liquids-rich Upper Burkett Shale in Pennsylvania. During 2015, we did not drill any Burkett Shale wells and placed into service four gross (2.1 net) wells. Our estimated proved reserves related to the Burkett Shale as of December 31, 2015 totaled approximately 45.9 Bcfe, including one PUD location with estimated proved reserves of 5.2 Bcfe and three proved non-producing locations with estimated proved reserves of 7.1 Bcfe.
34
In the Illinois Basin, we own an interest in 1,180 oil wells. We have approximately 99,200 gross (79,700 net) acres owned and under lease.
Total estimated proved reserves in the Illinois Basin decreased approximately 22.0 Bcfe, or 51.9%, to approximately 20.4 Bcfe at December 31, 2015 when compared to year-end 2014, which was primarily due to the continued depressed commodity price environment. Capital expenditures in 2015 for drilling and facility improvements in the region were approximately $15.3 million, which funded the drilling of five gross (3.5 net) wells, the recompletion of five gross (five net) wells and the placement into service of eight gross (7.5 net) wells. These expenditures also covered work performed in the basin designed to optimize our secondary waterflood operations whereby we stabilized declining production.
Estimated Proved Reserves
For estimated proved reserves as of December 31, 2015, 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 |
| Oil (Barrels) |
|
| NGL (Barrels) |
|
| Gas (Mcf) |
| |||
Proved Developed |
|
| 3,995,200 |
|
|
| 30,740,100 |
|
|
| 334,159,500 |
|
Proved Developed Non-Producing |
|
| 949,400 |
|
|
| 7,201,800 |
|
|
| 55,594,900 |
|
Proved Undeveloped |
|
| 372,500 |
|
|
| 2,404,700 |
|
|
| 16,708,400 |
|
Total Proved |
|
| 5,317,100 |
|
|
| 40,346,600 |
|
|
| 406,462,800 |
|
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, 2015 in conjunction with our reserve estimates.
The following table sets forth our estimated proved reserves at the end of each of the past three years:
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Description |
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
| 4,944,600 |
|
|
| 7,628,100 |
|
|
| 7,742,500 |
|
Natural Gas (Mcf) |
|
| 389,754,400 |
|
|
| 365,673,300 |
|
|
| 212,061,400 |
|
NGLs (Bbls) |
|
| 37,941,900 |
|
|
| 29,215,000 |
|
|
| 16,322,500 |
|
Proved Undeveloped Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
| 372,500 |
|
|
| 2,056,600 |
|
|
| 877,100 |
|
Natural Gas (Mcf) |
|
| 16,708,400 |
|
|
| 473,511,800 |
|
|
| 309,221,400 |
|
NGLs (Bbls) |
|
| 2,404,700 |
|
|
| 44,037,500 |
|
|
| 29,808,200 |
|
Total Estimated Proved Reserves (Mcfe)1, 2 |
|
| 680,445,000 |
|
|
| 1,336,808,300 |
|
|
| 849,784,600 |
|
PV-10 Value (millions)3 |
| $ | 300.7 |
|
| $ | 1,205.2 |
|
| $ | 668.7 |
|
Standardized Measure (millions)3 |
| $ | 255.6 |
|
| $ | 1,025.4 |
|
| $ | 529.1 |
|
35
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 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 2015 of $46.79 per barrel of oil and $2.587 per Mcfe of natural gas. These prices are adjusted for transportation fees, quality and regional price differentials resulting in $44.45 per barrel of oil, $12.48 per barrel of NGLs and $2.401 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)
As of December 31, 2015, our PUD reserves totaled 0.4 MMbbl of oil, 2.4 MMbbl of NGLs and 16.7 Bcf of natural gas, for a total of 33.4 Bcfe. All of our PUDs at year-end 2015 were associated with the Appalachian Basin. All of these projects are expected to have PUDs convert from undeveloped to developed as these projects begin production and/or production facilities are expanded or upgraded. Changes in PUDs that occurred during the year were due to:
| â—Ź | conversion of approximately 24.9 Bcfe attributable to PUDs into proved developed reserves; |
| â—Ź | negative revisions of 700.4 Bcfe attributable to lower commodity pricing; and |
| â—Ź | 33.4 Bcfe in PUDs due to extensions and discoveries, which are primarily related to the extension of proved acreage in areas that are believed to be prospective for the Marcellus, Utica and Burkett Shale, through our drilling activities. During 2015, we drilled 17.0 gross (15.2 net) wells that were not considered proved in addition to 22.0 gross (11.3 net) wells that were classified as PUDs as of December 31, 2014. |
Costs incurred relating to the development of 22.0 gross (3.9 net) PUD locations converted to proved developed were approximately $10.5 million in 2015. Estimated future development costs relating to the development of our seven gross (5.2 net) PUDs are projected to be approximately $19.0 million in 2016.
All of our PUD drilling locations are scheduled to be drilled in 2016. Initial production from these PUD locations is expected to begin in 2016. We do not have PUD locations associated with reserves that have been booked for longer than five years. Approximately six gross (4.3 net) PUD locations were booked based on reliable technology. Reliable technologies include the use of both public and proprietary geologic data to establish continuity of the formation and its producing properties. This data includes 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 cases where a producing lateral well has been drilled but not yet fracture stimulated, we use observations from drill cuttings and logs as reliable technology to confirm the resources are likely in place for extraction and to support scheduling the well for fracture stimulation in the near future.
Our estimated proved undeveloped reserves at December 31, 2015, did not include any locations that were more than one offset away from a producing well. During 2015, we drilled 35.0 gross (16.6 net) wells that were more than one offset away from a producing well. Our estimated proved undeveloped reserves did not include any locations that generated positive future net revenue but negative present value discounted at 10%.
36
The following table summarizes the changes in our proved undeveloped reserves for the year ended December 31, 2015:
Proved Undeveloped Reserves (Mcfe) |
| For the Year Ended December 31, 2015 |
| |
Beginning proved undeveloped reserves |
|
| 750,076,400 |
|
Sales of Reserves in Place |
|
| (24,856,000) |
|
Undeveloped reserves converted to developed |
|
| (24,856,000 | ) |
Revisions |
|
| (700,364,600 | ) |
Extensions and discoveries |
|
| 33,371,800 |
|
Ending proved undeveloped reserves |
|
| 33,371,600 |
|
In our 2014 reserve report, we had 197.0 gross proved undeveloped locations scheduled for development between 2015 and 2021, of which 20.0 were scheduled for development in 2015. During 2015, 11.0 of the 197.0 PUD locations were completed and converted to proved developed producing reserves. This equated to a conversion of approximately 5.6% 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 the majority of our remaining proved undeveloped locations from the 2015 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, 2015 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 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.
Anticipated capital expenditures related to proved undeveloped locations of approximately $19.0 million are significantly lower than in prior years. This reduction is largely due to the current commodity price environment and the related impact on the economic viability of our proved undeveloped locations from 2014 and prior years, as described above. We have evaluated the impact on our proved undeveloped reserves based on spot commodity prices of $32.53 per barrel of oil and $2.152 per MMbtu of gas at February 1, 2016, due to the differences between SEC pricing and spot pricing on this date. This analysis includes only the impact of the change in pricing and does not contemplate changes in development costs, operating expenses, taxes, operational efficiencies, changes in technologies and access to capital. Based on spot commodity pricing at February 1, 2016, our proved undeveloped reserves would have been approximately 9.9% less than the results obtained using the SEC-mandated beginning-of-the-month average prices for the trailing 12 months for the year ended December 31, 2015. Our number of proved undeveloped locations would have decreased from seven gross (5.2 net) locations to four gross (2.6 net) locations and projected future development costs related to the development of proved undeveloped locations would have been reduced from approximately $19.0 million to approximately $9.1 million.
The foregoing calculations of the impact of lower commodity prices were prepared assuming that all inputs and factors other than commodity prices remain constant, thereby isolating the impact of commodity prices on our PUD reserves, PUD locations and future development costs related to the development of PUDs. Price is only one variable in the estimation of our proved reserves, and other factors could have a significant impact on future reserves and the present value of future cash flows, including, but not limited to, extensions and discoveries, changes in costs, drilling results, well performance and changes in our development plans. There are numerous uncertainties inherent in the estimation of proved reserves and accounting for oil and natural gas properties in subsequent periods and this pro forma estimate should not be construed as indicative of our development plans or future results
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. Richard B. Talley, Jr. and Mr. David E. Nice. Mr. Talley has been practicing consulting petroleum engineering at NSAI since 2004. Mr. Talley is a Licensed Professional Engineer in the State of Texas (No. 102425) and has over 16 years of practical experience in petroleum engineering, with over 11 years of experience in the estimation and evaluation of reserves. He graduated from the University of Oklahoma in 1998 with a Bachelor of Science Degree in Mechanical Engineering and from Tulane University in 2001 with a Master of Business Administration Degree. Mr. Nice has been practicing consulting petroleum
37
geology at NSAI since 1998. Mr. Nice is a Licensed Professional Geoscientist in the State of Texas, Geology (No. 346) and has over 30 years of practical experience in petroleum geosciences, with over 17 years of experience in the estimation and evaluation of reserves. He graduated from the University of Wyoming in 1982 with a Bachelor of Science Degree in Geology and in 1985 with a Master of Science Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; 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, 2015:
|
| Undeveloped Acreage1 |
|
| Developed Acreage2 |
|
| Total Acreage |
|
| Producing Gas Wells |
|
| Producing Oil Wells |
| |||||||||||||||||||||||||
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||||||
Appalachian Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pennsylvania |
|
| 187,383 |
|
|
| 177,298 |
|
|
| 160,923 |
|
|
| 109,768 |
|
|
| 348,306 |
|
|
| 287,066 |
|
|
| 608 |
|
|
| 290 |
|
|
| — |
|
|
| — |
|
Ohio |
|
| 18,456 |
|
|
| 17,742 |
|
|
| 16,756 |
|
|
| 14,852 |
|
|
| 35,212 |
|
|
| 32,594 |
|
|
| 31 |
|
|
| 27 |
|
|
| — |
|
|
| — |
|
Total Appalachian Basin |
|
| 205,839 |
|
|
| 195,040 |
|
|
| 177,679 |
|
|
| 124,620 |
|
|
| 383,518 |
|
|
| 319,660 |
|
|
| 639 |
|
|
| 317 |
|
|
| — |
|
|
| — |
|
Illinois Basin |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois |
|
| 8,724 |
|
|
| 4,122 |
|
|
| 17,657 |
|
|
| 16,243 |
|
|
| 26,381 |
|
|
| 20,365 |
|
|
| — |
|
|
| — |
|
|
| 950 |
|
|
| 939 |
|
Indiana |
|
| 37,413 |
|
|
| 32,435 |
|
|
| 15,809 |
|
|
| 15,141 |
|
|
| 53,222 |
|
|
| 47,576 |
|
|
| — |
|
|
| — |
|
|
| 223 |
|
|
| 218 |
|
Kentucky |
|
| 17,747 |
|
|
| 10,819 |
|
|
| 1,862 |
|
|
| 901 |
|
|
| 19,609 |
|
|
| 11,720 |
|
|
| — |
|
|
| — |
|
|
| 7 |
|
|
| 3 |
|
Total Illinois Basin |
|
| 63,884 |
|
|
| 47,376 |
|
|
| 35,328 |
|
|
| 32,285 |
|
|
| 99,212 |
|
|
| 79,661 |
|
|
| — |
|
|
| — |
|
|
| 1,180 |
|
|
| 1,160 |
|
Total |
|
| 269,723 |
|
|
| 242,416 |
|
|
| 213,007 |
|
|
| 156,905 |
|
|
| 482,730 |
|
|
| 399,321 |
|
|
| 639 |
|
|
| 317 |
|
|
| 1,180 |
|
|
| 1,160 |
|
(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 have obtained actual production from acreage subject to the lease, in which event, the lease will remain in effect until the cessation of production.
38
The following table sets forth, for our continuing operations, the gross and net acres of undeveloped land subject to leases summarized in the preceding table that will expire during the periods indicated:
|
| Expiring Acreage |
| |||||
|
| Gross |
|
| Net |
| ||
Year Ending December 31, |
|
|
|
|
|
|
|
|
2016 |
|
| 133,431 |
|
|
| 124,954 |
|
2017 |
|
| 60,037 |
|
|
| 56,079 |
|
2018 |
|
| 40,796 |
|
|
| 33,526 |
|
2019 |
|
| 18,135 |
|
|
| 16,846 |
|
2020 |
|
| 13,123 |
|
|
| 6,901 |
|
Thereafter |
|
| 4,201 |
|
|
| 4,110 |
|
Total |
|
| 269,723 |
|
|
| 242,416 |
|
The expiring acreage set forth in the table above accounts for 60.7% our total net acreage. As of December 31, 2015, 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 own several workover rigs, which are used in our Illinois Basin operations. We do not own any drilling equipment.
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||||||||||||||
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
|
| Gross |
|
| Net |
| ||||||
Development: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois Basin |
|
| — |
|
|
| — |
|
|
| 5.0 |
|
|
| 3.0 |
|
|
| 1.0 |
|
|
| 1.0 |
|
Appalachian Basin |
|
| 22.0 |
|
|
| 11.3 |
|
|
| 24.0 |
|
|
| 16.2 |
|
|
| 3.0 |
|
|
| 2.7 |
|
Non-Productive |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Total Developmental Wells |
|
| 22.0 |
|
|
| 11.3 |
|
|
| 29.0 |
|
|
| 19.2 |
|
|
| 4.0 |
|
|
| 3.7 |
|
Exploratory: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Illinois Basin |
|
| 3.0 |
|
|
| 2.5 |
|
|
| 10.0 |
|
|
| 7.0 |
|
|
| 16.0 |
|
|
| 16.0 |
|
Appalachian Basin |
|
| 12.0 |
|
|
| 11.7 |
|
|
| 27.0 |
|
|
| 21.4 |
|
|
| 39.0 |
|
|
| 27.0 |
|
Non-Productive |
|
| 2.0 |
|
|
| 1.0 |
|
|
| 3.0 |
|
|
| 2.0 |
|
|
| 2.0 |
|
|
| 2.0 |
|
Total Exploratory Wells |
|
| 17.0 |
|
|
| 15.2 |
|
|
| 40.0 |
|
|
| 30.4 |
|
|
| 57.0 |
|
|
| 45.0 |
|
Total Wells |
|
| 39.0 |
|
|
| 26.5 |
|
|
| 69.0 |
|
|
| 49.6 |
|
|
| 61.0 |
|
|
| 48.7 |
|
Success Ratio1 |
|
| 94.9 | % |
|
| 96.2 | % |
|
| 95.7 | % |
|
| 96.0 | % |
|
| 96.7 | % |
|
| 95.9 | % |
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:
| â—Ź | customary royalty interests; |
| â—Ź | liens incident to operating agreements and for current taxes; |
| â—Ź | obligations or duties under applicable laws; |
| â—Ź | development obligations under oil and gas leases; |
39
| â—Ź | overriding royalty interests; |
| â—Ź | non-surface occupancy leases; and |
| â—Ź | lessor consents to placement of wells. |
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.
Not applicable.
40
Our common stock is traded on the NASDAQ Global Select Market under the symbol “REXX”. As of March 11, 2016, there were approximately 139 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.
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 |
|
|
|
|
|
|
|
|
|
|
2014 |
| High |
|
| Low |
| ||
First Quarter |
| $ | 19.70 |
|
| $ | 16.74 |
|
Second Quarter |
| $ | 22.00 |
|
| $ | 16.94 |
|
Third Quarter |
| $ | 17.84 |
|
| $ | 12.38 |
|
Fourth Quarter |
| $ | 13.19 |
|
| $ | 4.50 |
|
The closing price of our common stock on March 11, 2016 was $1.54.
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 |
|
| Weighted-Average |
|
| Number of Securities |
| |||
Equity compensation plans approved by stockholders |
|
| 443,672 |
|
| $ | 9.64 |
|
|
| 1,144,297 |
|
Equity compensation plans not approved by stockholders |
|
| — |
|
| $ | — |
|
|
| — |
|
Issuer Purchases of Equity Securities
We do not have a stock repurchase program for our common stock.
41
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, 2011 to December 31, 2015, 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, 2011 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, 2010 |
| $ | 100 |
|
| $ | 100 |
|
| $ | 100 |
|
December 31, 2011 |
| $ | 108 |
|
| $ | 95 |
|
| $ | 100 |
|
December 31, 2012 |
| $ | 95 |
|
| $ | 99 |
|
| $ | 113 |
|
December 31, 2013 |
| $ | 144 |
|
| $ | 129 |
|
| $ | 147 |
|
December 31, 2014 |
| $ | 37 |
|
| $ | 114 |
|
| $ | 164 |
|
December 31, 2015 |
| $ | 8 |
|
| $ | 85 |
|
| $ | 163 |
|
* | 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. |
42
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, 2015, 2014, 2013, 2012 and 2011. 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, 2015 and 2014 and for each of the years ended December 31, 2015, 2014 and 2013, included elsewhere in this report. These selected combined historical financial results may not be indicative of our future financial or operating results.
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) |
| |||||||||||||||||
|
| 2015 |
|
| 2014 |
|
| 2013 |
|
| 2012 |
|
| 2011 |
| |||||
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Natural Gas and NGL Sales |
| $ | 171,951 |
|
| $ | 297,869 |
|
| $ | 213,919 |
|
| $ | 134,574 |
|
| $ | 111,879 |
|
Other Revenue |
|
| 42 |
|
|
| 118 |
|
|
| 200 |
|
|
| 218 |
|
|
| 209 |
|
Total Operating Revenue |
|
| 171,993 |
|
|
| 297,987 |
|
|
| 214,119 |
|
|
| 134,792 |
|
|
| 112,088 |
|
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
|
| 118,999 |
|
|
| 100,282 |
|
|
| 62,150 |
|
|
| 47,638 |
|
|
| 33,116 |
|
General and Administrative Expense |
|
| 29,435 |
|
|
| 36,137 |
|
|
| 30,839 |
|
|
| 22,458 |
|
|
| 23,110 |
|
(Gain) Loss on Disposal of Assets |
|
| (477 | ) |
|
| 644 |
|
|
| 1,602 |
|
|
| 50 |
|
|
| 353 |
|
Impairment Expense |
|
| 345,775 |
|
|
| 132,618 |
|
|
| 32,072 |
|
|
| 20,571 |
|
|
| 14,316 |
|
Exploration Expense |
|
| 3,011 |
|
|
| 9,446 |
|
|
| 11,408 |
|
|
| 4,782 |
|
|
| 2,507 |
|
Depreciation, Depletion, Amortization & Accretion |
|
| 104,744 |
|
|
| 94,467 |
|
|
| 62,386 |
|
|
| 44,955 |
|
|
| 27,671 |
|
Other Operating Expense |
|
| 5,595 |
|
|
| 134 |
|
|
| 592 |
|
|
| 1,136 |
|
|
| 819 |
|
Total Operating Expenses |
|
| 607,082 |
|
|
| 373,728 |
|
|
| 201,049 |
|
|
| 141,590 |
|
|
| 101,892 |
|
Income (Loss) from Operations |
|
| (435,089 | ) |
|
| (75,741 | ) |
|
| 13,070 |
|
|
| (6,798 | ) |
|
| 10,196 |
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
| (47,806 | ) |
|
| (36,977 | ) |
|
| (22,676 | ) |
|
| (6,418 | ) |
|
| (2,514 | ) |
Gain (Loss) on Derivatives, Net |
|
| 60,176 |
|
|
| 38,876 |
|
|
| (2,908 | ) |
|
| 10,687 |
|
|
| 18,916 |
|
Other Income (Expense) |
|
| (115 | ) |
|
| 90 |
|
|
| 6,739 |
|
|
| 98,653 |
|
|
| 10 |
|
Gain (Loss) on Equity Method Investments |
|
| (411 | ) |
|
| (813 | ) |
|
| (763 | ) |
|
| (3,921 | ) |
|
| 81 |
|
Total Other Income (Expense) |
|
| 11,844 |
|
|
| 1,176 |
|
|
| (19,608 | ) |
|
| 99,001 |
|
|
| 16,493 |
|
Income (Loss) from Continuing Operations Before Income Tax |
|
| (423,245 | ) |
|
| (74,565 | ) |
|
| (6,538 | ) |
|
| 92,203 |
|
|
| 26,689 |
|
Income Tax Benefit (Expense) |
|
| 24,227 |
|
|
| 26,915 |
|
|
| 4,154 |
|
|
| (37,282 | ) |
|
| (8,405 | ) |
Income (Loss) from Continuing Operations |
|
| (399,018 | ) |
|
| (47,650 | ) |
|
| (2,384 | ) |
|
| 54,921 |
|
|
| 18,284 |
|
Income (Loss) from Discontinued Operations, Net of Income Taxes |
|
| 37,985 |
|
|
| 5,000 |
|
|
| 1,811 |
|
|
| (8,623 | ) |
|
| (33,660 | ) |
Net Income (Loss) |
|
| (361,033 | ) |
|
| (42,650 | ) |
|
| (573 | ) |
|
| 46,298 |
|
|
| (15,376 | ) |
Net Income (Loss) Attributable to Noncontrolling Interests |
|
| 2,245 |
|
|
| 4,039 |
|
|
| 1,557 |
|
|
| 819 |
|
|
| (7 | ) |
Net Income (Loss) Attributable to Rex Energy |
|
| (363,278 | ) |
|
| (46,689 | ) |
|
| (2,130 | ) |
|
| 45,479 |
|
|
| (15,369 | ) |
Preferred Stock Dividends |
|
| 9,660 |
|
|
| 2,335 |
|
|
| - |
|
|
| - |
|
|
| - |
|
Net Income (Loss) Attributable to Common Shareholders |
| $ | (372,938 | ) |
| $ | (49,024 | ) |
| $ | (2,130 | ) |
| $ | 45,479 |
|
| $ | (15,369 | ) |
Earnings per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic - Net Income (Loss) From Continuing Operations Attributable to Rex Energy Common Shareholders |
| $ | (7.51) |
|
| $ | (0.94 | ) |
| $ | (0.05 | ) |
| $ | 1.06 |
|
| $ | 0.42 |
|
43
|
| Year Ended December 31, |
| |||||||||||||||||
|
| ($ in Thousands) |
| |||||||||||||||||
|
| 2015 |
|
| 2014 |
|
| 2013 |
|
| 2012 |
|
| 2011 |
| |||||
Cash Flow Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash provided by operating activities |
| $ | 30,885 |
|
| $ | 162,706 |
|
| $ | 108,316 |
|
| $ | 45,705 |
|
| $ | 64,507 |
|
Cash used in investing activities |
|
| (155,446) |
|
|
| (560,036 | ) |
|
| (313,518 | ) |
|
| (100,742 | ) |
|
| (276,574 | ) |
Cash provided by financing activities |
|
| 107,556 |
|
|
| 413,526 |
|
|
| 163,127 |
|
|
| 87,216 |
|
|
| 212,855 |
|
Balance Sheet Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
|
| 1,091 |
|
|
| 17,978 |
|
|
| 1,307 |
|
|
| 43,234 |
|
|
| 11,423 |
|
Property and Equipment (net of Accumulated Depreciation) |
|
| 1,001,215 |
|
|
| 1,224,208 |
|
|
| 892,006 |
|
|
| 650,735 |
|
|
| 479,624 |
|
Total Assets |
|
| 1,098,506 |
|
|
| 1,401,721 |
|
|
| 991,396 |
|
|
| 772,710 |
|
|
| 601,551 |
|
Current Liabilities, including current portion of long-term debt |
|
| 97,808 |
|
|
| 147,831 |
|
|
| 100,013 |
|
|
| 56,501 |
|
|
| 63,505 |
|
Long-Term Liabilities |
|
| 840,467 |
|
|
| 722,517 |
|
|
| 474,458 |
|
|
| 303,915 |
|
|
| 245,772 |
|
Total Liabilities |
|
| 938,275 |
|
|
| 870,348 |
|
|
| 574,471 |
|
|
| 360,416 |
|
|
| 309,277 |
|
Noncontrolling Interests |
|
| — |
|
|
| 4,241 |
|
|
| 2,042 |
|
|
| 775 |
|
|
| 275 |
|
Stockholders' Equity |
|
| 160,231 |
|
|
| 531,373 |
|
|
| 416,925 |
|
|
| 412,294 |
|
|
| 292,274 |
|
Other Financial Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
EBITDAX from Continuing Operations1 |
|
| 84,861 |
|
|
| 13,758 |
|
|
| 168,127 |
|
|
| 52,186 |
|
|
| 168,363 |
|
1 | A non-GAAP financial measure. 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.” |
44
Summary Operating and Reserve Data
The following table summarizes our operating and reserve data as of and for each of the periods indicated for continuing operations. The table includes the non-GAAP financial measure of PV-10. For a definition of PV-10 and a reconciliation to the standardized measure of discounted future net cash flow, its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Non-GAAP Financial Measures” below.
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Production |
|
|
|
|
|
|
|
|
|
|
|
|
Oil (Bbls) |
|
| 1,132,118 |
|
|
| 1,141,106 |
|
|
| 914,232 |
|
Natural Gas (Mcf) |
|
| 44,606,753 |
|
|
| 37,011,177 |
|
|
| 23,446,755 |
|
C3+ NGLs (Bbls) |
|
| 2,026,321 |
|
|
| 1,531,131 |
|
|
| 819,670 |
|
Ethane (Bbls) |
|
| 1,319,582 |
|
|
| 551,315 |
|
|
| — |
|
Mcf Equivalent (Mcfe) |
|
| 71,474,879 |
|
|
| 56,352,489 |
|
|
| 33,850,167 |
|
Oil and Natural Gas Sales (thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sales |
| $ | 47,312 |
|
| $ | 97,426 |
|
| $ | 86,959 |
|
Natural Gas Sales |
| $ | 83,140 |
|
| $ | 126,500 |
|
| $ | 87,078 |
|
C3+ NGL Sales |
| $ | 32,789 |
|
| $ | 69,626 |
|
| $ | 39,882 |
|
Ethane Sales |
| $ | 8,710 |
|
| $ | 4,317 |
|
| $ | — |
|
Total |
| $ | 171,951 |
|
| $ | 297,869 |
|
| $ | 213,919 |
|
Average Sales Price (a) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil ($ per Bbl) |
| $ | 41.79 |
|
| $ | 85.38 |
|
| $ | 95.12 |
|
Natural Gas ($ per Mcf) |
| $ | 1.86 |
|
| $ | 3.42 |
|
| $ | 3.71 |
|
C3+ NGLs ($ per Bbl) |
| $ | 16.18 |
|
| $ | 45.47 |
|
| $ | 48.66 |
|
Ethane ($ per Bbl) |
| $ | 6.60 |
|
| $ | 7.83 |
|
| $ | — |
|
Mcf Equivalent ($ per Mcfe) |
| $ | 2.41 |
|
| $ | 5.29 |
|
| $ | 6.32 |
|
Average Production Cost |
|
|
|
|
|
|
|
|
|
|
|
|
Mcf Equivalent ($ per Mcfe) |
| $ | 1.66 |
|
| $ | 1.78 |
|
| $ | 1.84 |
|
Estimated Proved Reserves (b) |
|
|
|
|
|
|
|
|
|
|
|
|
Bcf Equivalent (Bcfe) |
|
| 680.4 |
|
|
| 1,336.8 |
|
|
| 849.8 |
|
% Oil and NGL |
|
| 40 | % |
|
| 37 | % |
|
| 39 | % |
% Proved Producing |
|
| 80 | % |
|
| 40 | % |
|
| 41 | % |
PV-10 (millions) |
| $ | 300.7 |
|
| $ | 1,205.2 |
|
| $ | 668.7 |
|
Standardized Measure (millions) |
| $ | 255.6 |
|
| $ | 1,025.4 |
|
| $ | 529.1 |
|
(a) | Information excludes the impact of our financial derivative activities. |
(b) | 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 estimated present value of estimated proved reserves does not give effect to indirect expenses such as debt service and future income tax expense, asset retirement obligations, or to depletion, depreciation and amortization. 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. Also, the use of a 10% discount factor for reporting purposes may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. |
Non-GAAP Financial Measures
We include in this report our calculations of EBITDAX and PV-10, which are non-GAAP financial measures. Below, we provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measure as calculated and presented in accordance with GAAP.
45
“EBITDAX” means, for any period, the sum of net income (loss) for such period plus the following expenses, charges or income to the extent deducted from or added to net income (loss) in such period: interest, income taxes, gain (loss) on asset sales, depreciation, depletion, amortization, unrealized losses from financial derivatives, the retroactive portion of the Pennsylvania Impact Fee, exploration expenses and other non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income (loss). EBITDAX, as defined above, is used as a financial measure by our management team and by other users of our financial statements, such as our commercial bank lenders, to analyze such things as:
| â—Ź | Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure; |
| â—Ź | The financial performance of our assets and valuation of the entity without regard to financing methods, capital structure or historical cost basis; |
| â—Ź | Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and |
| â—Ź | The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
EBITDAX is not a calculation based on GAAP financial measures and should not be considered as an alternative to net income (loss) in measuring our performance, nor used as an exclusive measure of cash flow, because it does not consider the impact of working capital growth, capital expenditures, debt principal reductions, and other sources and uses of cash, which are disclosed in our statements of cash flows.
We have reported EBITDAX because it is a financial measure used by our existing commercial lenders, and we believe this measure is commonly reported and widely used by investors as an indicator of a company’s operating performance and ability to incur and service debt. You should carefully consider the specific items included in our computations of EBITDAX. While we have disclosed our EBITDAX to permit a more complete comparative analysis of our operating performance and debt servicing ability relative to other companies, you are cautioned that EBITDAX as reported by us may not be comparable in all instances to EBITDAX as reported by other companies. EBITDAX amounts may not be fully available for management’s discretionary use, due to requirements to conserve funds for capital expenditures, debt service and other commitments.
We believe EBITDAX assists our lenders and investors in comparing a company’s performance on a consistent basis without regard to certain expenses, which can vary significantly depending upon accounting methods. Because we may borrow money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Additionally, we are required to pay federal and state taxes, which are necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations.
To compensate for these limitations, we believe it is important to consider both net income determined under GAAP and EBITDAX to evaluate our performance.
46
The following table presents a reconciliation of our net income (loss) to our EBITDAX for each of the periods presented. For purposes of consistency with current calculations, we have revised certain amounts relating to prior period EBITDAX.
|
| Year Ended December 31, |
| |||||||||||||||||
|
| (in thousands) |
| |||||||||||||||||
|
| 2015 |
|
| 2014 |
|
| 2013 |
|
| 2012 |
|
| 2011 |
| |||||
Net Income (Loss) from Continuing Operations |
| $ | (399,018 | ) |
| $ | (47,650 | ) |
| $ | (2,384 | ) |
| $ | 54,921 |
|
| $ | 18,284 |
|
Add Back Non-Recurring Losses1 |
|
| 4,774 |
|
|
| - |
|
|
| - |
|
|
| 2,809 |
|
|
| - |
|
Add Back Depletion, Depreciation, Amortization and Accretion |
|
| 104,744 |
|
|
| 94,467 |
|
|
| 62,386 |
|
|
| 44,955 |
|
|
| 27,671 |
|
Add Back Non-Cash Compensation Expense |
|
| 6,450 |
|
|
| 5,672 |
|
|
| 5,384 |
|
|
| 3,140 |
|
|
| 1,601 |
|
Add Back Interest Expense |
|
| 47,806 |
|
|
| 36,977 |
|
|
| 22,676 |
|
|
| 6,418 |
|
|
| 2,514 |
|
Add Back Impairment Expense |
|
| 345,775 |
|
|
| 132,618 |
|
|
| 32,072 |
|
|
| 20,571 |
|
|
| 14,316 |
|
Add Back Exploration Expense |
|
| 3,011 |
|
|
| 9,446 |
|
|
| 11,408 |
|
|
| 4,782 |
|
|
| 2,507 |
|
Add (Less) Back (Gain) Loss on Disposal of Asset2 |
|
| (477 | ) |
|
| 644 |
|
|
| (5,204 | ) |
|
| (99,333 | ) |
|
| 353 |
|
Add (Less) Back (Gain) Loss on Financial Derivatives |
|
| (60,176 | ) |
|
| (38,876 | ) |
|
| 2,908 |
|
|
| (10,687 | ) |
|
| (18,916 | ) |
Add Back Cash Settlement of Derivatives |
|
| 55,793 |
|
|
| 7,281 |
|
|
| 7,128 |
|
|
| 16,219 |
|
|
| 6,212 |
|
Add Back Non-Cash Portion of Equity Method Investments |
|
| 406 |
|
|
| 805 |
|
|
| 752 |
|
|
| 4,471 |
|
|
| 2,258 |
|
Less Non-Cash Portion of Noncontrolling Interests |
|
| - |
|
|
| - |
|
|
| - |
|
|
| (32 | ) |
|
| - |
|
Add Back (Less) Income Tax Expense (Benefit) |
|
| (24,227 | ) |
|
| (26,915 | ) |
|
| (4,154 | ) |
|
| 37,282 |
|
|
| 8,405 |
|
EBITDAX from Continuing Operations |
| $ | 84,861 |
|
| $ | 174,469 |
|
| $ | 132,972 |
|
| $ | 85,516 |
|
| $ | 65,205 |
|
Income (Loss) from Discontinued Operations |
| $ | 37,985 |
|
| $ | 5,000 |
|
| $ | 1,811 |
|
| $ | (8,623 | ) |
| $ | (33,660 | ) |
Net (Income) Loss Attributable to Noncontrolling Interests |
|
| (2,245 | ) |
|
| (4,039 | ) |
|
| (1,557 | ) |
|
| (819 | ) |
|
| 7 |
|
Income (Loss) From Discontinued Operations Attributable to Rex Energy |
|
| 35,740 |
|
|
| 961 |
|
|
| 254 |
|
|
| (9,442 | ) |
|
| (33,653 | ) |
Add Back Depletion, Depreciation, Amortization and Accretion |
|
| 78 |
|
|
| 3,703 |
|
|
| 1,559 |
|
|
| 482 |
|
|
| 270 |
|
Add Back (Less) Non-Cash Compensation Expense (Income) |
|
| - |
|
|
| - |
|
|
| - |
|
|
| (31 | ) |
|
| 24 |
|
Add Back Interest Expense |
|
| 487 |
|
|
| 629 |
|
|
| 106 |
|
|
| 25 |
|
|
| 1 |
|
Add Back Impairment Expense |
|
| - |
|
|
| 67 |
|
|
| - |
|
|
| 19,784 |
|
|
| 13,491 |
|
Add Back Exploration Expense |
|
| - |
|
|
| - |
|
|
| 97 |
|
|
| 867 |
|
|
| 33,812 |
|
Add (Less) Back (Gain) Loss on Disposal of Asset3 |
|
| (57,808 | ) |
|
| (55 | ) |
|
| (924 | ) |
|
| (2,142 | ) |
|
| 149 |
|
Less Non-Cash Portion of Noncontrolling Interests |
|
| (208 | ) |
|
| (1,738 | ) |
|
| (631 | ) |
|
| (108 | ) |
|
| (157 | ) |
Add Back (Less) Income Tax Expense (Benefit) |
|
| 24,227 |
|
|
| 768 |
|
|
| 1,373 |
|
|
| (7,222 | ) |
|
| (15,437 | ) |
EBITDAX from Discontinued Operations |
| $ | 2,516 |
|
| $ | 4,335 |
|
| $ | 1,834 |
|
| $ | 2,213 |
|
| $ | (1,500 | ) |
EBITDAX |
| $ | 87,377 |
|
| $ | 178,804 |
|
| $ | 134,806 |
|
| $ | 87,729 |
|
| $ | 63,705 |
|
1 | Non-Recurring Costs for the year ended December 31, 2015 are due to net fees incurred to terminate two drilling rig contracts earlier than their original term. Non-Recurring Costs for the year ended December 31, 2012 are due to $2.8 million related to the retroactive portion of the Pennsylvania Impact Fee. |
2 | Includes gain on sale of Keystone Midstream Services, LLC of approximately $6.9 million and $99.4 million for the years ended December 31, 2013 and 2012, respectively. |
3 | Includes gain on sale of Water Solutions of approximately $57.8 million for the year ended December 31, 2015. |
PV-10
The following table shows the reconciliation of PV-10 to our standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 represents our estimate of 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. Our estimated future cash flows as of December 31, 2015, 2014 and 2013, 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 the prevailing economic conditions. The estimated future production for the years ended December 31, 2015, 2014 and 2013, was priced based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the period January through December, without escalation, using $44.45 per Bbl, $88.02 per Bbl and $94.28 per Bbl of oil, respectively, and $2.401 per MMBtu, $3.455 per MMBtu and $3.588 per MMBtu of natural gas, respectively, as adjusted by lease for transportation fees and regional price differentials. Unadjusted prices for oil for the years ended December 31, 2015, 2014 and 2013, were $46.79 per Bbl, $91.48 per Bbl and $93.42, respectively. Unadjusted prices for natural gas for the years ended December 31, 2015, 2014 and 2013, were $2.587 per MMBtu, $4.35 per MMBtu and $$3.67 per MMBtu, respectively. NGLs were priced at $12.48 per Bbl, $28.30 per Bbl and $26.37 per Bbl for
47
the years ended December 31, 2015, 2014 and 2013, respectively, as adjusted by lease for transportation fees and regional price differentials. Management believes that 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. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for evaluating our company. PV-10 should not be considered to be a superior measure to the standardized measure of discounted future net cash flows as computed under GAAP.
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Reconciliation of standardized measure to PV-10 (in millions) |
|
|
|
|
|
|
|
|
|
|
|
|
PV-10 |
| $ | 300.7 |
|
| $ | 1,205.2 |
|
| $ | 668.7 |
|
Less: Present value of future income tax discounted at 10% |
|
| - |
|
|
| (139.7 | ) |
|
| (111.1 | ) |
Less: Present value of future asset retirement obligations discounted at 10% |
|
| (45.1 | ) |
|
| (40.1 | ) |
|
| (28.5 | ) |
Standardized measure of discounted future net cash flows |
| $ | 255.6 |
|
| $ | 1,025.4 |
|
| $ | 529.1 |
|
48
The following discussion and analysis should be read in conjunction with “Item 6. Selected Financial Data” and the Consolidated Financial Statements and related notes included elsewhere in this report. This discussion contains forward-looking statements reflecting our current expectations and estimates, and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Cautionary Note Regarding Forward-Looking Statements” and “Item 1A. Risk Factors” appearing elsewhere in this report. All financial and operating data presented are the results of continuing operations unless otherwise noted.
Overview of Our Business
We are an independent oil, NGL and natural gas company operating in the Appalachian Basin and Illinois Basin. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Burkett Shale drilling and exploration activities. In the Illinois Basin, we are focused on our developmental oil drilling on our properties. 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 regional offices in Bridgeport, Illinois; Cranberry, Pennsylvania; and Carrolton, Ohio.
We believe the outlook for our business is favorable despite the continued uncertainty of oil and gas prices. Our resource base, risk management, including an active hedging program, and disciplined investment of capital provide us with an opportunity to exploit and develop our positions and maximize efficiency in our key operating areas. We continue to focus on maintaining financial flexibility while pursuing an active, technology-driven drilling program to develop and maximize the value of our existing acreage as market conditions continue to evolve. However, a continued prolonged period of depressed commodity prices could have a significant impact on the value and volumetric quantities of our proved reserves, and may result in write-downs of the carrying values of our oil and natural gas properties and revisions to our capital budget or development program. We discuss these matters in further detail under, among other places, “—Capital Resources and Liquidity,” and “—Volatility of Oil, NGL and Natural Gas Prices” below as well as in Note 16, Impairment Expense, to our Consolidated Financial Statements
We have historically divided our operations into two principal business segments, exploration and production and field services. During the third quarter of 2015, we sold Water Solutions and its related subsidiaries, which accounted for the majority of our field services segment. We view the activities of Water Solutions as non-core to our exploration and production operations and used the proceeds from the sale to fund development within our exploration and production operations. Unless otherwise noted, information presented herein is for continuing operations.
Our financial results from exploration and production depend upon many factors, particularly the price of oil, natural gas and NGLs. Commodity prices are affected by changes in market demand, which is impacted by overall economic activity, weather, refinery or pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future commodity prices, and therefore, we cannot determine what effect increases or decreases will have on our capital program, production volumes and future revenues. In addition to production volumes and commodity prices, finding and developing sufficient amounts of oil, natural gas and NGLs reserves at economical costs are critical to our long-term success.
In 2015, we grew our daily production by 26.8% year-over-year to 195.8 Mmcfe/day. The increase in production is primarily due to our successes in the Appalachian Basin, particularly our Marcellus Shale exploration and development in Butler County, Pennsylvania and our Utica Shale exploration and development in Ohio. We drilled 34.0 gross (23.0 net) operated wells within the Appalachian Basin, targeting primarily the Marcellus and Utica Shales, including 28.0 gross (17.0 net) operated wells in Butler County, Pennsylvania and six gross (six net) operated wells in Ohio. In the Illinois Basin, we drilled, or participated in the drilling of, five gross (3.5 net) conventional wells. During 2015, we had a drilling success rate of 96.0%, which included two dry hole exploratory wells in the Illinois Basin. Our estimated proved reserves decreased in 2015 by 49.1% from 1,336.8 Bcfe at December 31, 2014 to 680.4 Bcfe at December 31, 2015, primarily as a result of the deterioration of the commodity price environment. As of December 31, 2015, we had approximately 383,500 gross (319,700 net) acres in the Appalachian Basin, of which 299,000 gross (272,200 net) acres we believe to be prospective for the liquids-rich portion of the Marcellus and Utica Shales.
In July 2015, we sold Water Solutions, an entity of which we owned a 60% interest, to American Water Works Company, Inc. for total consideration of approximately $130.0 million, inclusive of cash and debt. We received net proceeds of approximately $66.8 million, resulting in a gain of approximately $57.8 million. We utilized the proceeds from this transaction to help fund development
49
within our core exploration and production areas. In March 2015, we entered into a joint venture agreement with an affiliate of ArcLight to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. We expect to receive consideration for the transaction of approximately $67.0 million, with $16.6 million received at closing. As of December 31, 2015, ArcLight had paid approximately $42.9 million for their interest in wells that have been drilled or are in the process of being drilled.
In 2014, we grew our daily production by 66.5% year-over-year to 154.4 Mmcfe/day. The increase in production is primarily due to our successes in the Appalachian Basin, particularly our Marcellus Shale exploration and development in Butler County, Pennsylvania and our Utica Shale exploration and development in Ohio. We drilled 51.0 gross (37.6 net) operated wells within the Appalachian Basin, targeting primarily the Marcellus and Utica shales, including 38.0 gross (26.6 net) operated wells in Butler County, Pennsylvania and 12.0 gross (10.6 net) operated wells in Ohio. In the Illinois Basin, we drilled, or participated in the drilling of, 18.0 gross (12.0 net) conventional wells. With a drilling success rate of 96.0% in 2014, which included three dry hole exploratory wells in the Illinois Basin, we increased proved reserves by 57.3% from 849.9 Bcfe at December 31, 2013 to 1,336.8 Bcfe at December 31, 2014. As of December 31, 2014, we had approximately 407,200 gross (339,500 net) acres in the Appalachian Basin, of which 324,300 gross (295,200 net) acres are believed to be prospective for the liquids-rich portion of the Marcellus and Utica Shales.
In July 2014, we issued a $325.0 million aggregate principal amount of 6.25% senior notes due 2022 (the “2022 Senior Notes”) in a private offering at an issue price of 100.0% due to mature on August 1, 2022. The net proceeds of the 2022 Senior Notes, after discounts and expenses, were approximately $318.8 million. In August 2014, we completed a registered offering of 16,100 shares of 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (the “Series A Preferred Stock”) that are represented by 1,610,000 depositary shares. The net proceeds of the offering were approximately $155.0 million, after deducting underwriting discounts, commissions and other offering expenses.
In September 2014, we completed the acquisition of approximately 208,000 gross (207,000 net) acres believed to be prospective for the Marcellus, Upper Devonian/Burkett and Utica Shales from Shell, for approximately $120.6 million in cash, after customary closing adjustments. Included in the acquisition were several producing wells and properties in various stages of development. The assets acquired are located in Armstrong, Beaver, Butler, Lawrence, Mercer and Venango counties in Pennsylvania and Columbiana and Mahoning counties in Ohio.
In 2013, we grew our daily production by 38.2% year-over-year to 92.7 Mmcfe/ day. The increase in production is primarily due to our successes in the Appalachian Basin, particularly our Marcellus Shale exploration and development in Butler County, Pennsylvania and our Utica Shale exploration and development in Ohio. We drilled 33.0 gross (26.1 net) operated wells within the Appalachian Basin, targeting primarily the Marcellus and Utica Shales, including 19.0 gross (13.3 net) operated wells in Butler County, Pennsylvania and 14.0 gross (12.8 net) operated wells in Ohio. In the Illinois Basin, we drilled 19.0 gross (19.0 net) operated 53 conventional wells. With a drilling success rate of 96.7% in 2013, which included two dry hole exploratory wells in the Illinois Basin, we increased proved reserves by 37.5% from 618.1 Bcfe at December 31, 2012 to 849.9 Bcfe at December 31, 2013. As of December 31, 2013, we had approximately 183,500 gross (113,600 net) acres in the Appalachian Basin, of which 109,900 gross (82,400 net) acres that are prospective for the liquids-rich portion of the Marcellus and Utica Shales.
In April 2013, we issued $100.0 million aggregate principal amount of 8.875% senior notes due 2020 in a private offering at an issue price of 105% due to mature December 1, 2020. These notes were an additional issue of our outstanding 8.875% senior notes due 2020, issued in an aggregate principal amount of $250.0 million in December 2012. The net proceeds of this offering, after discounts and expense were approximately $102.8 million, excluding accrued interest.
50
We generate our revenue primarily from the sale of crude oil, NGLs and natural gas. Our operating revenue before the effects of financial derivatives from these operations, and their relative percentages of our total revenue, consisted of the following:
|
| Year Ended December 31, |
| |||||||||||||||||||||
|
| 2015 |
|
| % of Total |
|
| 2014 |
|
| % of Total |
|
| 2013 |
|
| % of Total |
| ||||||
Sources of Revenue ($ in thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenue from Oil Sales |
| $ | 47,312 |
|
|
| 27.5 | % |
| $ | 97,426 |
|
|
| 32.7 | % |
| $ | 86,959 |
|
|
| 40.6 | % |
Revenue from Natural Gas Sales |
|
| 83,140 |
|
|
| 48.3 | % |
|
| 126,500 |
|
|
| 42.5 | % |
|
| 87,078 |
|
|
| 40.7 | % |
Revenue from C3+ NGL Sales |
|
| 32,789 |
|
|
| 19.1 | % |
|
| 69,626 |
|
|
| 23.4 | % |
|
| 39,882 |
|
|
| 18.6 | % |
Revenue from Ethane Sales |
|
| 8,710 |
|
|
| 5.1 | % |
|
| 4,317 |
|
|
| 1.4 | % |
|
| — |
|
|
| 0.0 | % |
Other |
|
| 42 |
|
|
| 0.0 | % |
|
| 118 |
|
|
| 0.0 | % |
|
| 200 |
|
|
| 0.1 | % |
Total |
| $ | 171,993 |
|
|
| 100.0 | % |
| $ | 297,987 |
|
|
| 100.0 | % |
| $ | 214,119 |
|
|
| 100.0 | % |
We have identified the impact of generally volatile commodity prices in the last several years as an important trend that we expect to affect our business in the future. If commodity prices increase, we would expect not only an increase in revenue, but also in the competitive environment for quality drilling prospects, qualified geological and technical personnel and oil field services, including rig availability. Increasing competition in these areas would likely result in higher costs in these areas, and could result in unavailability of drilling rigs, thus affecting the profitability of our future operations. We may not be able to compete successfully in the future with larger competitors in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. In the event of a further or extended decline in the commodity price environment, our revenues would decrease and we would anticipate that the cost of materials and services would decrease as well, although at a slower rate. Decreasing oil or natural gas prices may also make some of our prospects uneconomical to drill and some of our producing properties uneconomic to continue to operate.
Principal Components of Our Cost Structure
Our operating and other expenses consist of the following:
| â—Ź | Production and Lease Operating Expenses. Day-to-day costs incurred to bring hydrocarbons out of the ground and to the market together with the daily costs incurred to maintain our producing properties. Such costs also include repairs to our oil and gas properties not covered by insurance, and various production taxes that are paid based upon rates set by federal, state, and local taxing authorities. |
| â—Ź | General and Administrative Expenses. Overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters and regional offices, costs of managing our production and development operations, audit and other professional fees, and legal compliance are included in general and administrative expense. General and administrative expense includes non-cash stock-based compensation expense as part of employee compensation. |
| â—Ź | Exploration Expenses. Geological and geophysical costs, seismic costs, delay rentals and the costs of unsuccessful exploratory wells, also known as dry holes. |
| â—Ź | Interest. We typically finance a portion of our working capital requirements and leasehold acquisitions with borrowings under our senior credit facility or with senior notes. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. We may continue to incur significant interest expense as we continue to grow. |
| â—Ź | Depreciation, Depletion, Amortization and Accretion. The systematic expensing of the capital costs incurred to acquire, explore and develop natural gas and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and apportion these costs to each unit of production through depreciation, depletion and amortization expense. This also includes the systematic, monthly accretion of the future abandonment costs of tangible assets such as wells, service assets, pipelines, and other facilities. |
| â—Ź | Income Taxes. We are subject to state and federal income taxes. We do pay some state and federal income taxes where our IDC deductions do not exceed our taxable income or where state income taxes are determined on another basis. |
51
How We Evaluate Our Operations
Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include EBITDAX (a non-GAAP measure), lease operating expense per Mcf equivalent (“Mcfe”), growth in our proved reserve base, and general and administrative expense per Mcfe. The following table presents these metrics for continuing operations for each of the three years ended December 31, 2015, 2014 and 2013.
|
| Performance Measurements |
| |||||||||
|
| For the Years Ended December 31, |
| |||||||||
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
EBITDAX ($ in thousands) |
| $ | 84,861 |
|
| $ | 174,469 |
|
| $ | 132,972 |
|
Lease Operating Expense per Mcfe |
| $ | 1.66 |
|
| $ | 1.78 |
|
| $ | 1.84 |
|
Total Estimated Proved Reserves (Bcfe) |
|
| 680.4 |
|
|
| 1,336.8 |
|
|
| 849.8 |
|
G&A per Mcfe |
| $ | 0.41 |
|
| $ | 0.64 |
|
| $ | 0.98 |
|
EBITDAX
“EBITDAX,” a non-GAAP measure, means, for any period, the sum of net income (loss) for such period plus the following expenses, charges or income (loss) to the extent deducted from or added to net income (loss) in such period: interest, income taxes, gain (loss) on sale of assets, depreciation, depletion, amortization, unrealized losses from financial derivatives, exploration expenses and other non-cash charges, minus all non-cash income, including but not limited to, income from unrealized financial derivatives, added to net income (loss). EBITDAX, as defined above, is used as a financial measure by our management team and by other users of our financial statements, such as our commercial bank lenders, to analyze such things as:
| â—Ź | Our operating performance and return on capital in comparison to those of other companies in our industry, without regard to financial or capital structure; |
| â—Ź | The financial performance of our assets and valuation of the entity, without regard to financing methods, capital structure or historical cost basis; |
| â—Ź | Our ability to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our stockholders; and |
| â—Ź | The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities. |
For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Item 6. Selected Financial Data-Non-GAAP Financial Measures.”
The decrease in our EBITDAX from 2014 to 2015 can be primarily attributable to the continued depressed commodity price environment, which has been partially offset by increased production and lower operating costs. Historically, our EBITDAX growth has been commensurate with the growth of our Appalachian Basin operations, where we have been successful in our exploration and development of three producing horizons: the Marcellus, Utica and Burkett Shales. The majority of our holdings in the Appalachian Basin have a liquids-producing component which, when combined with low operating costs, has enabled us to consistently improve our results. In addition, our Illinois Basin properties have continued to provide stable cash flows with 100.0% oil production.
Production Cost per Mcfe
Production costs are comprised of those expenses which are directly attributable to our producing oil and gas leases, including state and county production taxes, production related insurance, the cost of materials, maintenance, electricity, chemicals, gathering, processing, fuel and the wages of our field personnel. Our production costs per Mcfe are higher than those of many of our peers primarily because of the nature of our oil properties, many of which are mature waterflood properties, and because of processing costs related to our liquids-rich production. Our production cost per Mcfe produced in 2015 was $1.66, as compared to $1.78 in 2014 and $1.84 in 2013. Because our production mix is heavily weighted toward liquids-rich production in the Appalachian Basin, we do not expect to experience large decreases in production costs per Mcfe in the future.
52
Growth in our Proved Reserve Base
We measure our ability to grow our estimated proved reserves over the amount of our total annual production. As we produce oil, NGLs and natural gas attributable to our estimated proved reserves, our estimated proved reserves decrease each year by that amount of production. We attempt to replace these produced estimated proved reserves each year through the addition of new estimated proved reserves through our drilling and other property improvement projects and through acquisitions. Our reserve replacement ratio for year end 2013 was approximately 923% based on total production for the year of 33.9 Bcfe and extensions, discoveries and other additions of 312.5 Bcfe. Our reserve replacement ratio for year end 2014 was approximately 972% based on total production for the year of 56.4 Bcfe, and extensions, discoveries and other additions of 547.9 Bcfe. Our reserve replacement ratio for year end 2015 was approximately 200% based on total production for the year of 71.5 Bcfe, and extensions, discoveries and other additions of 143.0 Bcfe. For 2015, our proved reserve base in the Appalachian Basin decreased by approximately 49.1% while our estimated proved reserves in the Illinois Basin decreased by 51.9%. The decrease in our estimated proved reserves is primarily due to the decrease in commodity prices during 2015.
General and Administrative Expenses per Mcfe
Our general and administrative expenses include fees for well operating services, non-field level employee compensation and related benefits, office and lease expenses, insurance costs and professional fees, as well as other costs and expenses not directly related to field operations. Our management continually evaluates the level of our general and administrative expenses in relation to our production because these expenses have a direct impact on our profitability. In 2015, our general and administrative expenses per Mcfe produced decreased to $0.41 from $0.64 in 2014 and decreased from $0.98 in 2013.
Pennsylvania Impact Fee
In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee is imposed on every producer of unconventional natural gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. Unconventional gas wells that were spud prior to 2012 are considered to be spud in 2011 for purposes of determining the fee, which is considered year one for those wells. The fee for each unconventional natural gas well is determined using the following matrix, with vertical unconventional natural gas wells being charged 20% of the applicable rates:
|
| <$2.25(a) |
|
| $2.26 - $2.99(a) |
|
| $3.00 - $4.99(a) |
|
| $5.00 - $5.99(a) |
|
| >$5.99(a) |
| |||||
Year One |
| $ | 40,200 |
|
| $ | 45,300 |
|
| $ | 50,300 |
|
| $ | 55,300 |
|
| $ | 60,400 |
|
Year Two |
| $ | 30,200 |
|
| $ | 35,200 |
|
| $ | 40,200 |
|
| $ | 45,300 |
|
| $ | 55,300 |
|
Year Three |
| $ | 25,200 |
|
| $ | 30,200 |
|
| $ | 30,200 |
|
| $ | 40,200 |
|
| $ | 50,300 |
|
Year 4 – 10 |
| $ | 10,100 |
|
| $ | 15,100 |
|
| $ | 20,100 |
|
| $ | 20,100 |
|
| $ | 20,100 |
|
Year 11 – 15 |
| $ | 5,000 |
|
| $ | 5,000 |
|
| $ | 10,100 |
|
| $ | 10,100 |
|
| $ | 10,100 |
|
(a) | Pricing utilized for determining annual fees is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the 12-month period ending December 31. |
For the years ended December 31, 2015, 2014 and 2013, we incurred approximately $3.0 million, $4.1 million and $3.2 million, respectively, in fees related to the natural gas impact fee. We have recorded these fees as Production and Lease Operating Expense on our Consolidated Statement of Operations.
Results of Continuing Operations
General Overview
Operating revenue decreased 42.3% in 2015 over 2014. This decrease was primarily due to lower oil, NGL and natural gas prices, which was partially offset by increased production in the Appalachian Basin. For 2015, total production increased 26.8% to 71,475 MMcfe from 56,352 MMcfe in 2014.
Operating expenses increased $233.4 million in 2015, or 62.4%, as compared to 2014. Operating expenses are primarily composed of production expenses, general and administrative expenses (“G&A”), loss on disposal of assets, exploration expenses, impairment of oil and gas properties and depreciation, depletion, amortization and accretion expenses (“DD&A”). Approximately $213.2 million of this increase is due to impairment expense, which is primarily due to the write down of proved and unproved properties in the Illinois and Appalachian Basins as a result of the sustained depressed commodity price environment. Also
53
contributing to the increase in operating expenses were higher Production and Lease Operating Expenses, DD&A Expenses and Other Operating Expenses. The increase in Production and Lease Operating Expenses is commensurate with our increased well count and production. The increase in DD&A Expenses is attributable to increased levels of production combined with a lower level of estimated proved reserves. The increase in Other Operating Expense is primarily due to fees related to the early cancellation of two drilling rig contracts.
Comparison of the Year Ended December 31, 2015 to the Year Ended December 31, 2014
Oil and gas revenue for the years ended December 31, 2015 and 2014 is summarized in the following table:
|
| For the Year Ended December 31, |
| |||||||||||||
($ in Thousands, except total Mcfe production and price per Mcfe) |
| 2015 |
|
| 2014 |
|
| Change |
|
| % |
| ||||
Oil, NGL and Gas Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales revenue |
| $ | 47,312 |
|
| $ | 97,426 |
|
| $ | (50,114 | ) |
|
| -51.4 | % |
Oil derivatives realized (a) |
| $ | 11,860 |
|
| $ | 1,085 |
|
| $ | 10,775 |
|
|
| 993.1 | % |
Total oil and condensate revenue and derivatives realized |
| $ | 59,172 |
|
| $ | 98,511 |
|
| $ | (39,339 | ) |
|
| -39.9 | % |
Gas sales revenue |
| $ | 83,140 |
|
| $ | 126,500 |
|
| $ | (43,360 | ) |
|
| -34.3 | % |
Gas derivatives realized (a) |
| $ | 32,573 |
|
| $ | 1,637 |
|
| $ | 30,936 |
|
|
| 1889.8 | % |
Total gas revenue and derivatives realized |
| $ | 115,713 |
|
| $ | 128,137 |
|
| $ | (12,424 | ) |
|
| -9.7 | % |
C3+ NGL sales revenue |
| $ | 32,789 |
|
| $ | 69,626 |
|
| $ | (36,837 | ) |
|
| -52.9 | % |
C3+ NGL derivatives realized (a) |
| $ | 10,384 |
|
| $ | 3,247 |
|
| $ | 7,137 |
|
|
| 219.8 | % |
Total C3+ NGL revenue and derivatives realized |
| $ | 43,173 |
|
| $ | 72,873 |
|
| $ | (29,700 | ) |
|
| -40.8 | % |
Ethane sales revenue |
| $ | 8,710 |
|
| $ | 4,317 |
|
| $ | 4,393 |
|
|
| 100.0 | % |
Ethane derivatives realized (a) |
| $ | 42 |
|
| $ | — |
|
| $ | 42 |
|
|
| 0.0 | % |
Total ethane revenue and derivatives realized |
| $ | 8,752 |
|
| $ | 4,317 |
|
| $ | 4,435 |
|
|
| 100.0 | % |
Consolidated sales |
| $ | 171,951 |
|
| $ | 297,869 |
|
| $ | (125,918 | ) |
|
| -42.3 | % |
Consolidated derivatives realized (a) |
| $ | 54,859 |
|
| $ | 5,969 |
|
| $ | 48,890 |
|
|
| 819.1 | % |
Total oil, NGL and gas revenue and derivatives realized |
| $ | 226,810 |
|
| $ | 303,838 |
|
| $ | (77,028 | ) |
|
| -25.4 | % |
Total Mcfe Production |
|
| 71,474,879 |
|
|
| 56,352,489 |
|
|
| 15,122,390 |
|
|
| 26.8 | % |
Average Realized Price per Mcfe, including the effects of derivatives |
| $ | 3.17 |
|
| $ | 6.53 |
|
| $ | (3.36 | ) |
|
| -51.4 | % |
| (a) | Realized derivatives are included in Other Income (Expense) on our Consolidated Statements of Operations. |
Average realized price received for oil, NGLs and natural gas during 2015 was $3.17 per Mcfe, a decrease of 51.4%, or $3.36 per Mcfe, from the prior year. The average realized price for oil, including the effects of derivatives, in 2015 decreased 39.5% or $34.06 per barrel, whereas the average realized price for natural gas, including the effects of derivatives, decreased 25.1%, or $0.87 per Mcf, from 2014. The average realized price for NGLs, including the effects of derivatives, in 2015 decreased 58.1%, or $21.55 per barrel, from 2014. Our derivative activities effectively increased net realized prices by $0.77 per Mcfe in 2015 and $0.11 per Mcfe in 2014.
Production volume for 2015 increased 26.8% from 2014 primarily due to the success of our Marcellus and Utica Shale horizontal drilling activities in the Appalachian Basin, where production increased approximately 30.3%, or 15.6 Bcfe. We placed into service 33.0 gross (17.6 net) wells within the Appalachian Basin, primarily targeting the Marcellus and Utica Shales, during 2015. Production in the Illinois Basin for 2015 decreased by 9.5% to 729,251 barrels as compared to the same period in 2014. The natural decline of our Illinois Basin properties was offset by increased oil production from our infill drilling and recompletion operations in the region. During 2015, we drilled five gross (3.5 net) wells and recompleted seven gross (seven net) wells in the Illinois Basin.
Overall, our production for 2015 averaged approximately 195.8 Mmcfe per day, of which 9.5% was attributable to oil, 28.1% was attributable to NGLs and 62.4% was attributable to natural gas.
54
Statements of Operations for the years ended December 31, 2015 and 2014 are as follows:
|
| For the Year Ended December 31, |
| |||||||||||||
($ in Thousands) |
| 2015 |
|
| 2014 |
|
| Change |
|
| % |
| ||||
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Natural Gas and NGL Sales |
| $ | 171,951 |
|
| $ | 297,869 |
|
| $ | (125,918 | ) |
|
| -42.3 | % |
Other Revenue |
|
| 42 |
|
|
| 118 |
|
|
| (76 | ) |
|
| -64.4 | % |
Total Operating Revenue |
|
| 171,993 |
|
|
| 297,987 |
|
|
| (125,994 | ) |
|
| -42.3 | % |
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
|
| 118,999 |
|
|
| 100,282 |
|
|
| 18,717 |
|
|
| 18.7 | % |
General and Administrative Expense |
|
| 29,435 |
|
|
| 36,137 |
|
|
| (6,702 | ) |
|
| -18.5 | % |
(Gain) Loss on Disposal of Assets |
|
| (477 | ) |
|
| 644 |
|
|
| (1,121 | ) |
|
| -174.1 | % |
Impairment Expense |
|
| 345,775 |
|
|
| 132,618 |
|
|
| 213,157 |
|
|
| 160.7 | % |
Exploration Expense |
|
| 3,011 |
|
|
| 9,446 |
|
|
| (6,435 | ) |
|
| -68.1 | % |
Depreciation, Depletion, Amortization & Accretion |
|
| 104,744 |
|
|
| 94,467 |
|
|
| 10,277 |
|
|
| 10.9 | % |
Other Operating Expense |
|
| 5,595 |
|
|
| 134 |
|
|
| 5,461 |
|
|
| 4075.4 | % |
Total Operating Expenses |
|
| 607,082 |
|
|
| 373,728 |
|
|
| 233,354 |
|
|
| 62.4 | % |
Loss from Operations |
|
| (435,089 | ) |
|
| (75,741 | ) |
|
| (359,348 | ) |
|
| 474.4 | % |
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
| (47,806 | ) |
|
| (36,977 | ) |
|
| (10,829 | ) |
|
| 29.3 | % |
Gain on Derivatives, Net |
|
| 60,176 |
|
|
| 38,876 |
|
|
| 21,300 |
|
|
| 54.8 | % |
Other Income (Expense) |
|
| (115 | ) |
|
| 90 |
|
|
| (205 | ) |
|
| -227.8 | % |
Loss on Equity Method Investments |
|
| (411 | ) |
|
| (813 | ) |
|
| 402 |
|
|
| -49.4 | % |
Total Other Income |
|
| 11,844 |
|
|
| 1,176 |
|
|
| 10,668 |
|
|
| 907.1 | % |
Loss from Continuing Operations Before Income Tax |
|
| (423,245 | ) |
|
| (74,565 | ) |
|
| (348,680 | ) |
|
| 467.6 | % |
Income Tax Benefit |
|
| 24,227 |
|
|
| 26,915 |
|
|
| (2,688 | ) |
|
| -10.0 | % |
Loss from Continuing Operations |
|
| (399,018 | ) |
|
| (47,650 | ) |
|
| (351,368 | ) |
|
| 737.4 | % |
Income from Discontinued Operations, Net of Income Taxes |
|
| 37,985 |
|
|
| 5,000 |
|
|
| 32,985 |
|
|
| 659.7 | % |
Net Loss |
|
| (361,033 | ) |
|
| (42,650 | ) |
|
| (318,383 | ) |
|
| 746.5 | % |
Net Income Attributable to Noncontrolling Interests |
|
| 2,245 |
|
|
| 4,039 |
|
|
| (1,794 | ) |
|
| -44.4 | % |
Net Loss Attributable to Rex Energy |
|
| (363,278 | ) |
|
| (46,689 | ) |
|
| (316,589 | ) |
|
| 678.1 | % |
Preferred Stock Dividends |
|
| 9,660 |
|
|
| 2,335 |
|
|
| 7,325 |
|
|
| 100.0 | % |
Net Loss Attributable to Common Shareholders |
| $ | (372,938 | ) |
| $ | (49,024 | ) |
| $ | (323,914 | ) |
|
| 660.7 | % |
Production and Lease Operating Expense increased approximately $18.7 million, or 18.7%, in 2015 from 2014. Since the first quarter of 2012, we have entered into several new transportation and marketing agreements to enhance our ability to sell our natural gas and NGLs. For the year ended December 31, 2015, these transportation and marketing agreements accounted for approximately 66.8% of our Production and Lease Operating Expense, as compared to 59.4% in 2014. These agreements typically have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per unit of production basis, our lifting costs decreased to $1.66 per Mcfe during 2015 from $1.78 in 2014. The decrease in our lift cost per unit is attributable to our higher production and a decrease in the cost of field services related to the depressed commodity price environment. We expect that if commodity prices increase the cost of field services will increase as well.
General and Administrative Expense of approximately $29.4 million for 2015 decreased approximately $6.7 million, or 18.5%, from 2014. The year-over-year decrease is predominately due to several cost control measures taken including reductions in bonus compensation, reductions in head count, decrease in travel expenditures, less usage of third-party consultants and pricing concessions received from suppliers and service providers. On a per unit of production basis, our G&A expenses decreased to $0.41 per Mcfe during 2015 from $0.64 per Mcfe during 2014. We expect that our G&A expenses will continue to decrease in 2016 in light of the depressed commodity price environment.
Impairment Expense increased to $345.8 million in 2015 from $132.6 million in 2014, an increase of 160.7%. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment (for additional information see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements). Approximately $271.3 million of the impairment incurred during 2015 was attributable to proved properties and other fixed assets, of which approximately $47.7 million was attributable to our conventional oil properties in the Illinois Basin,
55
$204.6 million was attributable to the unconventional assets in the Appalachian Basin and $17.5 million was attributable to our equity method investment in RW Gathering. The remaining proved property impairment expense is related to our conventional dry gas assets and salt water disposal well in the Appalachian Basin. In addition, we also incurred approximately $74.5 million in unproved property impairments, of which approximately $59.7 million was related to leases in the Appalachian Basin and approximately $14.8 million was attributable to leases in the Illinois Basin. The impairments were identified through an analysis of market conditions and future development plans that were in existence as of December 31, 2015, related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. The primary reason for the decrease in the estimated future cash flows of our assets is attributable to the continued depression of current and estimated future commodity prices as of December 31, 2015. Our estimates of future cash flows attributable to our oil and gas properties could decline further if commodity prices continue to decline, which may result in our incurrence of additional impairment expense. As of December 31, 2015, we continued to carry the costs of unproved properties of approximately $263.0 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.
To quantify the impact of continued low commodity prices or further declines in future prices, as of December 31, 2015, approximately 76% of the carrying value of our evaluated oil and natural gas properties were located in Butler County, Pennsylvania. As of December 31, 2015, estimated future cash flows for these properties exceeded net book value by over 100%, indicating that substantial further decreases in commodity prices, combined with a lack of access to capital or detrimental changes to costs or operating efficiencies, would need to occur for us to experience a write-down with respect to these properties. The remaining evaluated properties that are outside of Butler County, Pennsylvania are more sensitive to the current commodity price environment. These properties could experience additional write-downs if estimates of future commodity prices decline further. The net book value of these remaining evaluated properties total approximately $133.9 million.
Approximately $113.4 million of the impairment incurred during 2014 was attributable to proved properties and other fixed assets, of which approximately $103.9 million was attributable to the Illinois Basin and $9.5 million was attributable to the Appalachian Basin. In the Illinois Basin, which is 100% oil producing, the estimated future decline in oil prices as of December 31, 2014, caused the estimated future cash flows of certain properties to decrease below a level at which the carrying value that is expected to be recovered. In the Appalachian Basin, approximately $5.9 million of impairment was incurred for our salt water disposal well in Ohio due to the regulatory and environmental climate and the uncertainty of future viability of the disposal well. We also incurred approximately $3.6 million of impairment related to shallow conventional gas properties in the Appalachian Basin, which is attributable to the estimated future decrease in natural gas pricing as of December 31, 2014. In addition to our proved property and fixed asset impairments, we also incurred approximately $18.9 million in unproved property impairments. In the Appalachian Basin, we incurred approximately $10.4 million in unproved property impairments related to expiring leases that will not be developed. In the Illinois Basin, we incurred approximately $8.5 million of unproved property impairment primarily due to the estimated future economics of the properties at the depressed commodity price environment at December 31, 2014.
Exploration Expense of oil, NGL and natural gas properties for 2015 decreased approximately $6.4 million from $9.4 million in 2014. Approximately $1.3 million of the expense incurred during 2015 is attributable to geological and geophysical expenditures and approximately $1.4 million is attributable to delay rental payments predominately associated with properties in the Appalachian Basin. An additional $0.1 million was due to dry hole expense for three Illinois non-operated properties located in Illinois Basin and $0.2 million was due to dry hole expense for one property in the Appalachian Basin. Approximately $5.3 million of the expense incurred during 2014 is attributable to geological and geophysical expenditures and delay rental payments predominately associated with properties in the Appalachian Basin. Approximately $4.1 million of the expense incurred during 2014 was attributable to dry hole expense. During 2014, three exploratory dry holes were drilled in the Illinois Basin, resulting in $1.1 million in dry hole expense, while six exploratory projects in the Appalachian Basin were abandoned at various stages, resulting in $3.1 million in dry hole expense.
Depletion, Depreciation, Amortization and Accretion Expense of approximately $104.7 million for 2015 increased approximately $10.3 million, or 10.9%, from 2014. Contributing to the increase in DD&A expense were lower reserves, which were triggered by the ongoing lower commodity pricing environment, and increased production when compared to the same period in 2014.
Other Operating Expense increased approximately $5.5 million from a negligible amount for the same period in 2014. The period-over-period increase in Other Operating Expense is due to fees incurred associated with the early termination of two drilling rig contacts during the first quarter of 2015. Both drilling rigs were operated within our Appalachian Basin region and were terminated due to our lower activity levels in response to the commodity price environment. We currently have one drilling rig that remains active in the area. Should the current commodity price environment continue, we may elect to terminate the contract of this rig as well in 2016.
56
Interest Expense for 2015 was approximately $47.8 million as compared to $37.0 million for 2014. The increase in interest expense was primarily due to the issuance of $325.0 million in Senior Notes due 2022 in July 2014 as well as the outstanding balance on our Senior Credit Facility for second half of 2015. We discuss our Senior Notes and senior credit facility later in this report, and in Note 9, Long-Term Debt, to our Consolidated Financial Statements.
Gain on Derivatives, net for 2015 was a gain of approximately $60.2 million as compared to a gain of approximately $38.9 million for 2014. The gain in 2015 included cash receipts for commodity and interest rate derivatives of $55.8 million while the gain in 2014 included cash payments of approximately $7.3 million related to commodity and interest rate derivatives. Changes were attributable to the volatility of oil, NGL and natural gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil, NGL and gas prices in the marketplace than were in effect at the time we entered into a derivative contract, while gains would suggest the opposite. Our derivative program is designed to provide us with greater predictability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.
We believe oil, NGL and natural gas prices will remain volatile and could decline further. Although we have entered into derivative contracts covering a portion of our production volumes for 2016 and 2017, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future.
Income Tax Benefit for 2015 was approximately $24.2 million as compared to $26.9 million in 2014. Our effective tax rate in 2015 was approximately 5.7% as compared to 36.1% in 2014. As of December 31, 2015, we had a significant level of future tax benefits, some of which are not expected to be fully utilized, therefore limiting our ability to recognize further tax benefits.
Preferred Stock Dividends for 2015 totaled approximately $9.7 million as compared to $2.3 million in 2014. In August 2014, we completed an offering 6.0% Convertible Perpetual Preferred Stock, for which we paid a dividend of $145.00 per preferred share in November 2014. Quarterly dividends of approximately $2.4 million were paid in 2015. On January 20, 2016, we announced that we had suspended payment of our quarterly dividend on shares of our 6.0% Convertible Perpetual Preferred Stock. We have the ability to continue to suspend dividend payments and will continue to evaluate the payment or suspension of the dividend on a quarterly basis.
Net Loss Attributable to Rex Energy Common Shareholders for 2015 was approximately $372.9 million, as compared to approximately $49.0 million for 2014 as a result of the factors discussed above.
Comparison of the Year Ended December 31, 2014 to the Year Ended December 31, 2013
Oil and gas revenue for the years ended December 31, 2014 and 2013 is summarized in the following table:
|
| For the Year Ended December 31, |
| |||||||||||||
($ in Thousands, except total Mcfe production and price per Mcfe) |
| 2014 |
|
| 2013 |
|
| Change |
|
| % |
| ||||
Oil, NGL and Gas Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate sales revenue |
| $ | 97,426 |
|
| $ | 86,959 |
|
| $ | 10,467 |
|
|
| 12.0 | % |
Oil derivatives realized (a) |
| $ | 1,085 |
|
| $ | (3,495 | ) |
| $ | 4,580 |
|
|
| -131.0 | % |
Total oil and condensate revenue and derivatives realized |
| $ | 98,511 |
|
| $ | 83,464 |
|
| $ | 15,047 |
|
|
| 18.0 | % |
Gas sales revenue |
| $ | 126,500 |
|
| $ | 87,078 |
|
| $ | 39,422 |
|
|
| 45.3 | % |
Gas derivatives realized (a) |
| $ | 1,637 |
|
| $ | 10,885 |
|
| $ | (9,248 | ) |
|
| -85.0 | % |
Total gas revenue and derivatives realized |
| $ | 128,137 |
|
| $ | 97,963 |
|
| $ | 30,174 |
|
|
| 30.8 | % |
C3+ NGL sales revenue |
| $ | 69,626 |
|
| $ | 39,882 |
|
| $ | 29,744 |
|
|
| 74.6 | % |
C3+ NGL derivatives realized (a) |
| $ | 3,247 |
|
| $ | (263 | ) |
| $ | 3,510 |
|
|
| -1334.6 | % |
Total C3+ NGL revenue and derivatives realized |
| $ | 72,873 |
|
| $ | 39,619 |
|
| $ | 33,254 |
|
|
| 83.9 | % |
Ethane sales revenue |
| $ | 4,317 |
|
| $ | — |
|
| $ | 4,317 |
|
|
| 100.0 | % |
Ethane derivatives realized (a) |
| $ | — |
|
| $ | — |
|
| $ | — |
|
|
| 0.0 | % |
Total ethane revenue and derivatives realized |
| $ | 4,317 |
|
| $ | — |
|
| $ | 4,317 |
|
|
| 100.0 | % |
Consolidated sales |
| $ | 297,869 |
|
| $ | 213,919 |
|
| $ | 83,950 |
|
|
| 39.2 | % |
Consolidated derivatives realized (a) |
| $ | 5,969 |
|
| $ | 7,127 |
|
| $ | (1,158 | ) |
|
| -16.2 | % |
Total oil, NGL and gas revenue and derivatives realized |
| $ | 303,838 |
|
| $ | 221,046 |
|
| $ | 82,792 |
|
|
| 37.5 | % |
Total Mcfe Production |
|
| 56,352,489 |
|
|
| 33,850,167 |
|
|
| 22,502,322 |
|
|
| 66.5 | % |
Average Realized Price per Mcfe, including the effects of derivatives |
| $ | 5.39 |
|
| $ | 6.53 |
|
| $ | (1.14 | ) |
|
| -17.4 | % |
| (a) | Realized derivatives are included in Other Income (Expense) on our Consolidated Statements of Operations. |
57
Average realized price received for oil, NGLs and natural gas during 2014 was $5.39 per Mcfe, a decrease of 17.4%, or $1.14 per Mcfe, from the prior year. The average realized price for oil, including the effects of derivatives, in 2014 decreased 5.4% or $4.97 per barrel, whereas the average realized price for natural gas, including the effects of derivatives, decreased 17.0%, or $0.71 per Mcf, from 2013. The average realized price for NGLs, including the effects of derivatives, in 2014 decreased 23.3%, or $11.27 per barrel, from 2013. Our derivative activities effectively increased net realized prices by $0.11 per Mcfe in 2014 and $0.21 per Mcfe in 2013.
Production volume for 2014 increased 66.5% from 2013 primarily due to the success of our Marcellus and Utica Shale horizontal drilling activities in the Appalachian Basin, where production increased approximately 76.4%, or 22.3 Bcfe. We placed into service 52.0 gross (38.1 net) wells within the Appalachian Basin, primarily targeting the Marcellus and Utica Shales, during 2014. Production in the Illinois Basin for 2014 increased by 4.1% to 806,162 barrels as compared to the same period in 2013. The natural decline of our Illinois Basin properties was offset by increased oil production from our infill drilling and recompletion operations in the region. During 2014, we drilled 18.0 gross (12.0 net) wells and recompleted 23.0 gross (23.0 net) wells in the Illinois Basin.
Overall, our production for 2014 averaged approximately 154.4 Mmcfe per day, of which 12.1% was attributable to oil, 22.2% was attributable to NGLs and 65.7% was attributable to natural gas.
Statements of Operations for the years ended December 31, 2014 and 2013 are as follows:
|
| For the Year Ended December 31, |
| |||||||||||||
($ in Thousands) |
| 2014 |
|
| 2013 |
|
| Change |
|
| % |
| ||||
Statement of Operations Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Revenue: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Natural Gas and NGL Sales |
| $ | 297,869 |
|
| $ | 213,919 |
|
| $ | 83,950 |
|
|
| 39.2 | % |
Other Revenue |
|
| 118 |
|
|
| 200 |
|
|
| (82 | ) |
|
| -41.0 | % |
Total Operating Revenue |
|
| 297,987 |
|
|
| 214,119 |
|
|
| 83,868 |
|
|
| 39.2 | % |
Operating Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
|
| 100,282 |
|
|
| 62,150 |
|
|
| 38,132 |
|
|
| 61.4 | % |
General and Administrative Expense |
|
| 36,137 |
|
|
| 30,839 |
|
|
| 5,298 |
|
|
| 17.2 | % |
(Gain) Loss on Disposal of Assets |
|
| 644 |
|
|
| 1,602 |
|
|
| (958 | ) |
|
| -59.8 | % |
Impairment Expense |
|
| 132,618 |
|
|
| 32,072 |
|
|
| 100,546 |
|
|
| 313.5 | % |
Exploration Expense |
|
| 9,446 |
|
|
| 11,408 |
|
|
| (1,962 | ) |
|
| -17.2 | % |
Depreciation, Depletion, Amortization & Accretion |
|
| 94,467 |
|
|
| 62,386 |
|
|
| 32,081 |
|
|
| 51.4 | % |
Other Operating Expense |
|
| 134 |
|
|
| 592 |
|
|
| (458 | ) |
|
| -77.4 | % |
Total Operating Expenses |
|
| 373,728 |
|
|
| 201,049 |
|
|
| 172,679 |
|
|
| 85.9 | % |
Income (Loss) from Operations |
|
| (75,741 | ) |
|
| 13,070 |
|
|
| (88,811 | ) |
|
| -679.5 | % |
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
| (36,977 | ) |
|
| (22,676 | ) |
|
| (14,301 | ) |
|
| 63.1 | % |
Gain (Loss) on Derivatives, Net |
|
| 38,876 |
|
|
| (2,908 | ) |
|
| 41,784 |
|
|
| -1436.9 | % |
Other Income (Expense) |
|
| 90 |
|
|
| 6,739 |
|
|
| (6,649 | ) |
|
| -98.7 | % |
Gain (Loss) on Equity Method Investments |
|
| (813 | ) |
|
| (763 | ) |
|
| (50 | ) |
|
| 6.6 | % |
Total Other Income (Expense) |
|
| 1,176 |
|
|
| (19,608 | ) |
|
| 20,784 |
|
|
| -106.0 | % |
Income (Loss) from Continuing Operations Before Income Tax |
|
| (74,565 | ) |
|
| (6,538 | ) |
|
| (68,027 | ) |
|
| 1040.5 | % |
Income Tax Benefit (Expense) |
|
| 26,915 |
|
|
| 4,154 |
|
|
| 22,761 |
|
|
| 547.9 | % |
Income (Loss) from Continuing Operations |
|
| (47,650 | ) |
|
| (2,384 | ) |
|
| (45,266 | ) |
|
| 1898.7 | % |
Income (Loss) from Discontinued Operations, Net of Income Taxes |
|
| 5,000 |
|
|
| 1,811 |
|
|
| 3,189 |
|
|
| 176.1 | % |
Net Income (Loss) |
|
| (42,650 | ) |
|
| (573 | ) |
|
| (42,077 | ) |
|
| 7343.3 | % |
Net Income (Loss) Attributable to Noncontrolling Interests |
|
| 4,039 |
|
|
| 1,557 |
|
|
| 2,482 |
|
|
| 159.4 | % |
Net Income (Loss) Attributable to Rex Energy |
|
| (46,689 | ) |
|
| (2,130 | ) |
|
| (44,559 | ) |
|
| 2092.0 | % |
Preferred Stock Dividends |
|
| 2,335 |
|
|
| - |
|
|
| 2,335 |
|
|
| 100.0 | % |
Net Income (Loss) Attributable to Common Shareholders |
| $ | (49,024 | ) |
| $ | (2,130 | ) |
| $ | (46,894 | ) |
|
| 2201.6 | % |
Production and Lease Operating Expense increased approximately $38.1 million, or 61.4%, in 2014 from 2013. Since the first quarter of 2012, we have entered into several new transportation and marketing agreements to enhance our ability to sell our natural gas and NGLs. For the year ended December 31, 2014, these transportation and marketing agreements accounted for approximately 59.3% of our Production and Lease Operating Expense, as compared to 42.5% in 2013. These agreements typically
58
have a term of several years, and we expect them to continue to comprise a significant portion of our Production and Lease Operating Expense. On a per unit of production basis, our lifting costs decreased to $1.78 per Mcfe during 2014 from $1.84 in 2013.
General and Administrative Expense of approximately $36.1 million for 2014 increased approximately $5.3 million, or 17.2%, from 2013. The year-over-year increase is predominately due to the expansion of our Appalachian Basin operations and our corporate headquarters and is commensurate with our overall organizational growth. On a per unit of production basis, our G&A expenses decreased to $0.64 per Mcfe during 2014 from $0.98 per Mcfe during 2013.
Impairment Expense increased to $132.6 million in 2014 from $32.1 million, an increase of 313.5%, in 2013. We evaluate impairment of our properties when events occur that indicate that the carrying value of these properties may not be recoverable. Approximately $113.4 million of the impairment during 2014 was attributable to proved properties and other fixed assets, of which approximately $103.9 million was attributable to the Illinois Basin and $9.5 million was attributable to the Appalachian Basin. In the Illinois Basin, which is 100% oil producing, the decline in estimated future oil prices as of December 31, 2014, caused the estimated future cash flows of certain properties to decrease below a level at which the carrying value could be recovered. In the Appalachian Basin, approximately $5.9 million of impairment was incurred for our salt water disposal well in Ohio due to the regulatory and environmental climate. We also incurred approximately $3.6 million of impairment related to shallow conventional gas properties in the Appalachian Basin, which is attributable to the decrease in estimated future natural gas pricing as of December 31, 2014. In addition to our proved property and fixed asset impairments, we also incurred approximately $18.9 million in unproved property impairments. In the Appalachian Basin, we incurred approximately $10.4 million in unproved property impairments related to expiring leases that will not be developed. In the Illinois Basin, we incurred approximately $8.5 million of unproved property impairment primarily due to the estimated future economics of the properties at the depressed commodity price environment at December 31, 2014. During 2013, we incurred approximately $29.3 million of expense related to the impairment of conventional oil properties in the Illinois Basin. The impairment in Illinois was focused in two areas where extensive development activity occurred during 2013. In addition to the development activity, future estimated prices for the sale of crude oil as of December 31, 2013 decreased to a level which did not support the recovery of the full carrying value of the properties.
Exploration Expense of oil, NGL and natural gas properties for 2014 decreased approximately $2.0 million from $11.4 million in 2013. Approximately $5.3 million of the expense incurred during 2014 is attributable to geological and geophysical expenditures and delay rental payments predominately associated with properties in the Appalachian Basin. Approximately $4.1 million of the expense incurred during 2014 was attributable to dry hole expense. During 2014, three exploratory dry holes were drilled in the Illinois Basin, resulting in $1.1 million in dry hole expense, while six exploratory projects in the Appalachian Basin were abandoned at various stages, resulting in $3.1 million in dry hole expense. Approximately $8.4 million of the expenses incurred during 2013 is attributable to geological and geophysical expenditures and delay rental payments. The remaining expense incurred during 2013 is related to two dry holes drilled in exploratory areas of the Illinois Basin.
Depletion, Depreciation, Amortization and Accretion Expense of approximately $94.5 million for 2014 increased approximately $32.1 million, or 51.4%, from 2013. Contributing to the increase in DD&A expense were lower reserves in the Illinois Basin despite additional capital spending in the region. Overall, the period over period increase in DD&A expense is consistent with the growth in our asset base, reserves and production since the comparable period in 2013.
Interest Expense for 2014 was approximately $37.0 million as compared to $22.7 million for 2013. The increase in interest expense was primarily due to the issuance of our 2022 Senior Notes in July 2014. We discuss our Senior Notes and senior credit facility later in this report, and in Note 9, Long-Term Debt, to our Consolidated Financial Statements.
Gain (Loss) on Derivatives, net for 2014 was a gain of approximately $38.9 million as compared to a loss of approximately $2.9 million for 2013. This change was attributable to the volatility of oil, NGL and natural gas commodity prices in the marketplace along with changes in our portfolio of outstanding collars and swap derivatives. Losses from derivative activities generally reflect higher oil, NGL and gas prices in the marketplace than were in effect at the time we entered into a derivative contract, while gains would suggest the opposite. Our derivative program is designed to provide us with greater predictability of future cash flows at expected levels of oil and gas production volumes given the highly volatile oil and gas commodities market.
Other Income for 2014 was approximately $0.1 million as compared to $6.7 million in 2013. The gain recognized in 2013 was primarily attributable to approximately $6.9 million in proceeds related to the sale of our investment in Keystone Midstream in 2012 that were being held in escrow.
Income Tax Benefit for 2014 was approximately $26.9 million as compared to $4.2 million in 2013. The change was primarily due to the change in pre-tax loss. Also contributing to the period-over-period change are changes in estimates of current and deferred state taxes in addition to a valuation allowance in 2014 on the carrying value of our net operating loss carryforwards. Our effective tax
59
rate in 2014 was approximately 36.1% as compared to 63.5% in 2013. The change in rates was primarily due to the impact of permanent differences on a lower pre-tax loss.
Preferred Stock Dividends for 2014 totaled approximately $2.3 million. In August 2014, we completed and offering 6.0% Convertible Perpetual Preferred Stock, for which we paid a dividend of $145.00 per preferred share in November 2014. Prior to August 2014, we did not have any preferred stock outstanding nor did we pay any dividends.
Net Loss Attributable to Rex Energy Common Shareholders for 2014 was approximately $49.0 million, as compared to approximately $2.1 million for 2013 as a result of the factors discussed above.
Capital Resources and Liquidity
Our primary financial resource is our base of oil, natural gas and NGL reserves. Our working capital is significantly influenced by changes in commodity prices, and significant declines in prices could decrease our exploration and development expenditures. Historically, cash flows from operations, borrowings under the revolving credit facility and net proceeds from debt and equity offerings have been used to fund exploration and development of our oil and gas interests. During 2015, we spent approximately $232.7 million of capital on drilling projects, facilities and related equipment and acquisitions of acreage, which includes the capital expenditures of Water Solutions Holdings of approximately $8.6 million. Our 2015 capital program was funded with proceeds from offerings completed in 2014 of senior notes due 2022 and preferred stock, net cash flow from operations, net proceeds from the disposition of Water Solutions Holdings of approximately $66.8 million and from borrowings under our revolving credit facility. We are in the process of establishing our 2016 plan and expect our 2016 capital budget to be between $15.0 million and $25.0 million. We expect that our 2016 capital expenditure plan will continue to be funded primarily by cash flow from operations, joint venture proceeds, non-core asset sales and borrowings under our revolving credit facility.
As of December 31, 2015, we had approximately $1.1 million of cash on hand. We expect to receive additional cash of approximately $18.5 million from ArcLight during the first quarter of 2016 related to their working interest in 12 wells in Butler County, Pennsylvania, that were drilled and completed during 2015. We will receive payment from ArcLight upon placing these wells into service. At December 31, 2015, outstanding borrowings under our revolving credit facility consisted of $111.5 million of borrowings and an additional $41.0 million of undrawn letters of credit, of which approximately $39.8 million are related to our firm transportation contracts. In conjunction with our offer to exchange senior unsecured notes, in February 2016, our borrowing base was decreased to $200.0 million and was further reduced to $190.0 million on March 14, 2016 effective April 1, 2016. The next borrowing base redetermination will occur on or about July 1, 2016.
Our ability to fund our capital expenditures is dependent upon the level of product prices and the success of our exploration program in replacing existing oil, NGL and natural gas reserves. If commodity prices decline further, operating cash flows may decrease and our lenders may further reduce the borrowing base, thus reducing the funds available to fund future capital expenditures. If we are unable to replace our oil, NGL and natural gas reserves through acquisition, development and exploration, we may also suffer a reduction in operating cash flows and access to funds under the revolving credit facility. We have the ability to add commodity derivatives to our portfolio at prevailing market rates to mitigate a portion of the decrease in operating cash flows should commodity prices decline further. Since December 31, 2015, we have added commodity derivatives covering approximately 380,000 barrels of oil, 2,740,000 mcf of natural gas and 120,000 barrels of NGLs for volumes related to 2016. At December 31, 2015, we were in compliance with all required debt covenants under our revolving credit facility. We do not anticipate being in compliance with our current ratio requirement of 1.0 to 1.0 at March 31, 2016; however, we have received a waiver of this covenant for the period ending March 31, 2016 from the lenders under our revolving credit facility. Subsequent to March 31, 2016, we expect this ratio to improve as we receive proceeds from our joint development operations and do not expect to incur any covenant violations.
Due to the current depressed commodity price environment, in January 2016, we suspended payment of our quarterly dividend on shares of our Series A Convertible, Perpetual Preferred Stock. We have the ability to continue to suspend dividend payments and will continue to evaluate the payment of these dividends on a quarterly basis. As a result of not declaring the first quarter dividend on our Series A Preferred Stock, we are no longer eligible to use Form S-3 registration statements. 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 (for initial issuance or resale) or issue securities in private placements, which could increase the cost of raising capital. We may need to take additional actions in the future to address current industry trends and maintain our ability to pay expenses and service our indebtedness, including, but not limited to, selling assets or raising capital by issuing additional debt or equity securities.
We have senior unsecured notes due 2020 and 2022 that are governed by indentures with substantially similar terms and provisions (the “Indentures”). The Indentures contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on the ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or sell substantially all of
60
its assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted. Certain of the limitations in the Indentures, including the ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25:1. As of December 31, 2015, the Company’s Fixed Charge Coverage Ratio was 1.3. We expect our Fixed Charge Coverage Ratio to be less than 2.25:1 for the remainder of 2016. As a result, we anticipate that our ability to incur debt, pay dividends or make certain other restricted payments will be subject to the more restrictive provisions of the Indentures for those periods. As of December 31, 2015, we were limited to incurring an additional $214.3 million in additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default, including cross-default features with any other indebtedness. In certain circumstances, the Trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.
Future Liquidity Considerations
In connection with certain marketing, transportation and processing agreements that we have entered into, we may be obligated to pay fees in connection with these agreements of $179.0 million over the next five years, depending on our levels of production. Also in connection with certain of these agreements, we have guaranteed the payment of obligations up to a maximum of $421.8 million over the life of the agreements, which range from two to 20 years. As the commitments are satisfied, these guarantees will decrease over time. For additional information on our commitments and guarantees, see Note 7, Commitments and Contingencies, to our Consolidated Financial Statements.
Our revolving credit facility contains a number of restrictive covenants and limitations that will impose significant operating and financial restrictions on us. In particular, our financial covenants require us to maintain a minimum consolidated current ratio of 1.0 to 1.0 and a maximum ratio of net senior-secured debt to EBITDAX, a non-GAAP measure, of 3.0 to 1.0. On March 14, 2016, we entered an amendment to our revolving credit facility that decreases our net senior secured debt to EBITDAX ratio from 3.0 to 1.0 to 2.75 to 1.0 in the event that at least 80% of our senior unsecured notes are exchanged for new second lien notes. Failure to comply with either of these covenants could have an adverse effect on our business. 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. |
For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Item 6. Selected Financial Data – Non-GAAP Financial Measures.”
Our revolving credit facility requires we meet, on a quarterly basis, financial requirements of a minimum consolidated current ratio and a maximum net senior secured debt to EBITDAX ratio. EBITDAX is a non-GAAP measure used by our management team and by other users of our financial statements. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Item 6. Selected Financial Data - Non-GAAP Financial Measures.” If we are unable to comply with these financial requirements, an event of default could result which would permit acceleration of outstanding debt and could permit our lenders to foreclose on our mortgaged properties. In order to improve our liquidity position to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions including (i) debt-for-debt exchanges, (ii) joint venture opportunities, (iii) minimizing our capital expenditures, (iv) improving our cash flows from operations, (v) effectively managing our working capital (vi) adding additional hedging positions (vii) and in- and out-of-court restructuring. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transaction can be consummated within the period needed to meet certain obligations.
61
Financial Condition and Cash Flows for the Years Ended December 31, 2015, 2014 and 2013
The following table summarizes our sources and uses of funds for the periods noted:
|
| Year Ended December 31, |
| |||||||||
($ in Thousands) |
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Cash flows provided by operations |
| $ | 30,885 |
|
| $ | 162,706 |
|
| $ | 108,316 |
|
Cash flows used in investing activities |
|
| (155,446 | ) |
|
| (560,036 | ) |
|
| (313,518 | ) |
Cash flows provided by financing activities |
|
| 107,556 |
|
|
| 413,526 |
|
|
| 163,127 |
|
Net increase (decrease) in cash and cash equivalents |
| $ | (17,005 | ) |
| $ | 16,196 |
|
| $ | (42,075 | ) |
Net cash provided by operating activities decreased by approximately $131.8 million in 2015 when compared to 2014, to $30.9 million. This was primarily due to a reduction in oil, natural gas and NGL prices, increased lease operating expenses and payments related to our early termination of two drilling rig contracts. These decreases in cash flow were partially offset by increases in production in our Appalachian Basin operations. Net cash provided by operating activities increased by approximately $54.4 million in 2014 when compared to 2013, to $162.7 million. This increase in net cash provided by operating activities was primarily due to our overall increase in operating revenues attributable to our increase in production. This increase in cash flow was partially offset by an increase in operating expenses, primarily Production and Lease Operating Expense and G&A Expense.
Net cash used in investing activities decreased by approximately $404.6 million in 2015 when compared to 2014, to $155.4 million. This decrease was primarily attributed to lower capital activity levels related to the currently depressed commodity price environment, the $66.8 million in proceeds received from the sale of Water Solutions and $24.9 million in proceeds received from our joint venture with ArcLight. Net cash used in investing activities increased by approximately $246.5 million in 2014 when compared to 2013, to $560.0 million. This increase was in large part due an increase in our capital spending during 2014, of which approximately $120.6 million was related to our acquisition of assets from Shell in September 2014.
Net cash provided by financing activities decreased by approximately $306.0 million in 2015 when compared to 2014, to $107.6 million. The decrease in cash provided by financing activities in 2015 is primarily due to proceeds of $325.0 million related to our offering of 2022 Senior Notes and proceeds of $155.0 million related to our offering of preferred stock in 2014, which were partially offset by an increase in net borrowings on our revolving credit facility. During 2014, we received combined proceeds of approximately $473.2 million from our preferred stock offering and private offering of 2022 Senior Notes. This was partially offset by net repayments of debt of approximately $56.0 million in 2014 as compared to net proceeds from debt of approximately $61.8 million in 2013.
As market conditions warrant and subject to our contractual restrictions in our revolving credit facility or otherwise, liquidity position and other factors, we may from time to time seek to recapitalize, refinance or otherwise restructure our capital structure in open market or privately negotiated transactions, which may include, among other things, repurchases of shares of our common stock or outstanding debt, including our senior unsecured notes, by tender offer or otherwise. The amounts involved in any such transaction, individually or in the aggregate, may be material.
Effects of Inflation and Changes in Price
Our results of operations and cash flows are affected by changing oil and natural gas prices. If the price of oil and natural gas increases or decreases, there could be a corresponding increase or decrease in our operating costs, as well as an increase or decrease in revenues. Inflation has had a minimal effect on our results.
Critical Accounting Policies and Recent Accounting Pronouncements
The preparation of financial statements in conformity with United States generally accepted accounting principles (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future cash flows, asset retirement obligations, impairment (when applicable) of undeveloped properties, the collectability of outstanding accounts receivable, fair values of financial derivative instruments, contingencies and the results of current and future litigation. Oil and natural gas estimates, which are the basis for units-of-production depletion, have numerous inherent uncertainties. The certainty of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation
62
and judgment. Subsequent drilling results, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. These prices have been volatile in the past and are expected to be volatile in the future.
The significant estimates are based on current assumptions that may be materially affected by changes in future economic conditions such as the market prices received for sales of oil and natural gas, interest rates, and our ability to generate future income. Future changes in these assumptions may materially affect these significant estimates in the near term.
Accounts Receivable
Our trade accounts receivable, which are primarily from oil, NGLs and natural gas sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We assess the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2015 and 2014 was $0.2 million.
To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets.
Oil, NGL and Natural Gas Property, Depreciation and Depletion
We account for oil, NGL and natural gas exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of oil, NGLs and natural gas, are capitalized.
Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years.
We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future oil, NGL and natural gas prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future oil, NGL and natural gas prices are based on forward strip prices for NYMEX oil and Henry Hub natural gas and other related indices. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved oil and gas properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved oil, NGL and natural gas properties, we analyze the level and success of current development, future development plans and changes in market value. Performing the impairment evaluations requires use of judgments and estimates since the results are dependent on future events, including estimates of future proved and unproved reserves, future commodity prices, the timing of future production, capital expenditures and the intent to develop properties, among others.
63
We recognized approximately $345.8 million, $132.6 million and $32.1 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2015, 2014 and 2013, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 16, Impairment Expense, to our Consolidated Financial Statements.
Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.
Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated DD&A are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.
Natural Gas and Oil Reserve Quantities
Our estimate of proved reserves is based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2015 and 2014, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil, NGL and natural gas reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.
Future Abandonment Cost
Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.
Revenue Recognition
As it pertains to our exploration and production business segment, oil, NGL and natural gas revenue is recognized when the oil, NGL or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil and NGL sales, title is transferred to the purchaser when the oil or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil, NGLs and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for oil and NGL production held in stock tanks before delivery to the purchaser.
64
To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the Consolidated Balance Sheets and Oil, Natural Gas and NGL Sales on the Statements of Operations.
Derivative Instruments
We use put and call options (collars), fixed rate swap contracts, swaptions, puts, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We also, from time to time, use interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third-parties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.
We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2015, 2014 and 2013 we did not have any derivative instruments designated for hedge accounting.
For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil, natural gas and NGL production activity and interest rates, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.
Contingent Liabilities
A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information.
Income Taxes
We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to other temporary differences.
Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax basis of assets and liabilities using the enacted tax rate. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.
This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.
The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions
65
require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets.
We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 11, Income Taxes, to our Consolidated Financial Statements). Our policy is to recognize interest and penalties on any unrecognized tax benefits in interest expense and general and administrative expense, respectively.
Recent Accounting Pronouncements
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40). The new guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments in this ASU intend to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. In addition to reducing the number of consolidation models from four to two, the new standard places more emphasis on risk of loss when determining a controlling financial interest, reduces the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity and changes consolidation conclusions in several industries that typically make use of limited partnerships or variable interest entities. This ASU will be effective for periods beginning after December 15, 2015, for public companies, and early adoption is permitted, including adoption in an interim period. We are currently evaluating the potential effect of this ASU but do not believe that it will have a material impact on our Consolidated Financial Statements.
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The standard requires an entity to present debt issuance costs related to a recognized liability as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements. As of December 31, 2015, we had approximately $14.0 million in net deferred financing costs that would be potentially reclassified to reduce the debt carrying balance.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards. This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by following five steps:
1) Identify the contract(s) with a customer.
2) Identify the performance obligations in the contract.
3) Determine the transaction price.
4) Allocate the transaction price to the performance obligations in the contract.
66
5) Recognize revenue when (or as) the entity satisfies a performance obligation.
An entity should apply the amendments in this ASU using one of the following two methods:
1) Retrospectively to each prior reporting period presented.
2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications.
In July 2015, the FASB approved a one-year deferral of the effective date of this new standard so the guidance is effective for the reporting period beginning January 1, 2018, with early adoption permitted in the first quarter 2017. We are currently evaluating the new guidance and have not determined the impact this standard may have on our Consolidated Financial Statements or decided upon the method of adoption.
In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs with Line-of-Credit Arrangements. This ASU clarifies the presentation of debt issuance costs associated with line-of-credit arrangements. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires the presentation of debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements.
In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes. This ASU requires all deferred tax assets and liabilities, including any related valuation allowance, to be presented in the balance sheet as non-current. This ASU is effective for public entities for annual periods beginning after December 31, 2016, and interim periods within those annual periods. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements.
Volatility of Oil, NGL and Natural Gas Prices
Our revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and natural gas.
To mitigate some of our commodity price risk we engage periodically in certain other limited derivative activities, including price swaps and costless collars, to establish some price floor protection. For the year ended December 31, 2015, the net realized gain on oil, natural gas and NGL derivatives was approximately $54.9 million. For the year ended December 31, 2014, the net realized gain on oil, natural gas and NGL derivatives was approximately $6.0 million. For the year ended December 31, 2015, our total net gain on oil, natural gas and NGL derivatives was approximately $59.2 million, as compared to a net gain of approximately $37.6 million on oil, NGL and natural gas derivatives for 2014. Derivative gains and losses are reported as Gain on Derivatives, net in the Consolidated Statements of Operations.
While the use of derivative arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of oil, NGLs and natural gas. We enter into the majority of our derivative transactions with five counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the derivative transaction. Moreover, our derivative arrangements generally do not apply to all of our production, and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our derivatives will vary from time to time.
For a summary of our current oil, NGL and natural gas derivative positions at December 31, 2015, refer to Note 10, Fair Value of Financial Instruments and Derivative Instruments, of our Consolidated Financial Statements.
67
In addition to our capital expenditure program, we are committed to making cash payments in the future on various types of contracts and obligations. As of December 31, 2015, we do not have any off-balance sheet debt or other such unrecorded obligations and we have not guaranteed the debt of any other party. The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2015.
The following summarizes our contractual financial obligations for continuing operations at December 31, 2015 and their future maturities. We expect to fund these contractual obligations with cash generated from operating activities.
|
| Payment Due by Period (in thousands) |
| |||||||||||||||||||||||||
|
| 2016 |
|
| 2017 |
|
| 2018 |
|
| 2019 |
|
| 2020 |
|
| Thereafter |
|
| Total |
| |||||||
Senior Notes (a) |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 350,000 |
|
| $ | 325,000 |
|
| $ | 675,000 |
|
Operating Leases |
|
| 1,058 |
|
|
| 991 |
|
|
| 565 |
|
|
| 563 |
|
|
| 422 |
|
|
| — |
|
|
| 3,599 |
|
Other Loans and Notes Payable |
|
| 590 |
|
|
| 28 |
|
|
| — |
|
|
| 111,500 |
|
|
| — |
|
|
| — |
|
|
| 112,118 |
|
Derivative Obligations (b) |
|
| 2,486 |
|
|
| 2,147 |
|
|
| 1,433 |
|
|
| 988 |
|
|
| 988 |
|
|
| — |
|
|
| 8,042 |
|
Firm Commitments (c) |
|
| 44,450 |
|
|
| 57,119 |
|
|
| 56,415 |
|
|
| 55,439 |
|
|
| 54,211 |
|
|
| 493,159 |
|
|
| 760,793 |
|
Asset Retirement Obligations (d) |
|
| 4,056 |
|
|
| 2,236 |
|
|
| 2,285 |
|
|
| 2,124 |
|
|
| 1,660 |
|
|
| 32,711 |
|
|
| 45,072 |
|
Total Contractual Obligations |
| $ | 52,640 |
|
| $ | 62,521 |
|
| $ | 60,698 |
|
| $ | 170,614 |
|
| $ | 407,281 |
|
| $ | 850,870 |
|
| $ | 1,604,624 |
|
(a) | The amount included in the table represents the outstanding principal amount only. Interest paid on our senior notes will be approximately $51.4 million each year through 2020 and approximately $20.3 million in 2021 and 2022. |
(b) | Derivative obligations represent open derivative contracts valued as of December 31, 2015, which were in a liability position. |
(c) | Includes commitments for rig and completion services and sales, gathering and processing agreements. |
(d) | The ultimate settlement and timing cannot be precisely determined in advance. |
Interest Rates
At December 31, 2015, we had $111.5 million in borrowings outstanding under our revolving credit facility. The interest rates on outstanding balances during 2015 on our revolving credit facility averaged 1.7%. At December 31, 2015, we had $350.0 million in 2020 Senior Notes outstanding bearing interest at 8.875% annually and $325.0 million in 2022 Senior Notes outstanding bearing interest at 6.25% annually that will be paid bi-annually.
Off-Balance Sheet Arrangements
We do not currently use any off-balance sheet arrangements to enhance our liquidity or capital resource position, or for any other purpose.
We are exposed to various risks, including energy commodity price risk. We expect energy prices to remain volatile and unpredictable. If energy prices were to decrease for a substantial period of time or decline significantly, revenues and cash flows would significantly decline, and our ability to borrow to finance our operations could be adversely impacted. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, natural gas and NGLs. Conversely, increases in the market prices for oil, natural gas and NGLs can have a favorable impact on our financial condition, results of operations and capital resources. Based on December 31, 2015 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 2015 prices would reduce our gross revenues, before the effects of derivatives, for the year ending December 31, 2016 by approximately $18.3 million.
We have designed our hedging policy to reduce the risk of price volatility for our production in the natural gas, NGL and crude oil markets. Our risk management policy provides for the use of derivative instruments to manage these risks. The types of derivative instruments that we use include fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, call protected swaps basis swaps and three-way collars. The volume of derivative instruments that we may use are governed by the risk management policy and can vary from year to year, but under most circumstances will apply to only a portion of our current and anticipated production, and will provide only partial price protection against declines in commodity prices. We are exposed to market risk on our open contracts, to the extent of changes in market prices of oil, natural gas and NGLs. However, the market risk exposure on these hedged contracts is generally offset by the gain or loss recognized upon the ultimate sale of the commodity that is hedged. Further, if our counterparties should default, this protection might be limited as we might not receive the benefits of the hedges.
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We account for our commodity derivatives at fair value on a recurring basis. The fair value of our derivatives contemplate the impact of assumed counterparty credit risk, which are based on published credit ratings, public bond yield spreads and credit default swap spreads, as applicable. A 1% increase in counterparty credit risk would result in a decrease in net income of approximately $0.4 million based on our derivative assets as of December 31, 2015 of $43.8 million.
At December 31, 2015, the following commodity derivative contracts were outstanding:
Period |
| Volume |
| Put Option |
|
| Floor |
|
| Ceiling |
|
| Swap |
|
| Fair Market Value ($ in Thousands) |
| |||||
Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 - Deferred Put Spreads |
| 120,000 Bbls |
| $ | 50.00 |
|
| $ | 65.00 |
|
| $ | — |
|
| $ | — |
|
| $ | 852 |
|
2016 - Collars |
| 379,500 Bbls |
|
| — |
|
|
| 39.17 |
|
|
| 52.67 |
|
|
| — |
|
|
| 1,078 |
|
2016 - Three-Way Collars |
| 45,000 Bbls |
|
| 50.00 |
|
|
| 65.00 |
|
|
| 70.00 |
|
|
| — |
|
|
| 577 |
|
|
| 544,500 Bbls |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 2,507 |
|
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 - Swaps |
| 12,900,000 Mcf |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 3.19 |
|
| $ | 8,717 |
|
2016 - Swaptions |
| 1,200,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.15 |
|
|
| 596 |
|
2016 - Cap Swaps |
| 3,600,000 Mcf |
|
| 3.45 |
|
|
| — |
|
|
| — |
|
|
| 4.11 |
|
|
| 1,977 |
|
2016 - Three-Way Collars |
| 18,570,000 Mcf |
|
| 2.34 |
|
|
| 3.04 |
|
|
| 3.86 |
|
|
| — |
|
|
| 5,941 |
|
2016 - Put Spread |
| 4,500,000 Mcf |
|
| 2.93 |
|
|
| 3.59 |
|
|
| — |
|
|
| — |
|
|
| 1,737 |
|
2016 - Basis Swaps - Dominion South |
| 16,630,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.94 | ) |
|
| (1,634 | ) |
2016 - Collars |
| 3,900,000 Mcf |
|
| — |
|
|
| 2.82 |
|
|
| 3.32 |
|
|
| — |
|
|
| 1,728 |
|
2017 - Swaps |
| 960,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.60 |
|
|
| 797 |
|
2017 - Swaptions |
| 0 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (297 | ) |
2017 - Cap Swaps |
| 2,100,000 Mcf |
|
| 3.34 |
|
|
| — |
|
|
| — |
|
|
| 4.07 |
|
|
| 1,225 |
|
2017 - Three-Way Collars |
| 16,300,000 Mcf |
|
| 2.33 |
|
|
| 3.02 |
|
|
| 3.89 |
|
|
| — |
|
|
| 4,319 |
|
2017 - Basis Swaps - Dominion South |
| 4,550,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.83 | ) |
|
| (665 | ) |
2017 - Basis Swaps - Texas Gas |
| 14,600,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.13 | ) |
|
| (19 | ) |
2017 - Calls |
| 3,000,000 Mcf |
|
| — |
|
|
| — |
|
|
| 3.64 |
|
|
| — |
|
|
| (380 | ) |
2018 - Swaps |
| 960,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.60 |
|
|
| 797 |
|
2018 - Cap Swaps |
| 1,800,000 Mcf |
|
| 3.30 |
|
|
| — |
|
|
| — |
|
|
| 4.05 |
|
|
| 1,069 |
|
2018 - Three-Way Collars |
| 7,875,000 Mcf |
|
| 2.29 |
|
|
| 2.88 |
|
|
| 3.56 |
|
|
| — |
|
|
| 916 |
|
2018 - Calls |
| 5,810,000 Mcf |
|
| — |
|
|
| — |
|
|
| 3.97 |
|
|
| — |
|
|
| (609 | ) |
2018 - Basis Swaps - Dominion South |
| 6,400,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.83 | ) |
|
| (960 | ) |
2018 - Basis Swaps - Texas Gas |
| 14,600,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.13 | ) |
|
| (19 | ) |
2019 - Basis Swaps - Dominion South |
| 7,300,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.83 | ) |
|
| (1,103 | ) |
2020 - Basis Swaps - Dominion South |
| 7,320,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.83 | ) |
|
| (1,106 | ) |
|
| 154,875,000 Mcf |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 23,027 |
|
NGLs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 C3 + NGL Swaps |
| 1,131,000 Bbls |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 32.76 |
|
| $ | 9,888 |
|
2016 Ethane Swaps |
| 240,000 Bbls |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 8.82 |
|
|
| 362 |
|
2017 C3 + NGL Swaps |
| 180,000 Bbls |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 21.42 |
|
|
| 344 |
|
|
| 1,551,000 Bbls |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 10,594 |
|
Refined Product (Heating Oil) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 - Swaps |
| 12,000 Bbls |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 84.00 |
|
| $ | (376 | ) |
|
| 12,000 Bbls |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (376 | ) |
Item 305(a) of Regulation S-K requires that tabular information relating to contract terms allow readers of the table to determine expected cash flows from the market risk sensitive instruments for each of the next five years. At December 31, 2015, we had commodity derivative contracts relating to production through 2020.
69
We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of December 31, 2015, we had approximately $111.5 million outstanding under our Senior Credit Facility, which is subject to variable rates of interest, and had $675.0 million of Senior Notes outstanding subject to a fixed interest rate. See Note 9, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes. Based on our total debt as of December 31, 2015 of approximately $787.1 million, a 1.0% change in interest rates would impact our interest expense by approximately $7.9 million.
We entered into fixed-to-variable interest rate swaps during 2015 and 2014; however, there were no arrangements in place as of December 31, 2015 and 2014. We utilize the mark-to-market accounting method to account for our interest rate swaps. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain on Derivatives, Net under Other Income (Expense). During the years ended December 31, 2015 and 2014, we received cash payments of approximately $0.9 million and $1.3 million, respectively related to our interest rate swaps.
70
REX ENERGY CORPORATION
71
Report of Independent Registered Public Accounting Firm
The Board of Directors
Rex Energy Corporation:
We have audited the accompanying consolidated balance sheets of Rex Energy Corporation and subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations, changes in noncontrolling interest and stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 15, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
KPMG LLP
Pittsburgh, Pennsylvania
March 15, 2016
72
($ in Thousands, Except Share and Per Share Data)
|
| December 31, 2015 |
|
| December 31, 2014 |
| ||
ASSETS |
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
| $ | 1,091 |
|
| $ | 17,978 |
|
Accounts Receivable |
|
| 19,483 |
|
|
| 43,936 |
|
Taxes Receivable |
|
| 18 |
|
|
| 504 |
|
Short-Term Derivative Instruments |
|
| 34,260 |
|
|
| 29,265 |
|
Inventory, Prepaid Expenses and Other |
|
| 3,829 |
|
|
| 3,403 |
|
Assets Held for Sale |
|
| — |
|
|
| 34,257 |
|
Total Current Assets |
|
| 58,681 |
|
|
| 129,343 |
|
Property and Equipment (Successful Efforts Method) |
|
|
|
|
|
|
|
|
Evaluated Oil and Gas Properties |
|
| 1,239,430 |
|
|
| 1,079,039 |
|
Unevaluated Oil and Gas Properties |
|
| 262,992 |
|
|
| 322,413 |
|
Other Property and Equipment |
|
| 40,112 |
|
|
| 46,361 |
|
Wells and Facilities in Progress |
|
| 144,556 |
|
|
| 127,655 |
|
Pipelines |
|
| 14,024 |
|
|
| 15,657 |
|
Total Property and Equipment |
|
| 1,701,114 |
|
|
| 1,591,125 |
|
Less: Accumulated Depreciation, Depletion and Amortization |
|
| (699,899 | ) |
|
| (366,917 | ) |
Net Property and Equipment |
|
| 1,001,215 |
|
|
| 1,224,208 |
|
Deferred Financing Costs and Other Assets – Net |
|
| 16,544 |
|
|
| 17,070 |
|
Equity Method Investments |
|
| — |
|
|
| 17,895 |
|
Long-Term Derivative Instruments |
|
| 9,534 |
|
|
| 4,904 |
|
Long-Term Deferred Tax Asset |
|
| 12,532 |
|
|
| 8,301 |
|
Total Assets |
| $ | 1,098,506 |
|
| $ | 1,401,721 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
Accounts Payable |
| $ | 37,874 |
|
| $ | 53,340 |
|
Current Maturities of Long-Term Debt |
|
| 590 |
|
|
| 1,176 |
|
Accrued Liabilities |
|
| 44,326 |
|
|
| 59,478 |
|
Short-Term Derivative Instruments |
|
| 2,486 |
|
|
| 421 |
|
Current Deferred Tax Liability |
|
| 12,532 |
|
|
| 8,301 |
|
Liabilities Related to Assets Held for Sale |
|
| — |
|
|
| 25,115 |
|
Total Current Liabilities |
|
| 97,808 |
|
|
| 147,831 |
|
8.875% Senior Notes Due 2020 |
|
| 350,000 |
|
|
| 350,000 |
|
6.25% Senior Notes Due 2022 |
|
| 325,000 |
|
|
| 325,000 |
|
Premium on Senior Notes, Net |
|
| 2,344 |
|
|
| 2,725 |
|
Senior Secured Line of Credit and Long-Term Debt |
|
| 111,528 |
|
|
| 251 |
|
Long-Term Derivative Instruments |
|
| 5,556 |
|
|
| 2,377 |
|
Other Deposits and Liabilities |
|
| 3,156 |
|
|
| 4,018 |
|
Future Abandonment Cost |
|
| 42,883 |
|
|
| 38,146 |
|
Total Liabilities |
| $ | 938,275 |
|
| $ | 870,348 |
|
Commitments and Contingencies (See Note 13) |
|
|
|
|
|
|
|
|
Stockholders’ Equity |
|
|
|
|
|
|
|
|
Preferred Stock, $.001 par value per share, 100,000 shares authorized and 16,100 issued and outstanding on December 31, 2015 and 2014. |
| $ | 1 |
|
| $ | 1 |
|
Common Stock, $.001 par value per share, 100,000,000 shares authorized and 55,741,229 shares issued and outstanding on December 31, 2015 and 54,174,763 shares issued and outstanding on December 31, 2014. |
|
| 54 |
|
|
| 54 |
|
Additional Paid-In Capital |
|
| 623,863 |
|
|
| 617,826 |
|
Accumulated Deficit |
|
| (463,687 | ) |
|
| (90,749 | ) |
Rex Energy Stockholders’ Equity |
|
| 160,231 |
|
|
| 527,132 |
|
73
|
| — |
|
|
| 4,241 |
| |
Total Stockholders’ Equity |
|
| 160,231 |
|
|
| 531,373 |
|
Total Liabilities and Stockholders’ Equity |
| $ | 1,098,506 |
|
| $ | 1,401,721 |
|
See accompanying notes to the consolidated financial statements
74
CONSOLIDATED STATEMENTS OF OPERATIONS
($ and Shares in Thousands, Except Per Share Data)
|
| Year Ended December 31, |
| |||||||||
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
OPERATING REVENUE |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Natural Gas and NGL Sales |
| $ | 171,951 |
|
| $ | 297,869 |
|
| $ | 213,919 |
|
Other Revenue |
|
| 42 |
|
|
| 118 |
|
|
| 200 |
|
TOTAL OPERATING REVENUE |
|
| 171,993 |
|
|
| 297,987 |
|
|
| 214,119 |
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
|
| 118,999 |
|
|
| 100,282 |
|
|
| 62,150 |
|
General and Administrative Expense |
|
| 29,435 |
|
|
| 36,137 |
|
|
| 30,839 |
|
(Gain) Loss on Disposal of Asset |
|
| (477 | ) |
|
| 644 |
|
|
| 1,602 |
|
Impairment Expense |
|
| 345,775 |
|
|
| 132,618 |
|
|
| 32,072 |
|
Exploration Expense |
|
| 3,011 |
|
|
| 9,446 |
|
|
| 11,408 |
|
Depreciation, Depletion, Amortization and Accretion |
|
| 104,744 |
|
|
| 94,467 |
|
|
| 62,386 |
|
Other Operating Expense |
|
| 5,595 |
|
|
| 134 |
|
|
| 592 |
|
TOTAL OPERATING EXPENSES |
|
| 607,082 |
|
|
| 373,728 |
|
|
| 201,049 |
|
INCOME (LOSS) FROM OPERATIONS |
|
| (435,089 | ) |
|
| (75,741 | ) |
|
| 13,070 |
|
OTHER EXPENSE |
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
| (47,806 | ) |
|
| (36,977 | ) |
|
| (22,676 | ) |
Gain (Loss) on Derivatives, Net |
|
| 60,176 |
|
|
| 38,876 |
|
|
| (2,908 | ) |
Other Income (Expense) |
|
| (115 | ) |
|
| 90 |
|
|
| 6,739 |
|
Loss on Equity Method Investments |
|
| (411 | ) |
|
| (813 | ) |
|
| (763 | ) |
TOTAL OTHER INCOME (EXPENSE) |
|
| 11,844 |
|
|
| 1,176 |
|
|
| (19,608 | ) |
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAX |
|
| (423,245 | ) |
|
| (74,565 | ) |
|
| (6,538 | ) |
Income Tax Benefit |
|
| 24,227 |
|
|
| 26,915 |
|
|
| 4,154 |
|
NET LOSS FROM CONTINUING OPERATIONS |
|
| (399,018 | ) |
|
| (47,650 | ) |
|
| (2,384 | ) |
Income From Discontinued Operations, Net of Income Taxes |
|
| 37,985 |
|
|
| 5,000 |
|
|
| 1,811 |
|
NET LOSS |
|
| (361,033 | ) |
|
| (42,650 | ) |
|
| (573 | ) |
Net Income Attributable to Noncontrolling Interests |
|
| 2,245 |
|
|
| 4,039 |
|
|
| 1,557 |
|
NET LOSS ATTRIBUTABLE TO REX ENERGY |
| $ | (363,278 | ) |
| $ | (46,689 | ) |
| $ | (2,130 | ) |
Preferred Stock Dividends |
|
| 9,660 |
|
|
| 2,335 |
|
|
| — |
|
NET LOSS ATTRIBUTABLE TO COMMON SHAREHOLDERS |
| $ | (372,938 | ) |
| $ | (49,024 | ) |
| $ | (2,130 | ) |
Earnings per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders |
| $ | (7.51 | ) |
| $ | (0.94 | ) |
| $ | (0.05 | ) |
Basic – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders |
|
| 0.66 |
|
|
| 0.02 |
|
|
| 0.01 |
|
Basic – Net Loss Attributable to Rex Energy Common Shareholders |
| $ | (6.85 | ) |
| $ | (0.92 | ) |
| $ | (0.04 | ) |
Basic – Weighted Average Shares of Common Stock Outstanding |
|
| 54,392 |
|
|
| 53,150 |
|
|
| 52,572 |
|
Diluted – Net Loss From Continuing Operations Attributable to Rex Energy Common Shareholders |
| $ | (7.51 | ) |
| $ | (0.94 | ) |
| $ | (0.05 | ) |
Diluted – Net Income From Discontinued Operations Attributable to Rex Energy Common Shareholders |
|
| 0.66 |
|
|
| 0.02 |
|
|
| 0.01 |
|
Diluted – Net Loss Attributable to Rex Energy Common Shareholders |
| $ | (6.85 | ) |
| $ | (0.92 | ) |
| $ | (0.04 | ) |
Diluted – Weighted Average Shares of Common Stock Outstanding |
|
| 54,392 |
|
|
| 53,150 |
|
|
| 52,572 |
|
See accompanying notes to the consolidated financial statements
75
CONSOLIDATED STATEMENTS OF CHANGES IN NONCONTROLLING INTERESTS
AND STOCKHOLDERS’ EQUITY
(in Thousands)
|
| Common Stock |
|
| Preferred Stock |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||||||
|
| Shares |
|
| Par Value |
|
| Shares |
|
| Par Value |
|
| Additional Paid- In Capital |
|
| Accumulated Deficit |
|
| Rex Energy Stockholders' Equity |
|
| Noncontrolling Interests |
|
| Total Stockholders’ Equity |
| |||||||||
BALANCE December 31, 2012 |
|
| 53,213 |
|
| $ | 52 |
|
|
| — |
|
| $ | — |
|
| $ | 451,062 |
|
| $ | (39,595 | ) |
| $ | 411,519 |
|
| $ | 775 |
|
| $ | 412,294 |
|
Non-Cash Compensation |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 5,418 |
|
|
| — |
|
|
| 5,418 |
|
|
| — |
|
|
| 5,418 |
|
Issuance of Restricted Stock, Net of Forfeitures |
|
| 924 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock Option Exercise |
|
| 49 |
|
|
| 2 |
|
|
| — |
|
|
| — |
|
|
| 534 |
|
|
| — |
|
|
| 536 |
|
|
| — |
|
|
| 536 |
|
Capital Distributions |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (886 | ) |
|
| (886 | ) |
Change in Ownership of Noncontrolling Interests |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (460 | ) |
|
| — |
|
|
| (460 | ) |
|
| 596 |
|
|
| 136 |
|
Net Income (Loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2,130 | ) |
|
| (2,130 | ) |
|
| 1,557 |
|
|
| (573 | ) |
BALANCE December 31, 2013 |
|
| 54,186 |
|
| $ | 54 |
|
| $ | — |
|
| $ | — |
|
| $ | 456,554 |
|
| $ | (41,725 | ) |
| $ | 414,883 |
|
| $ | 2,042 |
|
| $ | 416,925 |
|
Non-Cash Compensation |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 5,769 |
|
|
| — |
|
|
| 5,769 |
|
|
| — |
|
|
| 5,769 |
|
Issuance of Restricted Stock, Net of Forfeitures |
|
| (58 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Stock Option Exercise |
|
| 47 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 515 |
|
|
| — |
|
|
| 515 |
|
|
| — |
|
|
| 515 |
|
Capital Distributions |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (1,840 | ) |
|
| (1,840 | ) |
Issuance of Preferred Stock |
|
| — |
|
|
| — |
|
|
| 16 |
|
|
| 1 |
|
|
| 154,988 |
|
|
| — |
|
|
| 154,989 |
|
|
| — |
|
|
| 154,989 |
|
Dividends Declared on Preferred Stock ($145.00 per preferred share) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2,335 | ) |
|
| (2,335 | ) |
|
| — |
|
|
| (2,335 | ) |
Net Income (Loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (46,689 | ) |
|
| (46,689 | ) |
|
| 4,039 |
|
|
| (42,650 | ) |
BALANCE December 31, 2014 |
|
| 54,175 |
|
| $ | 54 |
|
| $ | 16 |
|
| $ | 1 |
|
| $ | 617,826 |
|
| $ | (90,749 | ) |
| $ | 527,132 |
|
| $ | 4,241 |
|
| $ | 531,373 |
|
Non-Cash Compensation |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 6,469 |
|
|
| — |
|
|
| 6,469 |
|
|
| — |
|
|
| 6,469 |
|
Issuance of Restricted Stock, Net of Forfeitures |
|
| 1,566 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Capital Distributions |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (830 | ) |
|
| (830 | ) |
Sale of Consolidated Subsidiary |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (432 | ) |
|
| — |
|
|
| (432 | ) |
|
| (5,656 | ) |
|
| (6,088 | ) |
Dividends Declared on Preferred Stock ($600.00 per preferred share) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (9,660 | ) |
|
| (9,660 | ) |
|
| — |
|
|
| (9,660 | ) |
Net Income (Loss) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (363,278 | ) |
|
| (363,278 | ) |
|
| 2,245 |
|
|
| (361,033 | ) |
BALANCE December 31, 2015 |
|
| 55,741 |
|
| $ | 54 |
|
|
| 16 |
|
| $ | 1 |
|
| $ | 623,863 |
|
| $ | (463,687 | ) |
| $ | 160,231 |
|
| $ | - |
|
| $ | 160,231 |
|
See accompanying notes to the consolidated financial statements
76
CONSOLIDATED STATEMENTS OF CASH FLOWS
($ in Thousands)
|
| For the Years Ended December 31, |
| |||||||||
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss |
| $ | (361,033 | ) |
| $ | (42,650 | ) |
| $ | (573 | ) |
Adjustments to Reconcile Net Loss to Net Cash Provided by Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
Loss on Equity Method Investments |
|
| 411 |
|
|
| 813 |
|
|
| 763 |
|
Non-cash Expenses |
|
| 7,649 |
|
|
| 6,789 |
|
|
| 6,230 |
|
Depreciation, Depletion, Amortization and Accretion |
|
| 104,822 |
|
|
| 98,171 |
|
|
| 63,944 |
|
(Gain) Loss on Derivatives |
|
| (60,176 | ) |
|
| (38,876 | ) |
|
| 2,908 |
|
Cash Settlements of Derivatives |
|
| 55,793 |
|
|
| 7,281 |
|
|
| 7,128 |
|
Dry Hole Expense |
|
| 330 |
|
|
| 4,064 |
|
|
| 2,993 |
|
Deferred Income Tax Expense (Benefit) |
|
| — |
|
|
| (25,992 | ) |
|
| 2,279 |
|
Impairment Expense |
|
| 345,775 |
|
|
| 132,684 |
|
|
| 32,072 |
|
(Gain) Loss on Sale of Assets and Equity Method Investments |
|
| (521 | ) |
|
| 589 |
|
|
| (6,211 | ) |
Gain on Sale of Water Solutions |
|
| (57,778 | ) |
|
| — |
|
|
| — |
|
Changes in operating assets and liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Receivable |
|
| 21,679 |
|
|
| (13,620 | ) |
|
| (12,726 | ) |
Inventory, Prepaid Expenses and Other Assets |
|
| (568 | ) |
|
| (1,359 | ) |
|
| (885 | ) |
Accounts Payable and Accrued Liabilities |
|
| (22,955 | ) |
|
| 37,274 |
|
|
| 12,891 |
|
Other Assets and Liabilities |
|
| (2,543 | ) |
|
| (2,462 | ) |
|
| (2,497 | ) |
NET CASH PROVIDED BY OPERATING ACTIVITIES |
|
| 30,885 |
|
|
| 162,706 |
|
|
| 108,316 |
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from Joint Venture Acreage Management |
|
| 58 |
|
|
| 263 |
|
|
| 458 |
|
Contributions to Equity Method Investments |
|
| — |
|
|
| — |
|
|
| (2,493 | ) |
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets |
|
| 77,226 |
|
|
| 546 |
|
|
| 11,305 |
|
Proceeds from Joint Venture |
|
| 16,611 |
|
|
| — |
|
|
| — |
|
Acquisitions of Undeveloped Acreage |
|
| (28,242 | ) |
|
| (169,423 | ) |
|
| (41,784 | ) |
Acquisitions of Oil and Gas Properties and Equipment |
|
| (221,099 | ) |
|
| (391,422 | ) |
|
| (281,004 | ) |
NET CASH USED IN INVESTING ACTIVITIES |
|
| (155,446 | ) |
|
| (560,036 | ) |
|
| (313,518 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds of Long-Term Debt and Lines of Credit |
|
| 229,314 |
|
|
| 209,895 |
|
|
| 72,249 |
|
Repayments from Long-Term Debt and Lines of Credit |
|
| (108,335 | ) |
|
| (263,152 | ) |
|
| (8,480 | ) |
Repayments of Loans and Other Notes Payable |
|
| (1,519 | ) |
|
| (2,721 | ) |
|
| (2,005 | ) |
Proceeds from Senior Notes, Net of Discounts and Premiums |
|
| — |
|
|
| 325,000 |
|
|
| 105,000 |
|
Debt Issuance Costs |
|
| (1,414 | ) |
|
| (6,824 | ) |
|
| (3,134 | ) |
Proceeds from the Issuance of Preferred Stock, Net |
|
| — |
|
|
| 154,988 |
|
|
| — |
|
Proceeds from the Exercise of Stock Options |
|
| — |
|
|
| 515 |
|
|
| 533 |
|
Purchase of Noncontrolling Interests |
|
| — |
|
|
| — |
|
|
| (150 | ) |
Distributions by the Partners of Consolidated Subsidiary |
|
| (830 | ) |
|
| (1,840 | ) |
|
| (886 | ) |
Dividends Paid on Preferred Stock |
|
| (9,660 | ) |
|
| (2,335 | ) |
|
| — |
|
NET CASH PROVIDED BY FINANCING ACTIVITIES |
|
| 107,556 |
|
|
| 413,526 |
|
|
| 163,127 |
|
NET INCREASE (DECREASE) IN CASH |
|
| (17,005 | ) |
|
| 16,196 |
|
|
| (42,075 | ) |
CASH AND CASH EQUIVALENTS – BEGINNING |
|
| 18,096 |
|
|
| 1,900 |
|
|
| 43,975 |
|
CASH AND CASH EQUIVALENTS – ENDING |
| $ | 1,091 |
|
| $ | 18,096 |
|
| $ | 1,900 |
|
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO CONTINUING OPERATIONS |
| $ | 1,091 |
|
| $ | 17,978 |
|
| $ | 1,307 |
|
CASH AND CASH EQUIVALENTS ATTRIBUTABLE TO ASSETS HELD FOR SALE |
| $ | — |
|
| $ | 118 |
|
| $ | 593 |
|
SUPPLEMENTAL DISCLOSURES |
|
|
|
|
|
|
|
|
|
|
|
|
Interest Paid, net of capitalized interest |
|
| 47,628 |
|
|
| 26,874 |
|
|
| 23,605 |
|
Cash Received for Income Taxes |
|
| (502 | ) |
|
| (4,643 | ) |
|
| (6,390 | ) |
77
See accompanying notes to the consolidated financial statements
78
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. | BASIS OF PRESENTATION AND PRINCIPLES OF CONSOLIDATION |
We are an independent oil, natural gas liquid (“NGL”) and natural gas company with operations currently focused in the Appalachian and Illinois Basins. In the Appalachian Basin, we are focused on our Marcellus Shale, Utica Shale and Upper Devonian (“Burkett”) Shale drilling and exploration activities. In the Illinois Basin, we are focused on developmental oil drilling on our properties. 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.
The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and include the accounts of all of our wholly owned subsidiaries. All material intercompany balances and transactions have been eliminated. Unless otherwise indicated, all references to “Rex Energy Corporation,” “our,” “we,” “us” and similar terms refer to Rex Energy Corporation and its subsidiaries together. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures of contingencies.
Our revolving credit facility requires we meet, on a quarterly basis, financial requirements of a minimum consolidated current ratio and a maximum net senior secured debt to EBITDAX ratio. EBITDAX is a non-GAAP measure used by our management team and by other users of our financial statements. For a definition of EBITDAX and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please see “Item 6. Selected Financial Data - Non-GAAP Financial Measures.” If we are unable to comply with these financial requirements, an event of default could result which would permit acceleration of outstanding debt and could permit our lenders to foreclose on our mortgaged properties. In order to improve our liquidity position to meet the financial requirements under our revolving credit facility and to meet other outstanding obligations, we are currently pursuing or considering a number of actions including (i) debt-for-debt exchanges, (ii) joint venture opportunities, (iii) minimizing our capital expenditures, (iv) improving our cash flows from operations, (v) effectively managing our working capital (vi) adding additional hedging positions (vii) and in- and out-of-court restructuring. There can be no assurance that sufficient liquidity can be raised from one or more of these transactions or that these transaction can be consummated within the period needed to meet certain obligations.
Discontinued Operations
Unless otherwise noted, all disclosures and tables reflect the results of continuing operations and exclude any assets, liabilities or results from our discontinued operations. For additional information see Note 4, Discontinued Operations/Assets Held for Sale, to our Consolidated Financial Statements.
During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. Pursuant to the rules for discontinued operations, the results of operations are reflected as Discontinued Operations in our Consolidated Statements of Operations for the year ended December 31, 2013.
During December 2014, our board of directors approved and committed to a plan to sell Water Solutions Holdings, LLC and its related subsidiaries (“Water Solutions”), of which we owned a 60% interest. The sale of Water Solutions closed in July 2015. As a result, the assets and liabilities of Water Solutions have been classified as held for sale in the accompanying Consolidated Balance Sheets as of December 31, 2014 and the results of operations have been classified as discontinued operations in the accompanying Consolidated Statements of Operations as of December 31, 2015, 2014 and 2013.
2. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES |
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates.
Estimates made in preparing these Consolidated Financial Statements include, among other things, estimates of the proved oil, NGL and natural gas reserve volumes used in calculating Depletion, Depreciation and Amortization (“DD&A”) expense; the estimated future cash flows and fair value of properties used in determining the need for any impairment; fair values of financial
79
derivative instruments; volumes and prices for revenues accrued; estimates of the fair value of equity-based compensation awards; deferred tax valuation allowance and the timing and amount of future abandonment costs used in calculating asset retirement obligations. Future changes in the assumptions used could have a significant impact on reported results in future periods. The estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates and our ability to generate future income.
Cash and Cash Equivalents
We consider all highly liquid investments with original maturity of three months or less when purchased to be cash equivalents. As of December 31, 2015 and 2014, our Cash and Cash Equivalents consisted of only cash.
Accounts Receivable
Our trade accounts receivable, which are primarily from oil, NGLs and natural gas sales and joint interest billings, are recorded at the invoiced amount and include production receivables. The production receivable is valued at the invoiced amount and does not bear interest. Accounts receivable also include joint interest billing receivables which represent billings to the non-operators associated with the drilling and operation of wells and are based on those owners’ working interests in the wells. We have assessed the financial strength of our customers and joint owners and record an allowance for bad debts as necessary. Our allowance for bad debts as of December 31, 2015 and 2014, was negligible.
To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Accounts Receivable in the accompanying Consolidated Balance Sheets.
At December 31, 2015, we carried approximately $12.1 million in production receivable, of which approximately $10.5 million were production receivables due from four purchasers. At December 31, 2014, we carried approximately $25.2 million in production receivables, of which approximately $21.4 million were production receivables due from four purchasers. In addition, we carried approximately $3.2 million in receivables at December 31, 2015 and $6.7 million at December 31, 2014 that was in relation to our joint operations with Sumitomo Corporation and ArcLight Capital Partners, LLC.
Inventory
Inventory is valued at the lower of cost or market value and consists of our ownership interest in oil and NGLs held in terminal tanks located in the field. Oil and NGL cost basis is calculated using the average cost method, with average cost defined as production and lease operating expenses net of DD&A. General and Administrative expenses are not allocated to the cost of inventory for the purpose of valuing inventory.
Oil, NGL and Natural Gas Property, Depreciation and Depletion
We account for oil, NGL and natural gas exploration and production activities under the successful efforts method of accounting. Proved developed natural gas and oil property acquisition costs are capitalized when incurred, including our estimate of the fair value of future abandonment costs. Unproved properties with individually significant acquisition costs are assessed periodically on a property-by-property basis, and any impairment in value is recognized. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved natural gas and oil properties. Natural gas and oil exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. Costs to develop estimated proved reserves, including the costs of all development well and related equipment used in the production of oil, NGLs and natural gas, are capitalized. We capitalize interest on capital projects, most notably during the drilling and completion of oil and natural gas wells. For the years ended December 31, 2015, 2014 and 2013, we capitalized interest costs of $7.7 million, $7.3 million and $7.5 million, respectively.
Depletion is calculated using the unit-of-production method. In arriving at rates under the unit-of-production method, the quantities of recoverable oil and natural gas are established based on estimates made by our geologists and engineers and independent engineers. We periodically review estimated proved reserve estimates and make changes as needed to depletion expenses to account for new wells drilled, acquisitions, divestitures and other events which may have caused significant changes in our estimated proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are proved. When estimated proved reserves are assigned, the cost of the property is added to costs subject to depletion calculations. Non-producing properties consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Undeveloped
80
leasehold cost is allocated to the associated producing properties as the undeveloped acreage is developed. Individually significant non-producing properties are periodically assessed for impairment of value. Service properties, equipment and other assets are depreciated using the straight-line method over their estimated useful lives of three to 40 years.
We review assets for impairment when events or circumstances indicate a possible decline in the recoverability of the carrying value of such property. When circumstances indicate that an asset may be impaired, we compare expected undiscounted future cash flows at a producing field to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimate of future oil, NGL and natural gas prices, operating costs, anticipated production from estimated proved reserves and other relevant data, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate. Our estimates of future oil, NGL and natural gas prices are based on forward strip prices for NYMEX oil and various natural gas markets that are relevant to our operations. For unproved oil and gas properties, we analyze activity on the acreage prior to evaluating any fair value indicators, such as current drilling activity, drilling success, future development plans and the likelihood of expiration. Unproved oil and gas properties are impaired when it becomes more likely than not that a property will expire before it can be developed or an extension can be agreed upon. When evaluating the value of our unproved oil, NGL and natural gas properties, we analyze the level and success of current development, future development plans and changes in market value. Performing the impairment evaluations requires use of judgments and estimates since the results are dependent on future events, including estimates of future proved and unproved reserves, future commodity prices, the timing of future production, capital expenditures and the intent to develop properties, among others.
We recognized approximately $345.8 million, $132.6 million and $32.1 million of impairment from continuing operations on certain oil, NGL and natural gas properties for the years ending December 31, 2015, 2014 and 2013, respectively. We recorded these charges as Impairment Expense on our Consolidated Statements of Operations. For additional information, see Note 16, Impairment Expense, to our Consolidated Financial Statements.
Expenditures for repairs and maintenance to sustain production from the existing producing reservoir are charged to expense as incurred. Expenditures to recomplete a current well in a different unproved reservoir are capitalized pending determination that economic reserves have been added. If the recompletion is not successful, the expenditures are charged to expense.
Significant tangible equipment added or replaced that extends the useful or productive life of the property is capitalized. Expenditures to construct facilities or increase the productive capacity from existing reservoirs are capitalized.
Upon the sale or retirement of a proved natural gas or oil property, or an entire interest in unproved leaseholds, the cost and related accumulated depletion are removed from the property accounts and the resulting gain or loss is recognized. For sales of a partial interest in unproved leaseholds for cash, sales proceeds are first applied as a reduction of the original cost of the entire interest in the property and any remaining proceeds are recognized as a gain.
Natural Gas and Oil Reserve Quantities
Our estimate of proved reserves is based on the quantities of oil, NGLs and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. For the years ended December 31, 2015 and 2014, Netherland Sewell and Associates, Inc. (“NSAI”) prepared a consolidated reserve and economic evaluation of our proved oil and gas reserves. The preparation of our proved reserve estimates are completed in accordance with our internal control procedures, which include the verification of input data used by NSAI, as well as management review and approval.
Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Estimates of our crude oil, NGL and natural gas reserves, and the projected cash flows derived from these reserve estimates, are prepared by our engineers in accordance with guidelines established by the SEC. The independent reserve engineer estimates reserves annually on December 31. This annual estimate results in a new depletion rate, which we use for the preceding fourth quarter after adjusting for fourth quarter production.
Deferred Financing Costs and Other Assets—Net
At December 31, 2015, we had deferred financing costs and other assets consisting of $16.5 million, which is primarily made up of bond costs and loan costs that are amortized using the effective interest method and the straight line method, respectively, over their estimated lives, which is, on average, five to eight years. We amortize any costs incurred to renew or extend the terms of existing debt
81
over the contract term or estimated useful life, as applicable. For the years ended December 31, 2015, 2014 and 2013, we recorded amortization expense from continuing operations of $2.0 million, $1.5 million and $1.2 million, respectively.
The following is a summary of our deferred financing costs at the dates indicated:
|
| December 31, 2015 (in thousands) |
|
| December 31, 2014 (in thousands) |
| ||
Deferred Financing Costs - Gross |
| $ | 20,623 |
|
| $ | 19,212 |
|
Accumulated Amortization |
|
| (6,580 | ) |
|
| (4,564 | ) |
Deferred Financing Costs - Net |
| $ | 14,043 |
|
| $ | 14,648 |
|
Specific to our deferred financing costs, we have incurred gross debt issuance costs of approximately $1.4 million and $6.8 million for the years ended December 31, 2015 and 2014, respectively, which are presented net of accumulated amortization of $6.6 million and $4.6 million, respectively, and include deferred financing from our senior notes and revolving line of credit.
Future Abandonment Cost
Future abandonment costs are recognized as obligations associated with the retirement of tangible long-lived assets that result from the acquisition and development of the asset. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which the natural gas or oil well is acquired or drilled. The future abandonment cost is capitalized as part of the carrying amount of our natural gas and oil properties at its discounted fair value. The liability is then accreted each period until the liability is settled or the natural gas or oil well is sold, at which time the liability is reversed. If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the asset retirement cost.
Accretion expense from continuing operations during the years ended December 31, 2015, 2014 and 2013 totaled approximately $3.8 million, $3.6 million and $3.0 million, respectively. These amounts are recorded as DD&A on our Consolidated Statements of Operations. As of December 31, 2015 and 2014, approximately $2.2 million and $2.0 million, respectively, of our Future Abandonment Costs were classified as short-term liabilities under the caption Accrued Liabilities on our Consolidated Balance Sheets. During 2015 and 2014, we recognized an increase of $2.4 million and $8.4 million, respectively, in the estimated present value of our asset retirement obligations, representing an increase in the estimate to plug and abandon our oil and natural gas wells. The revised estimates were primarily the result of increased abandonment cost estimates, which were driven by the trends of actual outcomes. We account for asset retirement obligations that relate to wells that are drilled jointly based on our interest in those wells.
|
| December 31, 2015 (in thousands) |
|
| December 31, 2014 (in thousands) |
| ||
Beginning Balance |
| $ | 40,099 |
|
| $ | 28,525 |
|
Asset Retirement Obligation Incurred |
|
| 1,135 |
|
|
| 1,480 |
|
Asset Retirement Obligation Settled |
|
| (2,273 | ) |
|
| (1,943 | ) |
Asset Retirement Obligation Cancelled or Sold Properties |
|
| (136 | ) |
|
| (10 | ) |
Asset Retirement Obligation Revision of Estimated Obligation |
|
| 2,428 |
|
|
| 8,426 |
|
Asset Retirement Obligation Accretion Expense |
|
| 3,821 |
|
|
| 3,621 |
|
Total Future Abandonment Costs |
| $ | 45,074 |
|
| $ | 40,099 |
|
Revenue Recognition
Oil, NGL and natural gas revenue is recognized when the oil, NGL or natural gas is delivered to or collected by the respective purchaser, a sales agreement exists, collection for amounts billed is reasonably assured and the sales price is fixed or determinable. Title to the produced quantities transfers to the purchaser at the time the purchaser collects or receives the quantities. In the case of oil and NGL sales, title is transferred to the purchaser when the oil or NGLs leaves our stock tanks and enters the purchaser’s trucks. In the case of gas production, title is transferred when the gas passes through the meter of the purchaser. It is the measurement of the purchaser that determines the amount of oil, NGL or natural gas purchased. Prices for such production are defined in sales contracts and are readily determinable based on certain publicly available indices. The purchasers of such production have historically made payment for oil, NGLs and natural gas purchases within 30-60 days of the end of each production month. We periodically review the difference between the dates of production and the dates we collect payment for such production to ensure that receivables from those purchasers are collectible. The point of sale for our oil, NGL and natural gas production is at its applicable field gathering system. We do not recognize revenue for oil and NGL production held in stock tanks before delivery to the purchaser.
82
To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties are estimated and recorded as Oil, Natural Gas and NGL Sales on the Statements of Operations.
Derivative Instruments
We use put and call options (collars), fixed rate swap contracts, swaptions, puts, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars to manage price risks in connection with the sale of oil, natural gas and NGLs. We have also used interest rate swap agreements to manage interest rate exposure associated with our fixed rate senior notes. We have established the fair value of all derivative instruments using estimates determined by our counterparties and other third-parties. These values are based upon, among other things, future prices, volatility, time to maturity and credit risk. The values we report in our Consolidated Financial Statements change as these estimates are revised to reflect actual results, changes in market conditions or other factors.
We report our derivative instruments at fair value and include them in the Consolidated Balance Sheets as assets or liabilities. The accounting for changes in fair value of a derivative instrument depends on the intended use of the derivative and the resulting designation, which is established at the inception of a derivative. For derivative instruments designated for hedge accounting, for financial accounting purposes, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any changes in fair value resulting from ineffectiveness are recognized immediately in earnings. During 2015, 2014 and 2013 we did not have any derivative instruments designated for hedge accounting.
For derivative instruments designated as fair value hedges, changes in fair value, as well as the offsetting changes in the estimated fair value of the hedged item attributable to the hedged risk, are recognized currently in earnings. Derivative effectiveness is measured annually based on the relative changes in fair value between the derivative contract and the hedged item over time. For derivatives on oil, natural gas and NGL production activity, our evaluations are not documented, and as a result, we record changes on the derivative valuations through earnings. For additional information on our derivative instruments, see Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.
Contingent Liabilities
A provision for legal, environmental and other contingent matters is charged to expense when the loss is probable and the cost or range of cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental and contingent matters. In addition, we often must estimate the amount of such losses. In many cases, our judgment is based on the input of our legal advisors and on the interpretation of laws and regulations, which can be interpreted differently by regulators and/or the courts. We monitor known and potential legal, environmental and other contingent matters and make our best estimate of when to record losses for these matters based on available information.
Income Taxes
We are subject to income and other taxes in all areas in which we operate. When recording income tax expense, certain estimates are required because income tax returns are generally filed several months after the close of a calendar year, tax returns are subject to audit which can take years to complete, and future events often impact the timing of when income tax expenses and benefits are recognized. We have deferred tax assets relating to tax operating loss carryforwards and other deductible differences and deferred tax liabilities that relate to oil and gas properties and other taxable differences.
Deferred tax assets and liabilities are computed based on the difference between the financial statement and income tax basis of assets and liabilities using the enacted tax rates. Net deferred tax assets are required to be reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of the net deferred tax asset will not be realized.
This process requires our management to make assessments regarding the timing and probability of the ultimate tax impact. We record valuation allowances on deferred tax assets if we determine it is more likely than not that the asset will not be realized. Actual income taxes could vary from these estimates due to future changes in income tax law, significant changes in the jurisdictions in which we operate, our inability to generate sufficient future taxable income, or unpredicted results from the final determination of each year’s liability by taxing authorities. These changes could have a significant impact on our financial position.
The accounting estimate related to the tax valuation allowance requires us to make assumptions regarding the timing of future events, including the probability of expected future taxable income and available tax planning opportunities. These assumptions require significant judgment because actual performance has fluctuated in the past and may do so in the future. The impact that changes in actual performance versus these estimates could have on the realization of tax benefits as reported in our results of
83
operations could be material. We continuously evaluate facts and circumstances representing positive and negative evidence in the determination of our ability to realize the deferred tax assets.
We recognize a tax position if it is more likely than not that it will be sustained upon examination. If we determine it is more likely than not a tax position will be sustained based on its technical merits, we record the impact of the position in our Consolidated Financial Statements at the largest amount that is greater than fifty percent likely of being realized upon ultimate settlement. These estimates are updated at each reporting date based on the facts, circumstances and information available. We are also required to assess at each reporting date whether it is reasonably possible that any significant increases or decreases to the unrecognized tax benefits will occur during the next twelve months (for additional information, see Note 11, Income Taxes, to our Consolidated Financial Statements). Our policy is to recognize interest and penalties on any unrecognized tax benefits in interest expense and general and administrative expense, respectively.
Stock-based Compensation
We recognize in the Consolidated Financial Statements the cost of employee and non-employee director services received in exchange for awards of equity instruments based on the grant date fair value of those awards. We use a standard option pricing model (i.e. Black-Scholes) to measure the fair value of employee stock options and stock appreciation rights and a Monte Carlo simulation technique to value restricted stock awards that are tied to market performance. The fair value of non-market based restricted stock awards is determined based on the fair market value of our common stock on the date of the grant.
The benefits associated with the tax deductions in excess of recognized compensation cost are reported as a financing cash flow when realized. We recognize compensation costs related to awards with graded vesting on a straight-line basis over the requisite service period for each separately vesting portion of the award as if the award were, in-substance, multiple awards (for additional information, see Note 15, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). Stock appreciation rights are classified as a liability and are re-measured at fair value each reporting period.
Earnings per Common Share
Earnings per common share are computed by dividing consolidated net income attributable to us by the weighted average number of common shares outstanding. Diluted earnings per common share are computed based upon the weighted average number of common shares outstanding during the period plus the assumed issuance of common shares for all potentially dilutive securities, including the assumed conversion of preferred stock. At December 31, 2015, we had 55,741,229 common shares outstanding, 443,672 options outstanding and 20,500 stock appreciation rights outstanding with no outstanding warrants or other potentially dilutive securities. The total common shares outstanding include 2,479,408 restricted stock awards, of which approximately 1,065,296 shares are performance-based awards. For additional information, see Note 12, Earnings per Common Share, to our Consolidated Financial Statements.
Recent Accounting Pronouncements
In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements – Going Concern (Subtopic 205-40). The new guidance addresses management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern and in certain circumstances to provide related footnote disclosures. The standard is effective for the annual period ending after December 15, 2016 and for annual and interim periods thereafter. Early adoption is permitted. We adopted this ASU on January 1, 2016. Adoption did not have a material impact on our Consolidated Financial Statements.
In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis. The amendments in this ASU intend to improve targeted areas of consolidation guidance for legal entities such as limited partnerships, limited liability corporations and securitization structures. The ASU focuses on the consolidation evaluation for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. In addition to reducing the number of consolidation models from four to two, the new standard places more emphasis on risk of loss when determining a controlling financial interest, reduces the frequency of the application of related-party guidance when determining a controlling financial interest in a variable interest entity and changes consolidation conclusions in several industries that typically make use of limited partnerships or variable interest entities. This ASU will be effective for periods beginning after December 15, 2015, for public companies, and early adoption is permitted, including adoption in an interim period. We are currently evaluating the potential effect of this ASU but do not believe that it will have a material impact on our Consolidated Financial Statements.
In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The standard requires an entity to present debt issuance costs related to a recognized liability as a direct
84
deduction from the carrying amount of that debt liability, consistent with debt discounts. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements. As of December 31, 2015, we had approximately $14.0 million in net deferred financing costs that would be potentially reclassified to reduce the debt carrying balance.
In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. The amendments in this ASU affects any entity using U.S. GAAP that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards. This ASU will supersede the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services by following five steps:
1) Identify the contract(s) with a customer.
2) Identify the performance obligations in the contract.
3) Determine the transaction price.
4) Allocate the transaction price to the performance obligations in the contract.
5) Recognize revenue when (or as) the entity satisfies a performance obligation.
An entity should apply the amendments in this ASU using one of the following two methods:
1) Retrospectively to each prior reporting period presented.
2) Retrospectively with the cumulative effect of initially applying this ASU recognized at the date of the initial applications.
In July 2015, the FASB approved a one-year deferral of the effective date of this new standard so the guidance is effective for the reporting period beginning January 1, 2018, with early adoption permitted in the first quarter 2017. We are currently evaluating the new guidance and have not determined the impact this standard may have on our Consolidated Financial Statements or decided upon the method of adoption.
In August 2015, the FASB issued ASU 2015-15, Interest – Imputation of Interest (Subtopic 835-30), Presentation and Subsequent Measurement of Debt Issuance Costs with Line-of-Credit Arrangements. This ASU clarifies the presentation of debt issuance costs associated with line-of-credit arrangements. In April 2015, the FASB issued ASU 2015-03, Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, which requires the presentation of debt issuance costs related to a recognized debt liability as a direct deduction from the carrying amount of that debt liability. ASU 2015-03 does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in the ASU is effective for public entities for annual reporting periods beginning after December 15, 2015, including interim periods therein. Early adoption is permitted. We are currently evaluating the potential effect of this ASU and the related impact on our Consolidated Financial Statements.
3. | BUSINESS AND OIL AND GAS PROPERTY ACQUISITIONS AND DISPOSITIONS |
Acquisitions
On September 9, 2014, we completed the acquisition of approximately 208,000 gross (207,000 net) acres prospective for the Marcellus, Upper Devonian/Burkett and Utica Shales from SWEPI, LP, an affiliate of Royal Dutch Shell, plc (“Shell”), for approximately $120.6 million in cash, after customary closing adjustments. Included in the acquisition were several producing wells and properties in various stages of development. The assets acquired are located in Armstrong, Beaver, Butler, Lawrence, Mercer and Venango counties in Pennsylvania and Columbiana and Mahoning counties in Ohio. The acquisition does not meet the definition of a business combination and, therefore, has been accounted for as an asset acquisition. The acquisition price was allocated as follows:
85
($ in Thousands) |
| December 31, 2014 |
| |
Evaluated Oil and Gas Properties |
| $ | 6,968 |
|
Unevaluated Oil and Gas Properties |
|
| 88,351 |
|
Wells and Facilities in Progress |
|
| 25,244 |
|
Purchase Price |
| $ | 120,563 |
|
Dispositions
Water Solutions
In December 2014, our board of directors approved a formal plan to sell Water Solutions, of which we owned a 60% interest. In June 2015, we entered into a purchase and sale agreement with American Water Works Company, Inc. (“American Water”) pursuant to which American Water acquired Water Solutions for consideration of approximately $130.0 million, inclusive of cash and debt and subject to other customary adjustments. The sale closed in July 2015, and we received approximately $66.8 million in net proceeds, resulting in a gain of approximately $57.8 million. The transaction is recorded as Discontinued Operations.
ArcLight Capital Partners, LLC
On March 31, 2015, we entered into a joint venture agreement with an affiliate of ArcLight Capital Partners, LLC (“ArcLight”) to jointly develop 32 specifically designated wells in our Butler County, Pennsylvania operated area. ArcLight will participate and fund 35.0% of the estimated well costs for the designated wells. We expect to receive total consideration for the transaction of approximately $67.0 million, of which $16.6 million was received at closing for wells that had previously been completed or were at that time in the process of being drilled and completed. As of December 31, 2015, ArcLight had paid approximately $39.8 million for their interest in wells that have been drilled or are in the process of being drilled. The remainder of the proceeds will be received as additional wells are and completed and placed into service. 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, leaving ArcLight with a 17.5% working interest.
The ArcLight transaction constitutes a pooling of assets in a joint undertaking to develop these specific properties for which there is substantial uncertainty about the ability to recover the costs applicable to our interest in the properties. Under the terms of the agreement, we hold a substantial obligation for future performance, which may not be proportionally reimbursed by ArcLight. Due to the uncertainty that exists on the recoverability of costs associated with our retained interest, proceeds received from ArcLight are considered a recovery of costs and no gain or loss is recognized. Due to the fixed payment per well structure of the transaction, payments by ArcLight are treated as gains or losses, as appropriate, on a well-by-well basis for tax purposes.
Keystone Midstream Services, LLC
On May 29, 2012, we closed the sale of our ownership in Keystone Midstream Services, LLC (“Keystone Midstream”), which we had accounted for as an equity method investment. The base consideration for the sale was $483.2 million after adjustments for closing cash, working capital and outstanding debt. Our net proceeds at closing totaled $121.4 million, net of $3.3 million for our share of transactional costs which we recorded as Gain (Loss) on Equity Method Investments on our Consolidated Statement of Operations. During the third quarter of 2012, we recorded $0.5 million of post-closing settlement charges, effectively decreasing our net proceeds to approximately $120.9 million. We have used the proceeds to pay down amounts outstanding under our Senior Credit Facility and for working capital. The amount received at closing excluded approximately $14.3 million held in escrow to be paid out over the course of the 12 months following closing. During 2012, we received approximately $7.2 million of the outstanding escrow amount and during 2013 we received final distributions from the escrow of approximately $6.9 million, with the remaining amounts funding claims made by the purchaser. Also included in the proceeds at closing was approximately $3.8 million funded by other sellers in the transaction as consideration for our entry into an amendment to one of our gas gathering, compression and processing agreements. This consideration is recorded as Other Deposits and Liabilities on our Consolidated Balance Sheet and will be recognized in earnings over the term of the gas gathering, compression and processing agreement. We recognized a gain on the sale of our investment of Keystone Midstream, including the post-closing adjustment of $0.5 million and the receipt of the escrow funds of $7.2 million, of $99.4 million, in 2012 and a gain of approximately $6.9 million in 2013, all of which were recorded as Other Income (Expense) in our Consolidated Statement of Operations. See Note 5, Equity Method Investments, to our Consolidated Financial Statements for additional information on Keystone Midstream.
4. | DISCONTINUED OPERATIONS/ASSETS HELD FOR SALE |
DJ Basin
During December 2011, our board of directors approved a formal plan to sell our DJ Basin assets located in the states of Wyoming and Colorado. During 2012, we sold various parcels of acreage throughout our DJ Basin. During the first quarter of 2013,
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we entered an agreement to sell our remaining DJ Basin assets for $3.1 million. This transaction closed during the second quarter of 2013 and resulted in a gain of approximately $1.0 million. As of December 31, 2015 and 2014, we had no assets or liabilities related to the DJ Basin or continuing cash flows from this region.
Summarized financial information for Discontinued Operations related to our DJ Basin assets is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
|
| December 31, |
| |||||||||
($ in Thousands) |
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Natural Gas and NGL Sales |
| $ | — |
|
| $ | — |
|
| $ | 25 |
|
Total Operating Revenue |
|
| — |
|
|
| — |
|
|
| 25 |
|
Costs and Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
|
| — |
|
|
| — |
|
|
| 104 |
|
General and Administrative Expense |
|
| — |
|
|
| — |
|
|
| 23 |
|
Exploration Expense |
|
| — |
|
|
| — |
|
|
| 97 |
|
Other Operating Income |
|
| — |
|
|
| — |
|
|
| (3 | ) |
Gain on Disposal of Asset |
|
| — |
|
|
| — |
|
|
| (969 | ) |
Total Income |
|
| — |
|
|
| — |
|
|
| (748 | ) |
Income from Discontinued Operations Before Income Taxes |
|
| — |
|
|
| — |
|
|
| 773 |
|
Income Tax Expense |
|
| — |
|
|
| — |
|
|
| (1,005 | ) |
Loss from Discontinued Operations, net of taxes |
| $ | — |
|
| $ | — |
|
| $ | (232 | ) |
Production: |
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil (Bbls) |
|
| — |
|
|
| — |
|
|
| 356 |
|
Water Solutions Holdings, LLC
As described in Note 3 above, we sold Water Solutions pursuant to a purchase and sale agreement with American Water.
The carrying value of the assets and liabilities of Water Solutions Holdings, LLC that are classified as held for sale in the accompanying Consolidated Balance Sheet at December 31, 2014 are as follows:
87
| December 31, |
| ||
($ in Thousands) |
| 2014 |
| |
Assets: |
|
|
|
|
Cash and Cash Equivalents |
| $ | 118 |
|
Accounts Receivable |
|
| 13,226 |
|
Inventory, Prepaid Expenses and Other |
|
| 163 |
|
Total Current Assets |
|
| 13,507 |
|
Other Property and Equipment, Net |
|
| 19,690 |
|
Wells and Facilities in Progress |
|
| 688 |
|
Intangible Assets, Net |
|
| 372 |
|
Total Long-Term Assets |
|
| 20,750 |
|
Total Assets Held for Sale |
| $ | 34,257 |
|
Liabilities: |
|
|
|
|
Accounts Payable |
|
| 3,694 |
|
Current Maturities of Long-Term Debt |
|
| 6,236 |
|
Accrued Liabilities |
|
| 6,304 |
|
Total Current Liabilities |
|
| 16,234 |
|
Senior Secured Line of Credit and Long-Term Debt |
|
| 8,881 |
|
Long-Term Liabilities |
|
| 8,881 |
|
Total Liabilities Related to Assets Held for Sale |
| $ | 25,115 |
|
Net Assets Held for Sale: |
| $ | 9,142 |
|
Summarized financial information for Discontinued Operations related to Water Solutions is set forth in the table below, and does not reflect the costs of certain services provided. Such costs, which were not allocated to the Discontinued Operations, were for services, including legal counsel, insurance, external audit fees, payroll processing, certain human resource services and information technology systems support.
|
| December 31, |
| |||||||||
($ in Thousands) |
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Field Services Revenue |
| $ | 33,086 |
|
| $ | 58,627 |
|
| $ | 23,812 |
|
Total Operating Revenue |
|
| 33,086 |
|
|
| 58,627 |
|
|
| 23,812 |
|
Costs and Expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
General and Administrative Expense |
|
| 1,961 |
|
|
| 4,081 |
|
|
| 2,287 |
|
Depreciation, Depletion, Amortization and Accretion |
|
| 78 |
|
|
| 3,703 |
|
|
| 1,559 |
|
Impairment Expense |
|
| — |
|
|
| 67 |
|
|
| - |
|
Field Service Operating Expense |
|
| 25,981 |
|
|
| 44,369 |
|
|
| 17,318 |
|
(Gain) Loss on Disposal of Asset |
|
| (44 | ) |
|
| (55 | ) |
|
| 46 |
|
Interest Expense |
|
| 487 |
|
|
| 628 |
|
|
| 106 |
|
Other (Income) Expense |
|
| (57,589 | ) |
|
| 66 |
|
|
| 84 |
|
Total Costs and Expenses (Income) |
|
| (29,126 | ) |
|
| 52,859 |
|
|
| 21,400 |
|
Income from Discontinued Operations Before Income Taxes |
|
| 62,212 |
|
|
| 5,768 |
|
|
| 2,412 |
|
Income Tax Expense |
|
| (24,227 | ) |
|
| (768 | ) |
|
| (369 | ) |
Income from Discontinued Operations, net of taxes |
|
| 37,985 |
|
| $ | 5,000 |
|
| $ | 2,043 |
|
During 2015, Water Solutions spent approximately $8.6 million in capital expenditures on facilities and equipment to support its business growth. In addition to its cash capital expenditures, Water Solutions incurred approximately $1.0 million in non-cash vehicle acquisitions primarily related to its capital lease program.
88
RW Gathering
RW Gathering, LLC (“RW Gathering”) is a Delaware limited liability company that we jointly own with WPX Energy Inc. (“WPX”) and Sumitomo, with our ownership equaling 40%. RW Gathering owns gas-gathering and other midstream assets that service jointly owned properties in Westmoreland and Clearfield Counties, Pennsylvania.
Our investment in RW Gathering totaled approximately $17.9 million as of December 31, 2014, and was recorded on our Consolidated Balance Sheet as Equity Method Investments. During the second quarter of 2015 we incurred a 100% impairment charge of $17.5 million related to RW Gathering (for additional information, see Note 16, Impairment Expense, to our Consolidated Financial Statements). We did not make any capital contributions to RW Gathering during 2015 and 2014. RW Gathering recorded net losses from continuing operations of $2.0 million, $2.0 million and $1.9 million for the years ended December 31, 2015, 2014 and 2013, respectively. The losses incurred were due to insurance fees, bank fees, rent expenses and DD&A expense. Our share of the net loss from continuing operations incurred by RW Gathering is recorded on the Statements of Operations as Loss on Equity Method Investments. As of June 30, 2015, we discontinued applying the equity method of accounting for our share of the net losses due to our investment being reduced to zero.
6. | CONCENTRATIONS OF CREDIT RISK |
At times during the years ended December 31, 2015 and 2014, our cash balance may have exceeded the Federal Deposit Insurance Corporation’s limit of $250,000. There were no losses incurred due to such concentrations.
By using derivative instruments to hedge exposure to changes in commodity prices, we are exposed to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of the derivative is positive, the counterparty owes us, which creates repayment risk. We minimize the credit or repayment risk in derivative instruments by entering into transactions with five high-quality counterparties. Our counterparties are investment grade financial institutions, and lenders in our Senior Credit Facility. We have a master netting agreement in place with our counterparties that provides for the offsetting of payables against receivables from separate derivative contracts. None of our derivative contracts have a collateral provision that would require funding prior to the scheduled settlement date. For additional information, see Note 2, Summary of Significant Accounting Policies, and Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements.
We also depend on a relatively small number of purchasers for a substantial portion of our revenue. At December 31, 2015, we carried approximately $12.1 million in production receivables, of which approximately $10.5 million were production receivables due from four purchasers. At December 31, 2014, we carried approximately $25.2 million in production receivables, of which approximately $21.4 million were production receivables due from four purchasers. We believe the growth in our Appalachian estimated proved reserves will help us to minimize our future risks by diversifying our ratio of oil and gas sales as well as the quantity of purchasers.
| 7. | COMMITMENTS AND CONTINGENCIES |
Legal Reserves
We are involved in various legal proceedings that arise in the ordinary course of our business. Although we cannot predict the outcome of these proceedings with certainty, we do not currently expect these matters to have a material adverse effect on our consolidated financial position or results of operations.
As of December 31, 2015 and 2014, we did not have any reserves established for future legal obligations. The establishment of a reserve involves an estimation process that includes the advice of legal counsel and the subjective judgment of management. While we currently believe that no reserve is needed, there are uncertainties associated with legal proceedings and we can give no assurance that our estimate of any related liability will not increase or decrease in the future. The unreserved exposures for our legal proceedings could change based upon developments in those proceedings or changes in the facts and circumstances. It is possible that we could incur future losses that are not currently accrued. Based on currently available information, we believe that it is remote that future costs, if any, would have a material adverse effect on our consolidated financial position, although cash flow could be significantly impacted in the reporting periods in which such costs might be incurred.
89
Due to the nature of the natural gas and oil business, we are exposed to possible environmental risks. We have implemented various policies and procedures to avoid environmental contamination and risks from environmental contamination. We conduct periodic reviews to identify changes our environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate salaries and wages cost of employees who are expected to devote a significant amount of time directly to any remediation effort.
We manage our exposure to environmental liabilities on properties to be acquired by conducting evaluations (both internal and using consultants) to identify existing problems and assessing the potential liability. Except for contingent liabilities associated with the consent decree with the U.S. EPA relating to alleged H 2S emissions in the Lawrence Field, we know of no significant probable or possible environmental contingent liabilities.
Letters of Credit
As of December 31, 2015 and 2014, we had posted $41.0 million and $6.0 million, respectively, in various letters of credit to secure our drilling and related operations. Approximately $39.8 million of the letters of credit outstanding at December 31, 2015 are related to firm natural gas transportation agreements.
Lease Commitments
At December 31, 2015 we had lease commitments for various real estate leases. Rent expense from continuing operations has been recorded in General and Administrative expense as $1.0 million, $0.8 million and $0.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Lease commitments by year for each of the next five years are presented in the table below.
($ in Thousands) |
|
|
|
|
2016 |
| $ | 1,058 |
|
2017 |
|
| 991 |
|
2018 |
|
| 565 |
|
2019 |
|
| 563 |
|
2020 |
|
| 422 |
|
Thereafter |
|
| — |
|
Total |
| $ | 3,599 |
|
Capacity Reservation
We are a party to a capacity reservation arrangement with a subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”) to ensure sufficient capacity at the cryogenic gas processing plants owned by MarkWest to process our produced natural gas. In the event that we do not process any gas through the cryogenic gas processing plants, we may be obligated to pay approximately $14.4 million in 2016, $16.4 million in 2017, $16.4 million in 2018, $16.4 million in 2019, $16.5 million in 2020 and $97.2 million thereafter, assuming our average working interest in the region of approximately 52.6%. For the years ended December 31, 2015, 2014 and 2013, we incurred capacity reservation charges of $0.6 million, $0.2 million and $0.3 million, respectively. Charges for the capacity reservation are recorded as Production and Lease Operating Expense on our Consolidated Statements of Operations.
Operational Commitments
We have contracted drilling rig services on one rig to support our Appalachian Basin operations. The minimum cost to retain this rig would require gross payments of approximately $2.3 million in 2016 and $2.3 million in 2017, which would be partially offset by other working interest owners, which vary from well to well. During the first quarter of 2015, we terminated two rig contracts earlier than their original term. To satisfy the early release, we incurred approximately $4.8 million in early termination fees, which were classified as Other Operating Expense in our Consolidated Statement of Operations as of December 31, 2015. Approximately $2.5 million of this amount was paid in January 2015 with the remaining amount paid in January 2016. We also have agreements for contracted completion services in the Appalachian Basin. The minimum gross cost to retain the completion services is approximately $4.0 million in 2016, which would be partially offset by other working interest owners, which vary from well to well.
90
Natural Gas Gathering, Processing and Sales Agreements
During the normal course of business we have entered into certain agreements to ensure the gathering, transportation, processing and sales of specified quantities of our oil, natural gas and NGLs. In some instances, we are obligated to pay shortfall fees, whereby we would pay a fee for any difference between actual volumes provided as compared to volumes that have been committed. In other instances, we are obligated to pay a fee on all volumes that are subject to the related agreement. In connection with our entry into certain of these agreements, we concurrently entered into a guaranty whereby we have guaranteed the payment of obligations under the specified agreements up to a maximum of $421.8 million.
For the years ended December 31, 2015, 2014 and 2013, we incurred expenses related to the transportation, processing and marketing our oil, natural gas and natural gas liquids of approximately $79.5 million, $55.4 million and $26.4 million, respectively.
Minimum net obligations under these sales, gathering and transportation agreements for the next five years are as follows:
($ in Thousands) |
| Total |
| |
2016 |
| $ | 23,836 |
|
2017 |
|
| 38,434 |
|
2018 |
|
| 39,993 |
|
2019 |
|
| 39,017 |
|
2020 |
|
| 37,744 |
|
Thereafter |
|
| 395,980 |
|
Total |
| $ | 575,004 |
|
Pennsylvania Impact Fee
In 2012, Pennsylvania instituted a natural gas impact fee on producers of unconventional natural gas. The fee will is imposed on every producer of unconventional natural gas and applies to unconventional wells spud in Pennsylvania regardless of when spudding occurred. Unconventional gas wells that were spud prior to 2012 are considered to be spud in 2011 for purposes of determining the fee, which is considered year one for those wells. The fee for each unconventional natural gas well is determined using the following matrix with vertical unconventional natural gas wells being charged 20%:
|
| <$2.25(a) |
|
| $2.26 - $2.99(a) |
|
| $3.00 - $4.99(a) |
|
| $5.00 - $5.99(a) |
|
| >$5.99(a) |
| |||||
Year One |
| $ | 40,200 |
|
| $ | 45,300 |
|
| $ | 50,300 |
|
| $ | 55,300 |
|
| $ | 60,400 |
|
Year Two |
| $ | 30,200 |
|
| $ | 35,200 |
|
| $ | 40,200 |
|
| $ | 45,300 |
|
| $ | 55,300 |
|
Year Three |
| $ | 25,200 |
|
| $ | 30,200 |
|
| $ | 30,200 |
|
| $ | 40,200 |
|
| $ | 50,300 |
|
Year 4 – 10 |
| $ | 10,100 |
|
| $ | 15,100 |
|
| $ | 20,100 |
|
| $ | 20,100 |
|
| $ | 20,100 |
|
Year 11 – 15 |
| $ | 5,000 |
|
| $ | 5,000 |
|
| $ | 10,100 |
|
| $ | 10,100 |
|
| $ | 10,100 |
|
(a) | Pricing utilized for determining annual fees is based on the arithmetic mean of the NYMEX settled price for the near-month contract as reported by the Wall Street Journal for the last trading day of each month of a calendar year for the year ending December 31. |
For the years ended December 31, 2015, 2014 and 2013, we incurred approximately $3.0 million, $4.1 million and $3.2 million, respectively, in fees related to the natural gas impact fee. We have recorded these fees as Production and Lease Operating Expense on our Consolidated Statement of Operations.
8. | RELATED PARTY TRANSACTIONS |
Aircraft Services
We have an oral month-to-month agreement with Charlie Brown Air Corp. (“Charlie Brown”), a New York corporation owned by Lance T. Shaner, our Chairman, regarding the use of one airplane owned or managed on our behalf by Charlie Brown. Under our agreement with Charlie Brown, we pay a monthly fee for the right to use the airplanes equal to our percentage (based upon the total number of hours of use of the airplanes by us) of the monthly fixed costs for the airplanes, plus a variable per hour flight rate that ranges from $700 to $1,560 per hour. For the years ended December 31, 2015 and 2014, we paid Charlie Brown $0.1 million and $0.1 million, respectively, for the use of the aircrafts, including the variable per hour cost in addition to pilot fees, maintenance, hangar rental and other miscellaneous expenses. For the year ended December 31, 2013, the amounts paid to Charlie Brown were negligible.
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We own a 50% membership interest in Charlie Brown Air II, LLC (“Charlie Brown II”). Shaner Hotel Group Limited Partnership, a Delaware limited partnership controlled by Mr. Lance T. Shaner (“Shaner Hotel”), in Charlie Brown II, which owns and operates an Eclipse 500 aircraft.
Charlie Brown II has a loan from Graystone Bank to purchase the aircraft that was originally $1.5 million at its inception in June 2007. The loan matures on June 21, 2017 and bears interest at a rate of LIBOR plus 2.5%. The loan required payments of interest only for the first three months of the loan. Thereafter, Charlie Brown II has been required to make monthly payments of principal and interest utilizing an amortization period of 180 months. The company and Shaner Hotel each guarantee up to fifty percent, or $0.8 million, of the principal balance of the loan. The balance of this loan as of December 31, 2015 and 2014 was approximately $1.0 million and $1.1 million, respectively. For the years ended December 31, 2015, 2014 and 2013, we paid Charlie Brown II approximately $0.3 million, $0.2 million and $0.2 million, respectively, for loan interest, services rendered and retainer fees.
The business affairs of Charlie Brown Air II, LLC are managed by two members, appointed by each of its two owners. We have designated Thomas C. Stabley, our President and Chief Executive Officer, as the manager representing our membership interest. Actions of the company must be approved by a majority of the interest percentages of the managers. Each manager votes in matters before the company in accordance with the membership interest percentage of the member that appointed the manager. Certain events, such as the sale by a member of its interest, the merger or consolidation of the company, the filing of bankruptcy, or the sale of the airplane owned by Charlie Brown Air II, LLC, require the written consent of both managers. The consent of managers is also required before the company may change or terminate the management agreement with Charlie Brown, incur any indebtedness, sell substantially all of the company’s assets or sell the airplane owned by the company. In the event that the members are unable to unanimously agree upon any of these matters within 10 days of the proposal of any such matter, an “impasse” may be declared, and the airplane will be sold by the company.
As of December 31, 2015, there were negligible amounts due to or from us to any Shaner affiliated entities.
Office Rental
On June 27, 2012, we entered into an office lease agreement with Shaner Office Holdings, L.P., a limited partnership controlled by Lance T. Shaner. The office lease, which replaced our former headquarters office lease in State College, Pennsylvania, calls for monthly rental payments in the amount of $35,000 which began on April 1, 2013 and ends on December 31, 2017, with an annual Consumer Price Index (“CPI”) adjustment. The annual CPI adjustment is capped at 2.5%. The term of the lease may be extended for up to three five-year extensions or the property may be purchased outright by our exercise of a purchase option at the end of the initial five-year lease term. For the year 2015, we paid Shaner Office Holdings, L.P. approximately $0.5 million in office rental payments and utilities. We account for this lease as an operating lease, subsequently recording the rental payments as General and Administrative Expense on our Consolidated Statements of Operations. During the third quarter of 2013, we purchased a parcel of land adjacent to our headquarters office location from Shaner Office Holdings, L.P. for approximately $0.6 million.
RW Gathering, LLC
We own a 40% interest in RW Gathering which owns gas-gathering assets to facilitate the development of our joint operations with WPX and Sumitomo (see Note 5, Equity Method Investments, to our Consolidated Financial Statements). We incurred approximately $0.7 million, $0.7 million and $0.8 million for the years ended December 31, 2015, 2014 and 2013, respectively, in compression expenses that were charged to us from Williams Appalachia, LLC. These costs are in relation to compression costs incurred by RW Gathering and are recorded as Production and Lease Operating Expense on our Consolidated Statement of Operations. As of December 31, 2015, 2014 and 2013, there were no receivables or payables in relation to RW Gathering due to or from us.
Water Solutions
We incurred approximately $6.1 million, $20.1 million and $10.7 million in gross water transfer and equipment rental expenses that were charged to us from Water Solutions during 2015 (through the date of sale in July 2015), 2014 and 2013, respectively. Of the amounts incurred, we eliminated approximately $4.7 million, $16.2 million and $8.8 million in consolidation for the years 2015, 2014 and 2013, respectively. As of December 31, 2015 we had no payables due to sale of our interest in Water Solutions during third quarter 2015 as compared to approximately $1.3 million as of December 31, 2014, owed to Water Solutions for work performed during the periods. As of December 31, 2015 and 2014, we classified the operations of Water Solutions as Discontinued Operations. See note 4, Discontinued Operations/Assets Held for Sale, of our Consolidated Financial Statements for additional information.
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Senior Credit Facility
We maintain a revolving credit facility evidenced by the Credit Agreement, dated March 27, 2013, with Royal Bank of Canada, as Administrative Agent and lenders from time to time parties thereto (as amended from time to time, the “Senior Credit Facility”). Borrowings under the Senior Credit Facility are limited by a borrowing base that is determined in regard to our oil and gas properties. The borrowing base under the Senior Credit Facility as of December 31, 2015 was $350.0 million; however, the revolving credit facility may be increased to up to $500.0 million upon re-determinations of the borrowing base, consent of the lenders and other conditions prescribed in the agreement. Within the Senior Credit Facility, a letter of credit subfacility exists of up to $60.0 million of letters of credit. As of December 31, 2015, we had $41.0 million in undrawn letters of credit outstanding. In conjunction with our offer to exchange senior unsecured notes, on February 3, 2016, our Senior Credit Facility was amended to lower our borrowing base to $200.0 million. Effective April 1, 2016, our borrowing base will be further reduced to $190.0 million. For additional information on our most recent Senior Credit Facility amendments, see Note 26, Subsequent Events, to our Consolidated Financial Statements. The Senior Credit Facility provides that the borrowing base will be re-determined semi-annually by the lenders, in good faith, based on, among other things, reports regarding our oil and gas reserves attributable to our oil and gas properties, together with a projection of related production and future net income, taxes, operating expenses and capital expenditures. We may, or the Administrative Agent at the direction of a majority of the lenders may, each elect once per calendar year to cause the borrowing base to be re-determined between the scheduled re-determinations. In addition, we may request interim borrowing base re-determinations upon our proposed acquisition of proved developed producing oil and gas reserves with a purchase price for such reserves greater than 10% of the then borrowing base. Our next scheduled redetermination will occur on or about July 1, 2016. As of December 31, 2015, loans made under the Senior Credit Facility were set to mature on September 12, 2019. In certain circumstances, we may be required to prepay the loans. Management does not believe that a prepayment will be required within the next twelve months. As of December 31, 2015, we had $111.5 million outstanding and as of December 31, 2014 we had no borrowings outstanding on the Senior Credit Facility.
Subsequent to our February 3, 2016 amendment, and at our election, borrowings under the Senior Credit Facility bear interest at a rate per annum equal to the “Adjusted LIBO Rate” or the “Alternate Base Rate,” plus, in each case, an applicable per annum margin. The “Adjusted LIBO Rate” is equal to the product of (i) the rate per annum as determined by the administrative agent by reference to the rate set by ICE Benchmark Administration for deposits in dollars for a period equal to the applicable interest period (the “LIBO Rate”), multiplied by (ii) the statutory reserve rate. The Alternate Base Rate is equal to the greatest of (a) Royal Bank of Canada’s prime rate in effect at its principal office in Toronto, Canada, (b) the weighted average of the rates on overnight Federal funds transactions published on the next succeeding business day by the Federal Reserve Bank of New York (the “Federal Funds Effective Rate”), plus 0.5%, and (c) the Adjusted LIBO Rate for a one month interest period plus 1.0%. The applicable per annum margin, in the case of loans bearing interest at the Adjusted LIBO Rate, ranges from 225 to 325 basis points, and in the case of loans bearing interest at the Alternate Base Rate, ranges from 125 to 225 basis points, in each case, determined based upon our borrowing base utilization at such date of determination. Upon the occurrence and continuance of an event of default, all outstanding loans shall bear interest at a per annum rate equal to 200 basis points plus the then effective rate of interest. Interest is payable on the last day of each applicable interest period.
Under the Senior Credit Facility, we may enter into commodity swap agreements with counterparties approved by the lenders, provided that the notional volumes for such agreements, when aggregated with other commodity swap agreements then in effect (other than basis differential swaps on volumes already hedged pursuant to other swap agreements), do not exceed, as of the date the swap agreement is executed, 85% of the reasonably anticipated projected production from our proved developed producing reserves for the 36 months following the date such agreement is entered into, and 75% thereafter, for each of crude oil and natural gas, calculated separately. As of December 31, 2015, we were in compliance with these swap agreement restrictions. We may also enter into interest rate swap agreements with counterparties approved by the lenders that convert interest rates from floating to fixed provided that the notional amounts of those agreements, when aggregated with all other similar interest rate swap agreements then in effect, do not exceed the greater of $20 million or 75% of the then outstanding principal amount of our debt for borrowed money which bears interest at a floating rate.
The Senior Credit Facility 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 (for further information, see Note 2, Summary of Significant Accounting Policies, Note 6, Concentrations of Credit Risk, and Note 10, Fair Value of Financial Instruments and Derivative Instruments, to our Consolidated Financial Statements). Borrowings under the Senior Credit Facility have been used to finance our working capital needs and for general corporate purposes in the ordinary course of business, including the exploration, acquisition and development of oil and gas properties. Obligations under the Senior Credit Facility are secured by mortgages on the oil and gas properties of our subsidiaries located in the states of Pennsylvania, Ohio, Illinois and Indiana. As a result of the March 14, 2016 amendment to our Senior Credit Facility, we are required to maintain liens on 95% of the total value of all our oil and gas properties, with certain properties within our Moraine East operated area and our Warrior North operated area requiring liens on 100% of such properties.
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The Senior Credit Facility requires we meet, on a quarterly basis, financial requirements of a minimum consolidated current ratio and a maximum net senior secured debt to EBITDAX ratio. EBITDAX is a non-GAAP financial measure used by our management team and by other users of our financial statements, such as our commercial bank lenders, which adds to or subtracts from net income the following expenses or income for a given period to the extent deducted from or added to net income in such period: interest, income taxes, depreciation, depletion, amortization, unrealized gains and losses from derivatives, exploration expense and other similar non-cash activity. The Senior Credit Facility requires that as of the last day of any fiscal quarter, our ratio of consolidated current assets, which includes the unused portion of our borrowing base, as of such day to consolidated current liabilities as of such day, known as our current ratio, must not be less than 1.0 to 1.0. Our current ratio as of December 31, 2015 was approximately 2.3 to 1.0. We do not anticipate being in compliance with our current ratio requirement at March 31, 2016; however, we have received a waiver of this covenant for the period ending March 31, 2016 from the lenders under our revolving credit facility. Subsequent to March 31, 2016, we expect proceeds from our joint venture operations will bring us back in compliance with the current ratio requirement of 1.0 to 1.0. Additionally, as of the last day of any fiscal quarter, our ratio of net senior secured debt to EBITDAX for the trailing twelve months must not exceed 3.0 to 1.0. Our ratio of total debt to EBITDAX as of December 31, 2015 was approximately 1.7 to 1.0. As a result of the March 14, 2016 amendment, in the event that at least 80% of our Senior Notes exchange such notes for new second lien notes, our required net senior secured debt to EBITDAX ratio will decrease to 2.75 to 1.0. See Note 26, Subsequent Events, to our Consolidated Financial Statements for additional information on our Senior Credit Facility amendments and the proposed exchange offer.
2020 Senior Notes and 2022 Senior Notes
On December 12, 2012, we issued a $250.0 million aggregate principal amount of 8.875% senior notes in a private offering at an issue price of 99.3% due to mature on December 1, 2020 (the “2020 Senior Notes”). The net proceeds of the 2020 Senior Notes, after discounts and expenses, were approximately $242.2 million. Debt issuance costs of $6.4 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the 2020 Senior Notes as Interest Expense on our Consolidated Statements of Operations using the effective interest method. Interest is payable semi-annually at a rate of 8.875% per annum on June 1 and December 1 of each year, with the first interest payment made on June 1, 2013.
On April 26, 2013, we issued an additional $100.0 million in aggregate principal amount of the 2020 Senior Notes in a private offering at an issue price to the initial purchasers of 105% of par plus accrued interest from December 12, 2012. Net proceeds after discounts and offering expenses were approximately $102.8 million plus accrued interest of approximately $3.3 million. Debt issuance costs of $2.3 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the 2020 Senior Notes as Interest Expense on our Consolidated Statements of Operations using the effective interest method.
We may redeem, at specified redemption prices, some or all of the 2020 Senior Notes at any time on or after December 1, 2016. If we sell certain of our assets or experience specific kinds of changes in control, we may be required to offer to purchase the 2020 Senior Notes from the holders.
On July 17, 2014, we issued a $325.0 million aggregate principal amount of 6.25% senior notes (the “2022 Senior Notes”) in a private offering at an issue price of 100.0% due to mature on August 1, 2022. The net proceeds of the 2022 Senior Notes, after discounts and expenses, were approximately $318.8 million. Debt issuance costs of $6.3 million were recorded as Deferred Financing Costs and Other Assets – Net on our Consolidated Balance Sheet and are being amortized over the term of the notes as Interest Expense on our Consolidated Statements of Operations. Interest is payable semi-annually at a rate of 6.25% per annum on February 1 and August 1 of each year, with the first interest payment made on February 1, 2015.
We may redeem, at specified redemption prices, some or all of the 2022 Senior Notes at any time on or after August 1, 2017. We may also redeem up to 35% of the notes using the proceeds of certain equity offerings completed before August 1, 2017. If we sell certain of our assets or experience specific kinds of changes of control, we may be required to offer to purchase the 2022 Senior Notes from the holders.
The Senior Notes due 2020 and the Senior Notes due 2022 (collectively, the “Senior Notes”) are fully and unconditionally guaranteed on a senior unsecured basis by certain of our existing and future domestic subsidiaries. In addition, there are no significant restrictions on our ability, or the ability of any subsidiary guarantor, to receive funds from our subsidiaries through dividends, loans, advances or otherwise. For additional information on our guarantor and non-guarantor subsidiaries, see Note 25, Condensed Consolidating Financial Information, to our Consolidated Financial Statements.
As of December 31, 2015 and 2014, we had recorded on our Consolidated Balance Sheets approximately $677.3 million and $677.7 million of Senior Notes, which is inclusive of a net premium of $2.3 million and $2.7 million, respectively. The amortization
94
of our net premium in 2015 and 2014, which follows the effective interest method, was approximately $0.4 million in each year and was recorded as a credit to Interest Expense on our Consolidated Statement of Operations.
Our Senior Notes are governed by indentures with substantially similar terms and provisions (the “Indentures”). The Indentures contain affirmative and negative covenants that are customary for instruments of this nature, including restrictions or limitations on the ability to incur additional debt, pay dividends, purchase or redeem stock or subordinated indebtedness, make investments, create liens, sell assets, merge with or into other companies or sell substantially all of its assets, unless those actions satisfy the terms and conditions of the Indentures or are otherwise excepted or permitted. Certain of the limitations in the Indentures, including the ability to incur debt, pay dividends or make other restricted payments, become more restrictive in the event our ratio of consolidated cash flow to fixed charges for the most recent trailing four quarters (the “Fixed Charge Coverage Ratio”) is less than 2.25:1. As of December 31, 2015, the Company’s Fixed Charge Coverage Ratio was 1.3. We expect our Fixed Charge Coverage Ratio to be less than 2.25:1 for the remainder of 2016. As a result, we anticipate that our ability to incur debt, pay dividends or make certain other restricted payments will be subject to the more restrictive provisions of the Indentures for those periods. As of December 31, 2015, we were limited to incurring an additional $213.6 million in additional debt due to our Fixed Charge Coverage Ratio. The Indentures also contain customary events of default, including cross-default features with any other indebtedness. In certain circumstances, the trustee or the holders of the Senior Notes may declare all outstanding Senior Notes to be due and payable immediately.
On February 3, 2016, we announced the commencement of an exchange offer related to our Senior Notes. For additional information on the exchange offer, see Note 26, Subsequent Events, to our Consolidated Financial Statements.
In addition to the Senior Credit Facility and the Senior Notes, we may, from time to time in the normal course of business finance assets such as vehicles, office equipment and leasehold improvements through debt financing at favorable terms. Long-term debt and other obligations consisted of the following at December 31, 2015 and December 31, 2014:
($ in Thousands) |
| December 31, 2015 |
|
| December 31, 2014 |
| ||
8.875% Senior Notes Due 2020 |
| $ | 350,000 |
|
| $ | 350,000 |
|
6.25% Senior Notes Due 2022 |
|
| 325,000 |
|
|
| 325,000 |
|
Premium on Senior Notes, Net |
|
| 2,344 |
|
|
| 2,725 |
|
Senior Line of Credit(a) |
|
| 111,500 |
|
|
| — |
|
Capital Leases and Other Obligations(a) |
|
| 618 |
|
|
| 1,427 |
|
Total Debt |
|
| 789,462 |
|
|
| 679,152 |
|
Less Current Portion of Long-Term Debt |
|
| (590 | ) |
|
| (1,176 | ) |
Total Long-Term Debt |
| $ | 788,872 |
|
| $ | 677,976 |
|
(a) | The weighted average interest rate on borrowings under our Senior Credit Facility for the years ended December 31, 2015, 2014 and 2013 was approximately 1.7%, 2.2 % and 1.9%, respectively. The weighted average interest rate on our Capital Leases and Other Obligations as of December 31, 2015, 2014 and 2013 was approximately 5.5%, 4.0% and 5.3%, respectively. |
The following is the principal maturity schedule for total debt outstanding as of December 31, 2015:
($ in thousands) |
| Year Ended December 31, |
| |
2016 |
| $ | 590 |
|
2017 |
|
| 28 |
|
2018 |
|
| — |
|
2019 |
|
| 111,500 |
|
2020 |
|
| 350,000 |
|
Thereafter |
|
| 325,000 |
|
Total1 |
| $ | 787,118 |
|
1 | Does not include $2.3 million net premium on Senior Notes. |
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Natural Gas, Oil and NGL Derivatives
We enter derivative financial instruments with the primary objective of managing our exposure to commodity price fluctuations and providing more predictable cash flows. Our results of operations and operating cash flows are impacted by changes in market prices for oil, natural gas and NGLs. To mitigate a portion of the exposure to adverse market changes, we enter into oil, natural gas and NGL commodity derivative instruments to establish price floor protection. As such, when commodity prices decline to levels that are less than our average price floor, we receive payments that supplement our cash flows. Conversely, when commodity prices increase to levels that are above our average price ceiling, we make payments to our counterparties. We do not enter into these arrangements for speculative trading purposes. As of December 31, 2015, 2014 and 2013, our commodity derivative instruments consisted of fixed rate swap contracts, puts, collars, swaptions, deferred put spreads, cap swaps, call protected swaps, basis swaps and three-way collars. We did not designate these instruments as cash flow hedges for accounting purposes. Accordingly, associated unrealized gains and losses are recorded directly as Gain (Loss) on Derivatives, Net. For additional information, see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements.
Swap contracts provide a fixed price for a notional amount of sales volumes. Collars contain a fixed floor price (“put”) and ceiling price (“call”). The put options are purchased from the counterparty by our payment of a cash premium. If the put strike price is greater than the market price for a settlement period, then the counterparty pays us an amount equal to the product of the notional quantity multiplied by the excess of the strike price over the market price. The call options are sold to the counterparty, for which we receive a cash premium. If the market price is greater than the call strike price for a settlement period, then we pay the counterparty an amount equal to the product of the notional quantity multiplied by the excess of the market price over the strike price. A three-way collar is a combination of options, a sold call, a purchased put and a sold put. The purchased put establishes a minimum price unless the market price falls below the sold put, at which point the minimum price would be the settlement price plus the difference between the purchased put and the sold put strike price. The sold call establishes a maximum price we will receive for the volumes under contract. Deferred put spread contracts are similar to three-way collars except that there is no maximum price ceiling established.
Swaption agreements provide options to counterparties to extend swaps into subsequent years. Similar to a deferred put spread and a three-way collar, a cap swap provides a sold put in combination with a swap. Should prices fall below the sold put, we would receive the settlement price plus the differential between the sold put and the swap. Basis swaps are arrangements that guarantee a price differential from a specified delivery point. Currently, our basis swaps provide basis protection between Henry Hub and Dominion Appalachia pricing.
We enter into the majority of our derivative arrangements with five counterparties and have a netting agreement in place with these counterparties, however the fair value of our derivative contracts are reported on a gross basis. We do not obtain collateral to support the agreements, but we believe our credit risk is currently minimal on these transactions. For additional information on the credit risk regarding our counterparties, see Note 6, Concentrations of Credit Risk, to our Consolidated Financial Statements.
None of our commodity derivatives are designated for hedge accounting but are, to a degree, an economic offset to our commodity price exposure. We utilize the mark-to-market accounting method to account for these contracts. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense). We received net cash settlements of $54.9 million, $6.0 million and $7.1 million in relation to our commodity derivatives for the years ended December 31, 2015, 2014 and 2013 respectively.
As of December 31, 2015, we had over 45.0% of our 2015 oil production volumes hedged through 2016, over 100.0% of our 2015 natural gas production volumes hedged through 2016 and over 40.0% of our 2015 NGL production volumes hedged through 2016. Including the effects of derivatives added since December 31, 2015, we have over 70.0% of our 2015 oil production hedged through 2016, over 100.0% of our 2015 natural gas production hedged through 2016 and over 45.0% of our 2015 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 oil and gas production.
Interest Rate Derivatives
We are exposed to interest rate risk on our long-term fixed and variable interest rate borrowings. Fixed rate debt, where the interest rate is fixed over the life of the instrument, exposes us to changes in the market interest rates which are lower than our current fixed rate. Variable rate debt, where the interest rate fluctuates, exposes us to changes in market interest rates, which may increase over time. As of December 31, 2015, we had approximately $111.5 million in borrowings outstanding under our Senior Credit Facility, which is subject to variable rates of interest, and had $675.0 million of Senior Notes outstanding subject to a fixed interest rate. See Note 9, Long-Term Debt, to our Consolidated Financial Statements for additional information on our Senior Credit Facility and Senior Notes.
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We did enter into fixed-to-variable interest rate swaps during 2015 and 2014, however there were no arrangements in place as of December 31, 2015 and 2014. We utilize the mark-to-market accounting method to account for our interest rate swaps. We recognize all gains and losses related to these contracts in the Consolidated Statements of Operations as Gain (Loss) on Derivatives, Net under Other Income (Expense). During the years ended December 31, 2015 and 2014, we received cash payments of approximately $0.9 million and $1.3 million, respectively, related to our interest rate swaps.
The following table summarizes the location and amounts of gains and losses on our derivative instruments from continuing operations, none of which are designated as hedges for accounting purposes, in our accompanying Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013:
|
| For the Year Ended December 31, |
| |||||||||
($ in Thousands) |
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Oil |
| $ | 7,132 |
|
| $ | 8,613 |
|
| $ | (2,798 | ) |
Natural Gas |
|
| 37,647 |
|
|
| 18,406 |
|
|
| 1,807 |
|
NGLs |
|
| 14,463 |
|
|
| 10,340 |
|
|
| (1,711 | ) |
Interest Rate |
|
| 934 |
|
|
| 1,517 |
|
|
| (206 | ) |
Gain (Loss) on Derivatives, Net |
| $ | 60,176 |
|
| $ | 38,876 |
|
| $ | (2,908 | ) |
We account for our derivatives in accordance with ASC 815, which requires that every derivative instrument be recorded on the balance sheet as either an asset or liability measured at its fair value. The fair value associated with our derivative instruments was a net asset of $35.8 million as of December 31, 2015, and a net asset of $31.4 million at December 31, 2014. Our open asset/(liability) financial commodity derivative instrument positions at December 31, 2015 consisted of the following:
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| Volume |
| Put Option |
|
| Floor |
|
| Ceiling |
|
| Swap |
|
| Fair Market Value ($ in Thousands) |
| ||||||
Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 - Deferred Put Spreads |
| 120,000 Bbls |
| $ | 50.00 |
|
| $ | 65.00 |
|
| $ | — |
|
| $ | — |
|
| $ | 852 |
|
2016 - Collars |
| 379,500 Bbls |
|
| — |
|
|
| 39.17 |
|
|
| 52.67 |
|
|
| — |
|
|
| 1,078 |
|
2016 - Three-Way Collars |
| 45,000 Bbls |
|
| 50.00 |
|
|
| 65.00 |
|
|
| 70.00 |
|
|
| — |
|
|
| 577 |
|
|
| 544,500 Bbls |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 2,507 |
|
Natural Gas |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 - Swaps |
| 12,900,000 Mcf |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 3.19 |
|
| $ | 8,717 |
|
2016 - Swaptions |
| 1,200,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.15 |
|
|
| 596 |
|
2016 - Cap Swaps |
| 3,600,000 Mcf |
|
| 3.45 |
|
|
| — |
|
|
| — |
|
|
| 4.11 |
|
|
| 1,977 |
|
2016 - Three-Way Collars |
| 18,570,000 Mcf |
|
| 2.34 |
|
|
| 3.04 |
|
|
| 3.86 |
|
|
| — |
|
|
| 5,941 |
|
2016 - Put Spread |
| 4,500,000 Mcf |
|
| 2.93 |
|
|
| 3.59 |
|
|
| — |
|
|
| — |
|
|
| 1,737 |
|
2016 - Basis Swaps - Dominion South |
| 16,630,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.94 | ) |
|
| (1,634 | ) |
2016 - Collars |
| 3,900,000 Mcf |
|
| — |
|
|
| 2.82 |
|
|
| 3.32 |
|
|
| — |
|
|
| 1,728 |
|
2017 - Swaps |
| 960,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.60 |
|
|
| 797 |
|
2017 - Swaptions |
| 0 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| (297 | ) |
2017 - Cap Swaps |
| 2,100,000 Mcf |
|
| 3.34 |
|
|
| — |
|
|
| — |
|
|
| 4.07 |
|
|
| 1,225 |
|
2017 - Three-Way Collars |
| 16,300,000 Mcf |
|
| 2.33 |
|
|
| 3.02 |
|
|
| 3.89 |
|
|
| — |
|
|
| 4,319 |
|
2017 - Basis Swaps - Dominion South |
| 4,550,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.83 | ) |
|
| (665 | ) |
2017 - Basis Swaps - Texas Gas |
| 14,600,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.13 | ) |
|
| (19 | ) |
2017 - Calls |
| 3,000,000 Mcf |
|
| — |
|
|
| — |
|
|
| 3.64 |
|
|
| — |
|
|
| (380 | ) |
2018 - Swaps |
| 960,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3.60 |
|
|
| 797 |
|
2018 - Cap Swaps |
| 1,800,000 Mcf |
|
| 3.30 |
|
|
| — |
|
|
| — |
|
|
| 4.05 |
|
|
| 1,069 |
|
2018 - Three-Way Collars |
| 7,875,000 Mcf |
|
| 2.29 |
|
|
| 2.88 |
|
|
| 3.56 |
|
|
| — |
|
|
| 916 |
|
2018 - Calls |
| 5,810,000 Mcf |
|
| — |
|
|
| — |
|
|
| 3.97 |
|
|
| — |
|
|
| (609 | ) |
2018 - Basis Swaps - Dominion South |
| 6,400,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.83 | ) |
|
| (960 | ) |
2018 - Basis Swaps - Texas Gas |
| 14,600,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.13 | ) |
|
| (19 | ) |
2019 - Basis Swaps - Dominion South |
| 7,300,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.83 | ) |
|
| (1,103 | ) |
2020 - Basis Swaps - Dominion South |
| 7,320,000 Mcf |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (0.83 | ) |
|
| (1,106 | ) |
|
| 154,875,000 Mcf |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 23,027 |
|
NGLs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 C3 + NGL Swaps |
| 1,131,000 Bbls |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 32.76 |
|
| $ | 9,888 |
|
2016 Ethane Swaps |
| 240,000 Bbls |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 8.82 |
|
|
| 362 |
|
2017 C3 + NGL Swaps |
| 180,000 Bbls |
|
| — |
|
|
| — |
|
|
| — |
|
|
| 21.42 |
|
|
| 344 |
|
|
| 1,551,000 Bbls |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 10,594 |
|
Refined Product (Heating Oil) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016 - Swaps |
| 12,000 Bbls |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 84.00 |
|
| $ | (376 | ) |
|
| 12,000 Bbls |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (376 | ) |
The combined fair value of our derivatives included in our Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014 is summarized below.
98
| December 31, |
|
| December 31, |
| |||
($ in Thousands) |
| 2015 |
|
| 2014 |
| ||
Short-Term Derivative Assets: |
|
|
|
|
|
|
|
|
Crude Oil—Collars |
| $ | 1,078 |
|
| $ | — |
|
Crude Oil—Call Protected Swap |
|
| — |
|
|
| 1,227 |
|
Crude Oil—Deferred Put Spread |
|
| 852 |
|
|
| 1,413 |
|
Crude Oil—Three-Way Collars |
|
| 577 |
|
|
| 4,596 |
|
NGL—Swaps |
|
| 10,250 |
|
|
| 6,181 |
|
Natural Gas—Swaps |
|
| 9,010 |
|
|
| 4,522 |
|
Natural Gas—Cap Swaps |
|
| 1,977 |
|
|
| 3,430 |
|
Natural Gas—Basis Swaps |
|
| 70 |
|
|
| 2,815 |
|
Natural Gas—Three-Way Collars |
|
| 6,183 |
|
|
| 5,081 |
|
Natural Gas—Collars |
|
| 1,728 |
|
|
| — |
|
Natural Gas—Swaption |
|
| 798 |
|
|
| — |
|
Natural Gas—Put Spread |
|
| 1,737 |
|
|
| — |
|
Total Short-Term Derivative Assets |
| $ | 34,260 |
|
| $ | 29,265 |
|
Long-Term Derivative Assets: |
|
|
|
|
|
|
|
|
NGL—Swaps |
| $ | 344 |
|
| $ | — |
|
Natural Gas—Cap Swaps |
|
| 2,294 |
|
|
| 1,617 |
|
Natural Gas—Swaps |
|
| 1,593 |
|
|
| 1,554 |
|
Natural Gas—Basis Swaps |
|
| 195 |
|
|
| — |
|
Natural Gas—Three-Way Collars |
|
| 5,108 |
|
|
| 1,733 |
|
Total Long-Term Derivative Assets |
| $ | 9,534 |
|
| $ | 4,904 |
|
Total Derivative Assets |
| $ | 43,794 |
|
| $ | 34,169 |
|
Short-Term Derivative Liabilities: |
|
|
|
|
|
|
|
|
Refined Product —Swaps |
|
| (376 | ) |
|
| — |
|
Natural Gas—Three-Way Collars |
|
| (31 | ) |
|
| — |
|
Natural Gas—Basis Swaps |
|
| (1,585 | ) |
|
| (193 | ) |
Natural Gas—Call |
|
| — |
|
|
| (74 | ) |
Natural Gas—Swaption |
|
| (202 | ) |
|
| (154 | ) |
Natural Gas—Swaps |
|
| (292 | ) |
|
| - |
|
Total Short - Term Derivative Liabilities |
| $ | (2,486 | ) |
| $ | (421 | ) |
Long-Term Derivative Liabilities: |
|
|
|
|
|
|
|
|
Natural Gas—Swaption |
|
| (297 | ) |
|
| — |
|
Natural Gas—Basis Swaps |
|
| (4,186 | ) |
|
| (1,281 | ) |
Natural Gas—Call |
|
| (989 | ) |
|
| (1,096 | ) |
Natural Gas—Three-Way Collars |
|
| (84 | ) |
|
| — |
|
Total Long-Term Derivative Liabilities |
| $ | (5,556 | ) |
| $ | (2,377 | ) |
Total Derivative Liabilities |
| $ | (8,042 | ) |
| $ | (2,798 | ) |
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and attempt to utilize the best available information. We utilize a fair value hierarchy that gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and lowest priority to unobservable inputs (Level 3 measurement). The three levels of fair value hierarchy are as follows:
Level 1—Observable inputs, such as quoted prices in active markets for identical assets or liabilities as of the reporting date.
Level 2—Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Our derivatives, which consist primarily of commodity swaps and collars and other like derivative contracts, are valued using commodity market data which
99
is derived by combining raw inputs and quantitative models and processes to generate forward curves. Where observable inputs are available, directly or indirectly, for substantially the full term of the asset or liability, the instrument is categorized in Level 2.
Level 3—Unobservable inputs that are supported by little or no market activity. Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Our Level 2 fair value measurements are comprised of our derivative contracts, excluding our basis swap derivatives, and are based upon inputs that are either readily available in the public market, such as oil and natural gas futures prices, volatility factors, interest rates and discount rates, or can be confirmed from other active markets. The fair values recorded as of December 31, 2015 and 2014, were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party.
Our Level 3 fair value measurements are comprised of our natural gas basis swap contracts. The fair values recorded as of December 31, 2015 were based upon quotes obtained from the counterparties to these contracts and verified by an independent third party. The significant unobservable input used in the fair value measurement of our natural gas basis swaps was the estimate of future natural gas basis differentials. Significant variations in price differentials could result in a significantly different fair value measurement. The significant unobservable inputs and the range and weighted average of these inputs used in the fair value measurements of our natural gas basis swaps as of December 31, 2015 and 2014 are included in the table below.
|
| As of December 31, 2015 |
| |||||||
|
| Range (price per Mcf) |
| Weighted Average (price per Mcf) |
|
| Fair Value (in thousands) |
| ||
Natural Gas Basis Differential Forward Curve - Dominion South |
| ($0.27) - ($1.08) |
| $ | (0.74 | ) |
| $ | (5,468 | ) |
Natural Gas Basis Differential Forward Curve - Texas Gas |
| ($0.05) - ($0.17) |
| $ | (0.12 | ) |
| $ | (38 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
| As of December 31, 2014 |
| |||||||
|
| Range (price per Mcf) |
| Weighted Average (price per Mcf) |
|
| Fair Value (in thousands) |
| ||
Natural Gas Basis Differential Forward Curve |
| ($0.27) - ($1.39) |
| $ | (0.84 | ) |
| $ | 1,341 |
|
The fair value of our derivative instruments may be different from the settlement value based on company-specific inputs, such as credit ratings, futures markets and forward curves, and readily available buyers and sellers for such assets and liabilities. During the years ended December 31, 2015 and 2014, there were no transfers into or out of Level 1 or Level 2 measurements. The following table presents the fair value hierarchy table for assets and liabilities measured at fair value:
|
|
|
|
|
| Fair Value Measurements at December 31, 2015 Using: |
| |||||||||
($ in Thousands) |
| Total Carrying Value as of December 31, 2015 |
|
| Quoted Prices in Active Markets for Identical Assets (Level 1) |
|
| Significant Other Observable Inputs (Level 2) |
|
| Significant Unobservable Inputs (Level 3) |
| ||||
Commodity Derivatives |
| $ | 35,752 |
|
| $ | — |
|
| $ | 41,258 |
|
| $ | (5,506 | ) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Fair Value Measurements at December 31, 2014 Using: |
| |||||||||
($ in Thousands) |
| Total Carrying Value as of December 31, 2014 |
|
| Quoted Prices in Active Markets for Identical Assets (Level 1) |
|
| Significant Other Observable Inputs (Level 2) |
|
| Significant Unobservable Inputs (Level 3) |
| ||||
Commodity Derivatives |
| $ | 31,371 |
|
| $ | — |
|
| $ | 30,030 |
|
| $ | 1,341 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100
Net derivative asset values are determined primarily by quoted futures and options prices and utilization of the counterparties’ credit default risk and net derivative liabilities are determined primarily by quoted futures and options prices and utilization of our credit default risk. The credit default risk of our counterparties and us are based on metrics such as interest coverage, operating cash flow and leverage ratios that calculate the likelihood that a firm will be unable to repay its lenders or fulfill payment obligations.
The value of our oil derivatives are comprised of three-way collar, call protected swap and deferred put spread contracts for notional barrels of oil at interval New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) oil prices. The fair value of our oil derivatives as of December 31, 2015 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for WTI oil and (iii) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our gas derivatives are comprised of swap, swaption, three way collar, basis swap, cap swap, call and deferred put spreads contracts for notional volumes of gas contracted at NYMEX Henry Hub (“HH”). The fair values attributable to our gas derivative contracts as of December 31, 2015 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for HH gas, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. Our NGL derivatives are comprised of swaps for notional volumes of NGLs contracted at NYMEX Mont Belvieu. The fair values attributable to our NGL derivative contracts as of December 31, 2015 are based on (i) the contracted notional volumes, (ii) independent active NYMEX futures price quotes for Mont Belvieu, (iii) independent market-quoted forward index prices and (iv) the implied rate of volatility inherent in the contracts. The implied rates of volatility inherent in our contracts were determined based on market-quoted volatility factors. We classify our derivatives as Level 2 if the inputs used in the valuation models are directly observable for substantially the full term of the instrument; however, if the significant inputs were not observable for substantially the full term of the instrument, we would classify those derivatives as Level 3. We categorize our measurements as Level 2 because the valuation of our derivative instruments are based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instruments.
The table below sets forth a reconciliation of our commodity derivative contracts at fair value on a recurring basis using significant unobservable inputs (Level 3) during the years ended December 31, 2015 and 2014 (in thousands):
|
| For the Year Ended December 31, |
| |||||
($ in Thousands) |
| 2015 |
|
| 2014 |
| ||
Beginning Balance of Level 3 |
| $ | 1,341 |
|
| $ | 4,323 |
|
Changes in Fair Value |
|
| (2,548 | ) |
|
| (1,670 | ) |
Purchases |
|
| — |
|
|
| — |
|
Settlements Received |
|
| (4,299 | ) |
|
| (1,312 | ) |
Ending Balance of Level 3 |
| $ | (5,506 | ) |
| $ | 1,341 |
|
Changes in fair value on our Level 3 commodity derivative contracts outstanding for the years ended December 31, 2015 and 2014, resulted in a gain of approximately $2.5 million and $1.7 million, respectively. These amounts have been included in Gain (Loss) on Derivatives, Net in our Consolidated Statements of Operations.
Asset Retirement Obligations
We report the fair value of asset retirement obligations on a nonrecurring basis in our Consolidated Balance Sheets. We estimate the fair value of asset retirement obligations based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. These inputs are unobservable, and thus result in a Level 3 classification. See Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements for further information on asset retirement obligations, which includes a reconciliation of the beginning and ending balances.
Financial Instruments Not Recorded at Fair Value
The following table sets forth the fair values of financial instruments that are not recorded at fair value in our Consolidated Financial Statements:
101
| December 31, 2015 |
|
| December 31, 2014 |
| |||||||||||
($ in Thousands) |
| Carrying Amount |
|
| Fair Value |
|
| Carrying Amount |
|
| Fair Value |
| ||||
8.875% Senior Notes due 2020 |
| $ | 350,000 |
|
| $ | 77,000 |
|
| $ | 350,000 |
|
| $ | 311,955 |
|
6.25% Senior Notes due 2022 |
|
| 325,000 |
|
|
| 72,313 |
|
|
| 325,000 |
|
|
| 241,313 |
|
Secured Lines of Credit |
|
| 111,500 |
|
|
| 111,500 |
|
|
| — |
|
|
| — |
|
Capital Leases and Other Obligations |
|
| 618 |
|
|
| 606 |
|
|
| 1,427 |
|
|
| 1,393 |
|
Total |
| $ | 787,118 |
|
| $ | 261,419 |
|
| $ | 676,427 |
|
| $ | 554,661 |
|
The fair value of the secured lines of credit approximates carrying value based on borrowing rates available to us for bank loans with similar terms and maturities and would be classified as Level 2 in the fair value hierarchy.
The fair value of the Senior Notes uses pricing that is readily available in the public market. Accordingly, the fair value of the Senior Notes would be classified as Level 2 in the fair value hierarchy. The fair value of our capital leases and other obligations are determined using a discounted cash flow approach based on the interest rate and payment terms of the obligations and assumed discount rate. The fair values of the obligations could be significantly influenced by the discount rate assumptions, which is unobservable. Accordingly, the fair value of the capital leases and other obligations would be classified as Level 3 in the fair value hierarchy.
The carrying values of all classes of cash and cash equivalents, accounts receivables and accounts payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.
Other Fair Value Measurements
We recorded an other than temporary impairment of $345.8 million related to proved properties, unproved properties and other non-revenue producing equipment. We utilize quoted futures prices and other observable market data in determining the fair value. The inputs used in determining fair value as a part of the impairment calculation are considered to be Level 2 within the fair value hierarchy. For additional information on our impairment, see Note 16, Impairment Expense, to our Consolidated Financial Statements.
11. | INCOME TAXES |
We recognize deferred tax liabilities and assets for the expected future tax consequences of events that may be recognized in our financial statements or tax returns. Using this method, deferred tax liabilities and assets are determined based on the difference between the financial carrying amounts and tax basis of assets and liabilities using enacted tax rates. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.
Our income tax expense (benefit) from continuing operations consisted of the following:
|
| For the Years Ended December 31, |
| |||||||||
($ in Thousands) |
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
| $ | — |
|
| $ | — |
|
| $ | (1,936 | ) |
State |
|
| — |
|
|
| 6 |
|
|
| (4,105 | ) |
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
| (20,993 | ) |
|
| (23,691 | ) |
|
| 509 |
|
State |
|
| (3,234 | ) |
|
| (3,230 | ) |
|
| 1,378 |
|
Income Tax Benefit |
| $ | (24,227 | ) |
| $ | (26,915 | ) |
| $ | (4,154 | ) |
A reconciliation of income tax expense (benefit) using the statutory U.S. income tax rate compared with actual income tax expense is as follows:
102
| Year Ended December 31, 2015 |
|
| Year Ended December 31, 2014 |
|
| Year Ended December 31, 2013 |
| ||||
Loss from continuing operations before noncontrolling interests and income taxes |
| $ | (423,245 | ) |
| $ | (74,565 | ) |
| $ | (6,538 | ) |
Statutory U.S. income tax rate |
|
| 35.0 | % |
|
| 35.0 | % |
|
| 35.0 | % |
Tax expense recognized using statutory U.S. income tax rate |
| $ | (148,136 | ) |
| $ | (26,098 | ) |
| $ | (2,288 | ) |
State income taxes, net of federal income tax benefit |
|
| (20,446 | ) |
|
| (3,144 | ) |
|
| (805 | ) |
Change in estimated future state rates |
|
| (212 | ) |
|
| (1,015 | ) |
|
| (484 | ) |
Permanent differences |
|
| 1,609 |
|
|
| 970 |
|
|
| 83 |
|
Change in valuation allowances |
|
| 143,566 |
|
|
| 2,450 |
|
|
| (160 | ) |
Other |
|
| (608) |
|
|
| (78) |
|
|
| (500 | ) |
Total income tax benefit |
| $ | (24,227 | ) |
| $ | (26,915 | ) |
| $ | (4,154 | ) |
Effective income tax rate |
|
| 5.7 | % |
|
| 36.1 | % |
|
| 63.5 | % |
103
Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. Deferred tax assets (liabilities) are comprised of the following at December 31, 2015 and 2014:
|
| For the Years Ended December 31, |
| |||||
($ in Thousands) |
| 2015 |
|
| 2014 |
| ||
Tax effects of temporary differences for: |
|
|
|
|
|
|
|
|
Current: |
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
Asset retirement obligation |
| $ | 866 |
|
| $ | 772 |
|
Deferred compensation plans |
|
| 2,028 |
|
|
| 695 |
|
Compensation Accruals |
|
| 767 |
|
|
| 2,087 |
|
Valuation allowances |
|
| (3,478 | ) |
|
| (71 | ) |
Other |
|
| 93 |
|
|
| 68 |
|
Total gross current deferred tax assets |
|
| 276 |
|
|
| 3,551 |
|
Liabilities: |
|
|
|
|
|
|
|
|
Unrealized gain on derivatives |
|
| (12,570 | ) |
|
| (11,410 | ) |
Other |
|
| (238 | ) |
|
| (442 | ) |
Total gross current deferred tax liabilities |
|
| (12,808 | ) |
|
| (11,852 | ) |
Net total current deferred tax liability |
| $ | (12,532 | ) |
| $ | (8,301 | ) |
Long-Term: |
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
Timing differences - tax partnerships |
| $ | 4,166 |
|
| $ | — |
|
Tax basis of oil and gas properties in excess of book basis |
|
| 8,965 |
|
|
| — |
|
Asset retirement obligation |
|
| 16,965 |
|
|
| 15,091 |
|
Deferred compensation plans |
|
| 1,083 |
|
|
| 2,218 |
|
Net operating loss carryforward |
|
| 123,488 |
|
|
| 73,531 |
|
Organization costs |
|
| 456 |
|
|
| 525 |
|
Deferred revenue |
|
| 1,098 |
|
|
| 1,209 |
|
Percentage depletion carryforward |
|
| 2,673 |
|
|
| 2,155 |
|
AMT credits |
|
| 292 |
|
|
| 292 |
|
Valuation allowances |
|
| (144,681 | ) |
|
| (4,318 | ) |
Other |
|
| 280 |
|
|
| 269 |
|
Total gross long-term deferred tax assets |
|
| 14,785 |
|
|
| 88,817 |
|
Liabilities: |
|
|
|
|
|
|
|
|
Timing differences - tax partnerships |
|
| — |
|
|
| (7,135 | ) |
Book basis of oil and gas properties in excess of tax basis |
|
| — |
|
|
| (73,557 | ) |
Unrealized gain on derivatives |
|
| (1,574 | ) |
|
| (999 | ) |
Other |
|
| (679 | ) |
| $ | (980 | ) |
Total gross long-term deferred tax liabilities |
|
| (2,253 | ) |
|
| (80,516 | ) |
Net total long-term deferred tax asset |
| $ | 12,532 |
|
| $ | 8,301 |
|
(a) | As a result of certain realization requirements of FASB ASC 718, the table of deferred tax assets and liabilities does not include $1.3 million at December 31, 2015 and 2014, of excess tax benefits that arose directly from tax deductions related to stock-based compensation greater than compensation recognized for financial reporting. Total stockholders’ equity will be increased by $1.3 million if and when such excess tax benefits are ultimately realized. |
104
Management continuously evaluates the facts and circumstances representing positive and negative evidence in the determination of our ability to realize our inventory of deferred tax assets. The company’s deferred tax assets consist primarily of net operating losses and deductible temporary differences. For the year ended December 31, 2015, management determined, based on positive and negative evidence, including our three-year cumulative loss position that it was necessary to provide a valuation allowance of approximately $148.2 million for deferred tax assets for which the company may be unable to realize the tax benefit. For the year ended December 31, 2014, management determined, based on positive and negative evidence examined and anticipated future taxable income, that it was necessary to provide a valuation allowance of approximately $4.3 million for deferred tax assets for which the company may be unable to realize the tax benefit. Our management will continue, in future periods, to assess the likely realization of the deferred tax assets. The valuation allowance may change based on future changes in circumstances.
At December 31, 2015, we had available unused gross federal net operating loss carryforwards of $308.1 million and gross state net operating loss carryforwards of $264.7 million that may be applied against future taxable income that expire from 2020 through 2035. The following table shows expirations by year for federal and state net operating loss carryforwards (all figures presented are tax effected):
Year of Expiration |
| Net Operating Loss Carryforwards (in thousands) |
| |
2020 |
| $ | 134 |
|
2021 |
|
| 175 |
|
2022 |
|
| — |
|
2023 |
|
| 899 |
|
2024 |
|
| — |
|
2025 |
|
| 531 |
|
2026 |
|
| 405 |
|
2027 |
|
| 1,003 |
|
2028 |
|
| 3,333 |
|
2029 |
|
| 767 |
|
2030 |
|
| 751 |
|
2031 |
|
| 19,746 |
|
2032 |
|
| 253 |
|
2033 |
|
| 19,703 |
|
2034 |
|
| 18,670 |
|
2035 |
|
| 57,118 |
|
Total |
|
| 123,488 |
|
Due to a change of ownership, as defined under the provisions of the Tax Reform Act of 1986, which occurred during 2014, a portion of our domestic net operating loss and tax credit carryforwards may be limited in future periods. Internal Revenue Code Section 382 places limitations on the amount of taxable income which may be offset by tax carryforward attributes, such as net operating losses or tax credits after a change of ownership event. As a result of this ownership change, certain of our accumulated net operating losses may be subject to an annual limitation regarding their utilization against taxable income in future periods. The 2014 change creates an annual utilization limit of approximately $34.8 million on our ability to utilize net operating losses generated prior to the ownership change event. If we were to experience another ownership change in future periods, our net operating loss carryforwards may be subject to additional utilization limits.
FASB ASC 740-10 sets forth a two-step process for evaluating tax positions. The first step is financial statement recognition of the tax position based on whether it is more likely than not that the position will be sustained upon examination by taxing authorities and resolution through related appeals or litigation, based on the technical merits of the case. FASB ASC 740-10 mandates certain assumptions in applying the more likely than not judgment, including the presupposition of an examination where the taxing authorities are fully informed of all relevant information for evaluation of the tax position. In other words, FASB ASC 740-10 precludes factoring the likelihood of a tax examination into the evaluation of the outcome so that the evaluation is to focus solely on the technical merits of the position.
Our management has concluded that, as of December 31, 2015, we have not taken any tax positions that would require disclosure as “unrecognized positions” and that no liability balance is required to offset any unsustainable positions. We did not have any accrued interest or penalties as of December 31, 2015 and 2014.
105
We file a consolidated federal income tax return and separate or consolidated state income tax returns in the United States federal jurisdiction and in many state jurisdictions. We are subject to U.S. federal income tax examinations and to various state tax examinations for periods after August 1, 2007.
12. | EARNINGS PER COMMON SHARE |
Basic loss per common share is calculated based on the weighted average number of common shares outstanding at the end of the period, excluding restricted stock with performance-based and market-based vesting criteria. Diluted income per common share includes the speculative exercise of stock options and performance-based restricted stock which contain conditions that are not earnings or market-based, given that the hypothetical effect is not anti-dilutive. For each of the years ended December 31, 2015, 2014 and 2013, we excluded stock options to purchase 0.4 million shares of our common stock due to our Net Loss from Continuing Operations. For the years ended December 31, 2015, 2014 and 2013, we excluded performance-based restricted stock of 1.1 million shares, 0.8 million shares and 1.3 million shares, respectively, due to our Net Loss from Continuing Operations (for additional information on our non-cash compensation plans, see Note 15, Employee Benefit and Equity Plans, to our Consolidated Financial Statements). We utilize the if-converted method for calculating the impact of our 6.0% Convertible Perpetual Preferred Stock on diluted earnings per share. Under the if-converted method, convertible preferred stock is assumed as converted to common shares for the weighted average period outstanding. For the years ended December 31, 2015 and 2014, we excluded the assumed conversion of preferred stock equating to approximately 8.9 million and 3.3 million shares, respectively, due to our Net Loss from Continuing Operations. The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share data):
|
| Year Ended December 31, |
|
| Year Ended December 31, |
|
| Year Ended December 31, |
| |||
(in thousands, except per share amounts) |
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Numerator: |
|
|
|
|
|
|
|
|
|
|
|
|
Net Loss From Continuing Operations |
| $ | (399,018 | ) |
| $ | (47,650 | ) |
| $ | (2,384 | ) |
Net Income From Discontinued Operations, Less Noncontrolling Interests |
|
| 35,740 |
|
|
| 961 |
|
|
| 254 |
|
Less: Preferred Stock Dividends |
|
| 9,660 |
|
|
| 2,335 |
|
|
| — |
|
Net Loss Attributable to Common Shareholders |
| $ | (372,938 | ) |
| $ | (49,024 | ) |
| $ | (2,130 | ) |
Denominator: |
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average Common Shares Outstanding - Basic |
|
| 54,392 |
|
|
| 53,150 |
|
|
| 52,572 |
|
Weighted Average Common Shares Outstanding - Diluted |
|
| 54,392 |
|
|
| 53,150 |
|
|
| 52,572 |
|
Earnings per Common Share Attributable to Rex Energy Common Shareholders(a): |
|
|
|
|
|
|
|
|
|
|
|
|
Basic — Net Loss From Continuing Operations |
| $ | (7.51 | ) |
| $ | (0.94 | ) |
| $ | (0.05 | ) |
— Net Income From Discontinued Operations |
|
| 0.66 |
|
|
| 0.02 |
|
|
| 0.01 |
|
— Net Loss Attributable to Rex Energy Common Shareholders |
| $ | (6.85 | ) |
| $ | (0.92 | ) |
| $ | (0.04 | ) |
Diluted — Net Loss From Continuing Operations |
| $ | (7.51 | ) |
| $ | (0.94 | ) |
| $ | (0.05 | ) |
— Net Income From Discontinued Operations |
|
| 0.66 |
|
|
| 0.02 |
|
|
| 0.01 |
|
— Net Loss Attributable to Rex Energy Common Shareholders |
| $ | (6.85 | ) |
| $ | (0.92 | ) |
| $ | (0.04 | ) |
(a) | All earnings per share amounts are attributable to Rex common shareholders. |
13. | CAPITAL STOCK |
Common Stock
Currently, our common stock is traded on the NASDAQ Global Select Market under the trading symbol “REXX”. We have authorized capital stock of 100,000,000 shares of common stock and 100,000 shares of preferred stock. As of December 31, 2015 and 2014, we had 55,741,229 and 54,174,763 shares of common stock outstanding, respectively.
Preferred Stock
On August 18, 2014, we completed a registered offering of 16,100 shares of 6.0% Convertible Perpetual Preferred Stock, Series A, par value $0.001 per share (the “Series A Preferred Stock”) that are represented by 1,610,000 depositary shares. The net proceeds of the offering were approximately $155.0 million, after deducting underwriting discounts, commissions and other offering expenses.
106
We utilized a portion of the net proceeds to fund the acquisition of assets from Shell and used the remaining proceeds to fund our capital expenditures program and for general corporate purposes.
The annual dividend on each share of the Series A Preferred Stock is 6.0% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on each February 15, May 15, August 15 and November 15 of each year, commencing on November 15, 2014. During the first quarter of 2016, we suspended the payment of these dividends.
We pay cumulative dividends, when and if declared, in cash, stock or a combination thereof, on a quarterly basis at a rate of $600 per share, or 6.0%, per year. For the years ended December 31, 2015 and 2014, we declared quarterly cash dividends totaling approximately $9.7 million and $2.3 million, respectively.
The Series A Preferred Stock is convertible at the option of the holder at an initial conversion rate of 555.56 shares of our common stock per share (5.5556 shares of our common stock per depositary share), equivalent to an initial conversion price of $18.00 per share of common stock. The conversion price represents a premium of approximately 25.2% relative to the NASDAQ Global Market closing sale price of our common stock on August 12, 2014 or $14.38 per share.
At any time on or after August 30, 2019, we may at our option cause all outstanding shares of the Series A Preferred Stock to be automatically converted into common stock at the then-applicable conversion price if the closing sale price of our common stock exceeds 130% of the then-prevailing conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series A Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to the converting holder.
Except as required by law or our Certificate of Incorporation, holders of the Series A Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). Until such arrearage is paid in full, the holders will be entitled to elect two directors and the number of directors on our board of directors will increase by that same number.
14. | MAJOR CUSTOMERS |
For the year ended December 31, 2015, approximately $152.7 million, or 85.1%, of our commodity sales from continuing operations were attributable to four customers with the largest single purchaser accounting for $75.8 million, or 42.2%. For the year ended December 31, 2014, approximately $253.6 million, or 85.1% of our commodity sales from continuing operations were attributable to four customers with the largest single purchaser accounting for $96.4 million, or 32.4%. For the year ended December 31, 2013, approximately $179.5 million, or 83.9%, of our commodity sales from continuing operations were derived from four customers, with the largest customer being responsible for approximately $73.8 million, or 34.5%, of total commodity sales.
15. | EMPLOYEE BENEFIT AND EQUITY PLANS |
401(k) Plan
We sponsor a 401(k) Plan for eligible employees who have satisfied age and service requirements. Employees can make contributions to the plan up to allowable limits. Our contributions to the plan are discretionary. Our contributions to the plan attributable to continuing operations were approximately $0.8 million, $0.9 million and $0.7 million for the years ended December 31, 2015, 2014 and 2013, respectively.
Equity Plans
We recognize all share-based payments to employees, including grants of employee stock options, in our Consolidated Statements of Operations based on their grant-date fair values, using prescribed option-pricing models where applicable. The fair value is expensed over the requisite service period of the individual grantees, which generally equals the vesting period. We report any benefits of income tax deductions in excess of recognized financial accounting compensation as a financing cash flow, rather than as an operating cash flow.
2007 Long-Term Incentive Plan
We have granted stock options and restricted stock awards to various employees, non-employee directors and non-employee contractors under the terms of our Amended and Restated 2007 Long-Term Incentive Plan (the “Plan”). The Plan is administered by the Compensation Committee of our board of directors (the “Compensation Committee”). Among the Compensation Committee’s responsibilities are selecting participants to receive awards, determining the form, amount and other terms and conditions of awards,
107
interpreting the provisions of the Plan or any award agreement and adopting such rules, forms, instruments and guidelines for administering the Plan as it deems necessary or proper. All actions, interpretations and determinations by the Compensation Committee are final and binding. The composition of the Compensation Committee is intended to permit the awards under the Plan to qualify for exemption under Rule 16b-3 of the Exchange Act. In addition, awards under the Plan, including annual incentive awards paid to executive officers subject to section 162(m) of the Code or covered employees may be designed, at the Compensation Committee’s discretion, to satisfy the requirements of section 162(m) to permit the deduction by us of the associated expenses for federal income tax purposes. The Compensation Committee has authorized the issuance of 5,979,470 shares under the Plan, with 1,144,297 and 2,825,260 still available as of December 31, 2015 and 2014, respectively.
All awards granted under the Plan have been issued at the prevailing market price at the time of the grant. All outstanding stock options have been awarded with five or ten year expiration at an exercise price equal to our closing price on the NASDAQ Global Select Market on the day of the award. A forfeiture rate based on a blended average of individual participant terminations and number of awards cancelled is used to estimate forfeitures prospectively.
Stock Options
Stock options represent the right to purchase shares of stock in the future at the fair market value of the stock on the date of grant. In the event that any outstanding award expires, is forfeited, cancelled or otherwise terminated without the issuance of shares of our common stock or is otherwise settled in cash, shares of our common stock allocable to such award, including the unexercised portion of such award, shall again be available for the purposes of the Plan. If any award is exercised by tendering shares of our common stock to us, either as full or partial payment, in connection with the exercise of such award under the Plan or to satisfy our withholding obligation with respect to an award, only the number of shares of our common stock issued net of such shares tendered will be deemed delivered for purposes of determining the maximum number of shares of our common stock then available for delivery under the Plan. During the year ended December 31, 2015, we issued 80,000 options to purchase shares of our common stock to three employees. During the year ended December 31, 2014, we did not issue options to purchase shares of our common stock.
A summary of the stock option activity is as follows:
|
| Number of Shares |
|
| Weighted-Average Exercise Price |
|
| Weighted-Average Remaining Term (in years) |
|
| Aggregate Intrinsic Value (in thousands) |
| ||||
Options outstanding December 31, 2012 |
|
| 502,253 |
|
| $ | 10.95 |
|
|
|
|
|
|
|
|
|
Granted |
|
| — |
|
|
| — |
|
|
|
|
|
|
|
|
|
Exercised |
|
| (49,166 | ) |
|
| 10.85 |
|
|
|
|
|
|
|
|
|
Cancelled/Forfeited |
|
| (4,000 | ) |
|
| 23.28 |
|
|
|
|
|
|
|
|
|
Options outstanding December 31, 2013 |
|
| 449,087 |
|
| $ | 10.85 |
|
|
|
|
|
|
|
|
|
Granted |
|
| — |
|
|
| — |
|
|
|
|
|
|
|
|
|
Exercised |
|
| (46,526 | ) |
|
| 11.09 |
|
|
|
|
|
|
|
|
|
Cancelled/Forfeited |
|
| - |
|
|
| - |
|
|
|
|
|
|
|
|
|
Options outstanding December 31, 2014 |
|
| 402,561 |
|
| $ | 10.82 |
|
|
|
|
|
|
|
|
|
Granted |
|
| 80,000 |
|
|
| 4.48 |
|
|
|
|
|
|
|
|
|
Exercised |
|
| - |
|
|
| - |
|
|
|
|
|
|
|
|
|
Cancelled/Forfeited |
|
| (38,889 | ) |
|
| 11.23 |
|
|
|
|
|
|
|
|
|
Options Outstanding December 31, 2015 |
|
| 443,672 |
|
| $ | 9.64 |
|
|
| 2.8 |
|
| $ | — |
|
Options Exercisable December 31, 2015 |
|
| 363,672 |
|
| $ | 10.77 |
|
|
| 2.1 |
|
| $ | — |
|
Stock-based compensation expense from continuing operations relating to stock options for the year ended December 31, 2015, was negligible and for the years ended December 31, 2014 and 2013 totaled $0.1 million and $0.2 million, respectively. The expense related to stock option grants was recorded on our Consolidated Statements of Operations under the heading of General and Administrative expense. No stock options were exercised for the year ended December 31, 2015. The intrinsic value of stock options exercised for the years ended December 31, 2014 and 2013 was $0.3 million and $0.4 million, respectively. The total tax benefit for the years ended December 31, 2015 was negligible and for the years ended December 31, 2014 and 2013 was approximately $0.1 million and $0.2 million, respectively.
108
A summary of the status of our issued and outstanding stock options as of December 31, 2015 is as follows:
|
|
|
| Outstanding |
|
| Exercisable |
| ||||||||||
Exercise Price |
|
| Number Outstanding At 12/31/15 |
|
| Weighted-Average Exercise Price |
|
| Number Exercisable At 12/31/15 |
|
| Weighted-Average Exercise Price |
| |||||
$ | 4.05 |
|
|
| 40,000 |
|
| $ | 4.05 |
|
|
| - |
|
| $ | - |
|
$ | 4.90 |
|
|
| 40,000 |
|
| $ | 4.90 |
|
|
| - |
|
| $ | - |
|
$ | 5.04 |
|
|
| 46,041 |
|
| $ | 5.04 |
|
|
| 46,041 |
|
| $ | 5.04 |
|
$ | 9.50 |
|
|
| 75,000 |
|
| $ | 9.50 |
|
|
| 75,000 |
|
| $ | 9.50 |
|
$ | 9.99 |
|
|
| 129,583 |
|
| $ | 9.99 |
|
|
| 129,583 |
|
| $ | 9.99 |
|
$ | 10.42 |
|
|
| 29,548 |
|
| $ | 10.42 |
|
|
| 29,548 |
|
| $ | 10.42 |
|
$ | 11.89 |
|
|
| 3,500 |
|
| $ | 11.89 |
|
|
| 3,500 |
|
| $ | 11.89 |
|
$ | 13.19 |
|
|
| 50,000 |
|
| $ | 13.19 |
|
|
| 50,000 |
|
| $ | 13.19 |
|
$ | 22.34 |
|
|
| 30,000 |
|
| $ | 22.34 |
|
|
| 30,000 |
|
| $ | 22.34 |
|
|
|
|
|
| 443,672 |
|
| $ | 9.64 |
|
|
| 363,672 |
|
| $ | 10.77 |
|
The weighted average remaining contractual term for options exercisable at December 31, 2015 was 2.1 years and the aggregate intrinsic value was negligible. The weighted average remaining contractual term and the aggregate intrinsic value for options outstanding at December 31, 2014 were 2.9 years and negligible, respectively. As of December 31, 2015, unrecognized compensation expense related to stock options was $0.1 million.
Restricted Stock Awards
During the year ended December 31, 2015, the Compensation Committee issued 2,236,839 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. During the year ended December 31, 2014, the Compensation Committee issued 131,610 shares of restricted common stock to selected employees, non-employee directors and non-employee contractors. The shares granted in 2015 and 2014 are subject to time vesting and, in some cases, performance-based vesting. The shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date until the date upon which the shares are released. Restrictions on the transfer associated with vesting schedules were determined by the Compensation Committee on an individual award basis. The restricted common stock is valued at the closing price of our common stock on the NASDAQ Global Select Market on the date of the grant. Upon a “change in control” of us, as such term is defined in the Plan, all restrictions will immediately lapse for performance-based awards to varying degrees based on performance metrics at the time of the change in control. For awards that do not contain a performance-based condition, all restrictions immediately lapse upon a change in control. Compensation expense associated with the restricted stock award is recognized on a straight-line basis over the vesting period.
Certain of the restricted common stock awards in 2015, 2014 and 2013 are subject to market-based vesting through a calculation of total shareholder return (“TSR”) of our common stock relative to a pre-defined peer group of 13 to 15 companies over a three-year period. The number of shares ultimately awarded will correspond with the final TSR rank amongst the peer group in accordance with the following schedule:
TSR Rank |
| Percentage of Awards to Vest |
| |
1-3 |
|
| 100 | % |
4-6 |
|
| 75 | % |
7-10 |
|
| 50 | % |
11-13 |
|
| 25 | % |
14-16 |
|
| 0 | % |
The weighted average fair value of the TSR awards as of December 31, 2015, 2014 and 2013 were $2.56, $10.15 and $12.59 per share, respectively. Average fair values were estimated on the date of each grant using a Monte Carlo Simulation model that estimates the most likely outcome based on the terms of the award and used the following assumptions:
109
| Year Ended December 31, 2015 |
|
| Year Ended December 31, 2014 |
| |||
Expected Dividend Yield |
|
| 0.0 | % |
|
| 0.0 | % |
Risk-Free Interest Rate |
|
| 1.0 | % |
|
| 0.8 | % |
Expected Volatility – Rex Energy |
|
| 58.6 | % |
|
| 50.4 | % |
Expected Volatility – Peer Group |
| 29.8%-85.0% |
|
| 28.4%-65.7% |
| ||
Market Index |
|
| 35.6 | % |
|
| 35.3 | % |
Expected Life |
| Three Years |
|
| Three Years |
|
The dividend yield of zero reflects the fact that we have never paid cash dividends on our common stock and have no present intentions of doing so. The risk-free interest rate reflects the U.S. Treasury Constant Maturity rates as of the measurement date, converted into an implied “spot rate” yield. Our expected volatility estimates are based on observed historical volatility of daily stock returns for the three-year period preceding the grant date. Market index is an equal-weight index of the companies in the peer group. Expected life is measured as the grant date through the end of the performance period. Performance and market shares will vest on the date on which the Compensation Committee certifies that the performance goals have been satisfied, provided that the recipient has been in continuous employment with us from the grant date through the third anniversary of the grant date. Compensation expense for the TSR awards is recognized on a straight-line basis over the vesting period.
We recorded compensation expense related to restricted common stock awards of $6.4 million, $5.8 million and $5.1 million for the years ended December 31, 2015, 2014 and 2013, respectively. During the first quarter of 2015, the board of directors approved a waiver to certain performance factors for restricted stock awards that vested in March 2015. This waiver resulted in the vesting of approximately 189,872 restricted stock awards with associated expense of approximately $2.5 million. As of December 31, 2015, total unrecognized compensation cost related to the restricted common stock grants was approximately $4.5 million to be recognized over a weighted average of 1.7 years. The total fair value of restricted common stock awards that vested in 2015 was approximately $2.0 million as compared to $7.7 million for restricted common stock awards that vested in 2014.
A summary of the restricted stock activity for the years ended December 31, 2015, 2014 and 2013 is as follows:
|
| Number of Shares |
|
| Weighted-Average Grant Date Fair Value |
| ||
Restricted stock awards, as of January 1, 2013 |
|
| 1,431,573 |
|
| $ | 12.45 |
|
Awards |
|
| 981,544 |
|
|
| 16.03 |
|
Vested |
|
| (182,994 | ) |
|
| 11.59 |
|
Forfeitures |
|
| (57,484 | ) |
|
| 11.84 |
|
Restricted stock awards, as of December 31, 2013 |
|
| 2,172,639 |
|
| $ | 14.16 |
|
Awards |
|
| 131,610 |
|
|
| 8.76 |
|
Vested |
|
| (595,085 | ) |
|
| 13.09 |
|
Forfeitures |
|
| (189,863 | ) |
|
| 14.60 |
|
Restricted stock awards, as of December 31, 2014 |
|
| 1,519,301 |
|
| $ | 14.05 |
|
Awards |
|
| 2,236,839 |
|
|
| 3.35 |
|
Vested |
|
| (606,359 | ) |
|
| 9.39 |
|
Forfeitures |
|
| (670,373 | ) |
|
| 11.33 |
|
Restricted stock awards, as of December 31, 2015 |
|
| 2,479,408 |
|
| $ | 6.27 |
|
16. | IMPAIRMENT EXPENSE |
For the years ended December 31, 2015, 2014 and 2013, we incurred impairment expense from continuing operations of approximately $345.8 million, $132.6 million and $32.1 million, respectively. We continually monitor the carrying value of our oil and gas properties and make evaluations of their recoverability when circumstances arise that may contribute to impairment (for additional information see Note 2, Summary of Significant Accounting Policies, to our Consolidated Financial Statements). Approximately $271.3 million of the impairment incurred during 2015 was attributable to proved properties and other fixed assets, of which approximately $47.7 million was attributable to our conventional oil properties in the Illinois Basin, $205.4 million was attributable to the unconventional assets in the Appalachian Basin and $17.5 million was attributable to our equity method investment in RW Gathering. The remaining proved property impairment expense is related to our conventional dry gas assets and salt water disposal well in the Appalachian Basin. In addition, we also incurred approximately $74.5 million in unproved property impairments,
110
of which approximately $59.7 million was related to leases in the Appalachian Basin and approximately $14.8 million was attributable to leases in the Illinois Basin. The impairments were identified through an analysis of market conditions and future development plans that were in existence as of December 31, 2015, related to these properties, which indicated that the carrying value of the assets was not recoverable. The analysis included an evaluation of estimated future cash flows with consideration given to market prices for similar assets. The primary reason for the decrease in the estimated future cash flows of our assets is attributable to the continued depression of current and estimated future commodity prices as of December 31, 2015. Our estimates of future cash flows attributable to our oil and gas properties could decline further if commodity prices continue to decline, which may result in our incurrence of additional impairment expense. As of December 31, 2015, we continued to carry the costs of unproved properties of approximately $263.0 million on our Consolidated Balance Sheet, which is primarily related to the Marcellus and Utica Shale in the Appalachian Basin and for which we have development, trade or lease extension plans.
During 2014, we recorded impairment expense of $132.6 million. Approximately $113.4 million of the impairment incurred during 2014 was attributable to proved properties and other fixed assets, of which approximately $103.9 million was attributable to the Illinois Basin and $9.5 million was attributable to the Appalachian Basin. In the Illinois Basin, which is 100% oil producing, the estimated future decline in oil prices as of December 31, 2014, caused the estimated future cash flows of certain properties to decrease below a level at which the carrying value that is expected to be recovered. In the Appalachian Basin, approximately $5.9 million of impairment was incurred for our salt water disposal well in Ohio due to the regulatory and environmental climate and the uncertainty of future viability of the disposal well. We also incurred approximately $3.6 million of impairment related to shallow conventional gas properties in the Appalachian Basin, which is attributable to the estimated future decrease in natural gas pricing as of December 31, 2014. In addition to our proved property and fixed asset impairments, we also incurred approximately $18.9 million in unproved property impairments. In the Appalachian Basin, we incurred approximately $10.4 million in unproved property impairments related to expiring leases that will not be developed. In the Illinois Basin, we incurred approximately $8.5 million of unproved property impairment primarily due to the estimated future economics of the properties at the depressed commodity price environment at December 31, 2014.
During 2013, we recorded impairment expense of $32.1 million. Approximately $29.3 million of expense incurred during 2013 was related to the impairment of conventional oil properties in the Illinois Basin. The impairment in Illinois was focused in two areas where extensive development activity occurred during 2013. In addition to the development activity, future estimated prices for the sale of crude oil as of December 31, 2013 decreased to a level which did not support the recovery of the full carrying value of the properties.
17. | SUSPENDED EXPLORATORY WELL COSTS |
We capitalize the costs of exploratory wells if a well finds a sufficient quantity of reserves to justify its completion as a producing well and we are making sufficient progress towards assessing the reserves and the economic and operating viability of the project.
The following table reflects the net change in capitalized exploratory well costs, excluding those related to Assets Held for Sale on our Consolidated Balance Sheets for the years ended December 31, 2015, 2014 and 2013 ($ in thousands):
111
| 2015 |
|
| 2014 |
|
| 2013 |
| ||||
Beginning Balance at January 1, |
| $ | 23,101 |
|
| $ | 5,731 |
|
| $ | 36,968 |
|
Additions to capitalized exploratory well costs pending the determination of estimated proved reserves |
|
| 144,954 |
|
|
| 258,097 |
|
|
| 171,087 |
|
Divested wells |
|
| — |
|
|
| — |
|
|
| — |
|
Reclassification of wells, facilities, and equipment based on the determination of estimated proved reserves |
|
| (147,850 | ) |
|
| (240,494 | ) |
|
| (202,323 | ) |
Capitalized exploratory well costs charged to expense |
|
| (2,907 | ) |
|
| (233 | ) |
|
| (1 | ) |
Ending Balance at December 31, |
|
| 17,298 |
|
|
| 23,101 |
|
|
| 5,731 |
|
Less exploratory well costs that have been capitalized for a period of one year or less |
|
| (12,156 | ) |
|
| (20,407 | ) |
|
| (3,597 | ) |
Capitalized exploratory well costs for a period of greater than one year |
| $ | 5,142 |
|
| $ | 2,694 |
|
| $ | 2,134 |
|
Number of projects that have exploratory well costs capitalized for a period of more than one year |
|
| 14 |
|
|
| 6 |
|
|
| 3 |
|
As of December 31, 2015 we had approximately $5.1 million in capitalized exploratory well costs that were capitalized for a period greater than one year. These costs are related to nine wells in Butler County, Pennsylvania, four wells in Lawrence County, Pennsylvania and one well in our non-operated region of the Illinois Basin. In Butler County, Pennsylvania there are eight completed wells that are awaiting infrastructure and one that has been drilled and is awaiting completion. In Lawrence County, Pennsylvania, there are three completed wells that are awaiting infrastructure and one drilled well that is awaiting completion. In Kentucky, there is one well with plans to convert to a disposal well to support other proven wells in region. The properties located in Pennsylvania are wells that we purchased through our acquisition from Shell in 2014. As we continue to develop the acquired acreage from Shell and build out the infrastructure we plan to opportunistically complete these wells and place them into sales. These costs are currently classified as Wells and Facilities in Progress on our Consolidated Balance Sheets and will be reclassified to Evaluated Oil and Gas Properties upon the discovery of proved reserves or to Exploration Expense if commercial quantities of reserves are not found.
18. | COSTS INCURRED IN OIL AND NATURAL GAS ACQUISITION, EXPLORATION AND DEVELOPMENT ACTIVITIES (UNAUDITED) |
Costs incurred in oil and natural gas property acquisitions and development are presented below and exclude any costs incurred related to Assets Held for Sale (in thousands):
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Consolidated Entities: |
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Properties |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
| $ | 1 |
|
| $ | 161 |
|
| $ | 2,445 |
|
Unproved |
|
| 28,242 |
|
|
| 169,408 |
|
|
| 39,291 |
|
Exploration Costs(a) |
|
| 158,318 |
|
|
| 316,235 |
|
|
| 231,112 |
|
Development Costs(a) |
|
| 31,574 |
|
|
| 71,383 |
|
|
| 64,661 |
|
Subtotal |
|
| 218,135 |
|
|
| 557,187 |
|
|
| 337,509 |
|
Asset Retirement Obligations |
|
| 2,818 |
|
|
| 9,110 |
|
|
| 3,031 |
|
Total Costs Incurred |
| $ | 220,953 |
|
| $ | 566,297 |
|
| $ | 340,540 |
|
Share of Equity Method Investments: |
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition of Properties |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
| $ | — |
|
| $ | — |
|
| $ | — |
|
Unproved |
|
| — |
|
|
| — |
|
|
| — |
|
Exploration Costs |
|
| — |
|
|
| — |
|
|
| — |
|
Development Costs(a) |
|
| 824 |
|
|
| 438 |
|
|
| 1,958 |
|
Total |
| $ | 824 |
|
| $ | 438 |
|
| $ | 1,958 |
|
(a) | Includes Depreciation expense for support equipment and facilities |
112
The following table provides a reconciliation of the total costs incurred for our consolidated entities to our reported capital expenditures (in thousands):
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Total Costs Incurred by Consolidated Entities |
| $ | 220,953 |
|
| $ | 566,297 |
|
| $ | 340,540 |
|
Equity Method Investments |
|
| — |
|
|
| — |
|
|
| 2,493 |
|
DJ Basin Expenditures |
|
| — |
|
|
| — |
|
|
| 2 |
|
Exploration Expense |
|
| (3,011 | ) |
|
| (9,446 | ) |
|
| (11,408 | ) |
Asset Retirement Obligations |
|
| (2,818 | ) |
|
| (9,110 | ) |
|
| (3,031 | ) |
Depreciation for Support Equipment and Facilities |
|
| (4,905 | ) |
|
| (6,075 | ) |
|
| (5,024 | ) |
Corporate Expenditures |
|
| 231 |
|
|
| 869 |
|
|
| 3,651 |
|
Other (a) |
|
| (16,522 | ) |
|
| 7,223 |
|
|
| 10,391 |
|
Total Capital Expenditures |
| $ | 193,928 |
|
| $ | 549,758 |
|
| $ | 337,614 |
|
(a) | Represents R.E. Disposal, LLC capital, future proceeds from ArcLight and intercompany capital transactions. |
19. | OIL AND NATURAL GAS CAPITALIZED COSTS (UNAUDITED) |
Our aggregate capitalized costs for natural gas and oil production activities with applicable accumulated depreciation, depletion and amortization are presented below and exclude any properties classified as Assets Held for Sale (in thousands):
|
| 2015 |
|
| 2014 |
| ||
Consolidated Entities: |
|
|
|
|
|
|
|
|
Proven Oil and Natural Gas Properties |
| $ | 1,239,430 |
|
| $ | 1,079,039 |
|
Pipelines and Support Equipment |
|
| 17,030 |
|
|
| 24,248 |
|
Field Operation Vehicles and Other Equipment |
|
| 28,064 |
|
|
| 27,030 |
|
Wells and Facilities in Progress |
|
| 144,408 |
|
|
| 127,597 |
|
Unproven Properties |
|
| 262,992 |
|
|
| 322,413 |
|
Total |
|
| 1,691,924 |
|
|
| 1,580,327 |
|
Less Accumulated Depreciation and Depletion |
|
| (696,447 | ) |
|
| (362,804 | ) |
Total |
| $ | 995,477 |
|
| $ | 1,217,523 |
|
Share of Equity Method Investments: |
|
|
|
|
|
|
|
|
Pipelines and Support Equipment |
|
| 19,970 |
|
|
| 19,946 |
|
Wells and Facilities in Progress |
|
| — |
|
|
| - |
|
Total |
|
| 19,970 |
|
|
| 19,946 |
|
Less Accumulated Depreciation and Depletion |
|
| (3,411 | ) |
|
| (2,611 | ) |
Total |
| $ | 16,559 |
|
| $ | 17,335 |
|
20. | OIL AND NATURAL GAS RESERVE QUANTITIES (UNAUDITED) |
Our independent engineers, Netherland, Sewell, and Associates, Inc. (“NSAI”) evaluated all of our proved oil, natural gas and NGL reserves for the years ended December 31, 2015, 2014 and 2013. The technical persons responsible for preparing the estimates of our estimated proved reserves meet the requirements with regards to qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our independent third-party engineers do not own an interest in any of our properties and are not employed by us on a contingent basis. We emphasize that reserve estimates are inherently imprecise. Our oil, natural gas and NGL reserve estimates were generally based upon extrapolation of historical production trends, analogy to similar properties and volumetric calculations. Accordingly, these estimates are expected to change, and such change could be material and occur in the near term as future information becomes available. All of our estimated proved reserves are located within the United States.
Proved natural gas, oil and NGL reserves are those quantities of natural gas, oil and NGL which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. Based on reserve reporting rules, the price is calculated using the average
113
price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. A project to extract hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible natural gas or oil on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Developed natural gas, oil and NGL reserves are reserves of any category that can be expected to be recovered (x) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (y) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Undeveloped natural gas, oil and NGL reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
Presented below is a summary of changes in estimated reserves of the oil and natural gas wells at December 31, 2015, 2014 and 2013:
|
| 2015 |
| |||||||||||||
|
| Oil (MBbls) |
|
| NGL (MBbls) |
|
| Natural Gas (MMcf) |
|
| (MMcf) Equivalents |
| ||||
Estimated Proved Reserves-Beginning of Period |
|
| 9,684.7 |
|
|
| 73,252.5 |
|
|
| 839,185.1 |
|
|
| 1,336,808.3 |
|
Extensions, Discoveries and Additions |
|
| 949.0 |
|
|
| 10,079.3 |
|
|
| 76,816.9 |
|
|
| 142,986.7 |
|
Revisions of Previous Estimates |
|
| (4,176.8 | ) |
|
| (38,249.7 | ) |
|
| (448,461.3 | ) |
|
| (703,020.3 | ) |
Purchases |
|
| (7.7 | ) |
|
| (1,389.6 | ) |
|
| (16,471.1 | ) |
|
| (24,854.9 | ) |
Production |
|
| (1,132.1 | ) |
|
| (3,345.9 | ) |
|
| (44,606.8 | ) |
|
| (71,474.8 | ) |
Estimated Proved Reserves-End of Period |
|
| 5,317.1 |
|
|
| 40,346.6 |
|
|
| 406,462.8 |
|
|
| 680,445.0 |
|
|
| 2014 |
| |||||||||||||
|
| Oil (MBbls) |
|
| NGL (MBbls) |
|
| Natural Gas (MMcf) |
|
| (MMcf) Equivalents |
| ||||
Estimated Proved Reserves-Beginning of Period |
|
| 8,619.6 |
|
|
| 46,130.7 |
|
|
| 521,282.8 |
|
|
| 849,784.6 |
|
Extensions, Discoveries and Additions |
|
| 1,723.1 |
|
|
| 31,160.3 |
|
|
| 326,464.2 |
|
|
| 523,764.6 |
|
Revisions of Previous Estimates |
|
| 471.1 |
|
|
| (2,889.1 | ) |
|
| 9,971.0 |
|
|
| (4,537.0 | ) |
Purchases |
|
| 12.0 |
|
|
| 933.0 |
|
|
| 18,478.3 |
|
|
| 24,148.3 |
|
Production |
|
| (1,141.1 | ) |
|
| (2,082.4 | ) |
|
| (37,011.2 | ) |
|
| (56,352.2 | ) |
Estimated Proved Reserves-End of Period |
|
| 9,684.7 |
|
|
| 73,252.5 |
|
|
| 839,185.1 |
|
|
| 1,336,808.3 |
|
114
|
| 2013 |
| |||||||||||||
|
| Oil (MBbls) |
|
| NGL (MBbls) |
|
| Natural Gas (MMcf) |
|
| (MMcf) Equivalents |
| ||||
Estimated Proved Reserves-Beginning of Period |
|
| 9,375.7 |
|
|
| 31,679.9 |
|
|
| 371,716.4 |
|
|
| 618,050.0 |
|
Extensions, Discoveries and Additions |
|
| 595.6 |
|
|
| 19,956.1 |
|
|
| 189,150.9 |
|
|
| 312,461.1 |
|
Revisions of Previous Estimates |
|
| (438.5 | ) |
|
| (4,685.6 | ) |
|
| (16,137.7 | ) |
|
| (46,882.3 | ) |
Purchases |
|
| 1.0 |
|
|
| — |
|
|
| — |
|
|
| 6.0 |
|
Production |
|
| (914.2 | ) |
|
| (819.7 | ) |
|
| (23,446.8 | ) |
|
| (33,850.2 | ) |
Estimated Proved Reserves-End of Period |
|
| 8,619.6 |
|
|
| 46,130.7 |
|
|
| 521,282.8 |
|
|
| 849,784.6 |
|
|
| Oil (MBbls) |
|
| NGL (MBbls) |
|
| Natural Gas (MMcf) |
|
| (MMcf) Equivalents |
| ||||
Proved Developed Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015 |
|
| 4,944.6 |
|
|
| 37,941.9 |
|
|
| 389,754.4 |
|
|
| 647,073.4 |
|
December 31, 2014 |
|
| 7,628.1 |
|
|
| 29,215.0 |
|
|
| 365,673.3 |
|
|
| 586,731.9 |
|
December 31, 2013 |
|
| 7,742.5 |
|
|
| 16,322.5 |
|
|
| 212,061.4 |
|
|
| 356,451.4 |
|
Proved Undeveloped Reserves |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2015 |
|
| 372.5 |
|
|
| 2,404.7 |
|
|
| 16,708.4 |
|
|
| 33,371.6 |
|
December 31, 2014 |
|
| 2,056.6 |
|
|
| 44,037.5 |
|
|
| 473,511.8 |
|
|
| 750,076.4 |
|
December 31, 2013 |
|
| 877.1 |
|
|
| 29,808.2 |
|
|
| 309,221.4 |
|
|
| 493,333.2 |
|
Our estimated proved undeveloped reserves did not include any locations that generated a positive future net revenue and a negative present value discounted at 10%. We may, from time to time, have proved undeveloped locations with these characteristics based on our planned operating budget and strategy to hold acreage by production combined with our expectations of future commodity prices.
Revisions. Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from developmental drilling and production history or resulting from a change in economic factors, such as commodity prices and operating costs.
Our revisions in 2015 included a negative adjustment of approximately 741.1 Bcfe related to lower commodity prices. This negative adjustment was partially offset by positive revision of approximately 15.4 Bcfe related to positive operating expenses, 4.1 Bcfe related to changes in our ethane recovery expectations and 18.6 Bcfe related to technical revisions. The positive technical revisions included 10.3 Bcfe in our Butler County, Pennsylvania area related to positive well performance. An additional 9.8 Bcfe of positive technical revisions were related to positive well performance in our Warrior North prospect in Ohio. These additions were partially offset by approximately 2.2 Bcfe in negative technical revisions related to well performance in our other areas of operation.
Our revisions in 2014 included a negative adjustment of approximately 58.5 Bcfe related to PUD locations that were not developed within five years, negative revisions of 1.6 Bcfe related to commodity pricing, positive revisions of 17.6 Bcfe related to favorable operating expenses and positive technical revisions of 38.0 Bcfe. The negative revisions were related to PUD locations that were previously booked in our Butler County, Pennsylvania region. The positive technical revisions included 51.0 Bcfe in our Butler County, Pennsylvania area related to positive well performance which was partially offset by negative revisions related to well performance in our Warrior South prospect and our non-operated Westmoreland County, Pennsylvania area of approximately 15.5 Bcfe.
We had significant revisions in our oil, NGL and natural gas reserves for the year ended December 31, 2013. Our negative revisions were primarily due to adjusting downward our estimated recovery of future ethane production from 2012 to 2013. Negative revisions related to our estimated ethane recovery accounted for approximately 27.3 Bcfe of our total revisions. In addition to our ethane recovery adjustments, we recognized additional negative revisions related to well performance in our non-operated Westmoreland County, Pennsylvania region as well as in the Illinois Basin. Partially offsetting these negative revisions were positive revisions due to natural gas pricing and lower than expected operating expenses.
Extensions, discoveries and other additions. These are additions to estimated proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with estimated proved reserves or of new reservoirs of estimated proved reserves in old fields.
115
We had significant extensions, discoveries and other additions for the year ended December 31, 2015, of 0.9 MMBOE of oil, 10.1 MMBOE of NGLs and 76.8 Bcfe of natural gas. We had significant extensions, discoveries and other additions for the year ended December 31, 2014, of 1.7 MMBOE of oil, 31.2 MMBOE of NGLs and 326.5 Bcf of natural gas. During 2013, we had extensions, discoveries and other additions of 0.6 MMBOE of oil, 20.0 MMBOE of NGLs and 189.1 Bcf of natural gas. Our continued success in the Appalachian Basin has been the primary contributor to the growth of our extensions, discoveries and other additions, specifically the Marcellus and Utica Shales. At December 31, 2015, approximately 102.1 Bcfe of our extensions, discoveries and other additions were related to Marcellus Shale properties while an additional 30.0 Bcfe was related to the Utica Shale.
21. | STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) |
FASB ASC 932 prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to the estimated proved reserves. We followed these guidelines, which are briefly discussed below.
Future cash inflows and future production and development costs are determined by applying year-end prices and costs to estimate quantities of oil and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the year-end prices and costs used. Estimates are made of quantities of estimated proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions. The resulting future net cash flows are reduced to present value amounts by applying a 10.0% annual discount factor.
The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.
The following summary sets forth our future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by FASB ASC 932 at December 31, 2015, 2014 and 2013 ($ in thousands):
|
| 2015 |
|
| 2014 |
|
| 2013 |
|
| |||
Future Cash Inflows |
| $ | 1,716,131 |
| (a) | $ | 5,824,231 |
| (b) | $ | 3,899,878 |
| (c) |
Future Costs: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
| (1,144,049 | ) |
|
| (2,332,151 | ) |
|
| (1,619,629 | ) |
|
Abandonment |
|
| (143,459 | ) |
|
| (134,308 | ) |
|
| (95,183 | ) |
|
Development |
|
| (18,952 | ) |
|
| (686,676 | ) |
|
| (517,875 | ) |
|
Net Future Cash Inflow Before Income Taxes |
|
| 409,671 |
|
|
| 2,671,096 |
|
|
| 1,667,191 |
|
|
Future Income Tax Expense |
|
| — |
|
|
| (468,597 | ) |
|
| (359,322 | ) |
|
Total Future Net Cash Flows Before 10.0% Discount |
|
| 409,671 |
|
|
| 2,202,499 |
|
|
| 1,307,869 |
|
|
Less: Effect of 10.0% Discount Factor |
|
| (154,048 | ) |
|
| (1,177,135 | ) |
|
| (778,756 | ) |
|
Standardized Measure of Discounted Future Net Cash Flows |
| $ | 255,623 |
|
| $ | 1,025,364 |
|
| $ | 529,113 |
|
|
(a) | Calculated using weighted average prices of $2.401 per Mcf, $44.45 per barrel of oil and $12.48 per barrel of NGLs |
(b) | Calculated using weighted average prices of $3.455 per Mcf, $88.02 per barrel of oil and $28.30 per barrel of NGLs |
(c) | Calculated using weighted average prices of $3.588 per Mcf, $94.28 per barrel of oil and $26.37 per barrel of NGLs |
The principal sources of change in the standardized measure of discounted future net cash flows are as follows:
116
| 2015 |
|
| 2014 |
|
| 2013 |
| ||||
Standardized Measure – Beginning of Period |
| $ | 1,025,364 |
|
| $ | 529,113 |
|
| $ | 396,123 |
|
Revisions of Previous Estimates: |
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Prices and Production Costs |
|
| (1,296,866 | ) |
|
| 253,865 |
|
|
| 72,503 |
|
Revisions in Quantities |
|
| (270,673 | ) |
|
| (5,970 | ) |
|
| (51,289 | ) |
Changes in Future Development Costs |
|
| 595,547 |
|
|
| (51,794 | ) |
|
| 22,341 |
|
Accretion of Discount and Timing of Future Cash Flows |
|
| 116,514 |
|
|
| 64,013 |
|
|
| 47,571 |
|
Net Change in Income Tax |
|
| 139,776 |
|
|
| 28,756 |
|
|
| 31,433 |
|
Purchase (Sale) of Reserves in Place |
|
| (37,101 | ) |
|
| 28,316 |
|
|
| - |
|
Plus Extensions, Discoveries, and Other Additions |
|
| 88,152 |
|
|
| 430,252 |
|
|
| 170,846 |
|
Development Costs Incurred |
|
| 31,574 |
|
|
| 71,383 |
|
|
| 64,661 |
|
Sales of Product – Net of Production Costs |
|
| (52,952 | ) |
|
| (197,587 | ) |
|
| (151,781 | ) |
Changes in Timing and Other |
|
| (83,712 | ) |
|
| (124,983 | ) |
|
| (73,295 | ) |
Standardized Measure – End of Period |
| $ | 255,623 |
|
| $ | 1,025,364 |
|
| $ | 529,113 |
|
22. | RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) |
Results of operations are equal to revenues, less (a) production costs, (b) impairment expenses, (c) exploration expenses, (d) DD&A expenses, and (e) income tax expense (benefit) (certain prior year amounts have been reclassified to conform to current presentation):
|
| 2015 |
|
| 2014 |
|
| 2013 |
| |||
Consolidated Entities (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Natural Gas Sales |
| $ | 171,951 |
|
| $ | 297,869 |
|
| $ | 213,919 |
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
|
| 118,999 |
|
|
| 100,282 |
|
|
| 62,150 |
|
Impairment Expense |
|
| 345,775 |
|
|
| 132,618 |
|
|
| 32,072 |
|
Exploration Expense |
|
| 3,011 |
|
|
| 9,446 |
|
|
| 11,408 |
|
Depletion, Depreciation, Amortization and Accretion |
|
| 104,744 |
|
|
| 94,467 |
|
|
| 62,386 |
|
Total Costs |
|
| 572,529 |
|
|
| 336,813 |
|
|
| 168,016 |
|
Pre-Tax Operating Income (Loss) |
|
| (400,578 | ) |
|
| (38,944 | ) |
|
| 45,903 |
|
Income Tax (Expense) Benefit (a) |
|
| 22,833 |
|
|
| 14,059 |
|
|
| (29,148 | ) |
Results of Operations for Oil and Gas Producing Activities |
| $ | (377,745 | ) |
| $ | (24,885 | ) |
| $ | 16,755 |
|
Share of Equity Method Investments (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Depletion, Depreciation, Amortization and Accretion |
| $ | 812 |
|
| $ | 805 |
|
| $ | 752 |
|
Total Costs |
|
| 812 |
|
|
| 805 |
|
|
| 752 |
|
Pre-Tax Operating Loss |
|
| (812 | ) |
|
| (805 | ) |
|
| (752 | ) |
Income Tax Benefit (a) |
|
| 46 |
|
|
| 291 |
|
|
| 478 |
|
Results of Operations for Oil and Gas Producing Activities |
| $ | (766 | ) |
| $ | (514 | ) |
| $ | (274 | ) |
Total Consolidated and Equity Method Investees Results of Operations for Oil and Gas Producing Activities |
| $ | (378,511 | ) |
| $ | (25,399 | ) |
| $ | 16,481 |
|
(a) | Computed using the effective rate for continuing operations for each period: 5.7% in 2015; 36.1% in 2014 and; 63.5% in 2013. |
23. | LITIGATION |
Illinois Basin EPA Consent Decree
In September 2006, the United States Department of Justice (“DOJ”), the United States Environmental Protection Agency (“EPA”) and the State of Illinois initiated an enforcement action against us seeking mandatory injunctive relief and potential civil penalties based on allegations that we (and various predecessor companies) were violating the Clean Air Act in connection with the release of hydrogen sulfide gas and volatile organic compounds (“VOC’s”) in the course of our oil producing operations near the towns of Bridgeport, Illinois and Petrolia, Illinois. In June 2007, we entered a consent decree to resolve the enforcement action. The consent decree required us to take certain remedial actions to reduce hydrogen sulfide and VOC emissions and monitor the same. The
117
consent decree did not require us to pay any civil fine or penalty, although it does provide for the possible imposition of specified daily fines and penalties for any violation of the terms and conditions of the consent decree.
In 2010, the EPA, DOJ and Illinois EPA approved revisions we proposed to a Directed Inspection and Maintenance Plan, which had been previously implemented by us pursuant to the terms of the consent decree. In 2014, in consultation with the EPA, DOJ and Illinois EPA, we implemented additional measures under the Directed Inspection and Maintenance Plan to reflect changes in hydrogen sulfide control monitoring and procedures. We are required under the terms of the consent decree to submit quarterly reports and to annually reassess the Directed Inspection and Maintenance Plan. There were no material changes to the Directed Inspection and Maintenance Plan in 2015 and we were compliant with all reporting requirements for the year.
Litigation Related to Proposed Oil and Gas Leases in Clearfield County, Pennsylvania
In October 2011, we were named as defendants in a proposed class action lawsuit filed in the Court of Common Pleas of Clearfield County, Pennsylvania (the “Cardinale case”). The named plaintiffs are two individuals who have sued on behalf of themselves and all persons who are alleged to be similarly situated. The complaint in the Cardinale case generally asserts that a binding contract to lease oil and gas interests was formed between the Company and each proposed class member when representatives of Western Land Services, Inc. (“Western”), a leasing agent that we engaged, presented a form of proposed oil and gas lease and an order for payment to each person in 2008, and each person signed the proposed oil and gas lease form and order for payment and delivered the documents to representatives of Western. We rejected these leases and never signed them on behalf of the Company. The plaintiffs seek a judgment declaring the rights of the parties with respect to those proposed leases, as well as damages and other relief as may be established by plaintiffs at trial, together with interest, costs, expenses and attorneys’ fees. We filed affirmative defenses and preliminary objections to the plaintiff’s claims, and the parties each made various responsive filings throughout the first quarter of 2012. In May 2012, the trial court dismissed the Cardinale case with prejudice on the grounds that there was no contract formed between us and the plaintiffs. The plaintiffs appealed the dismissal during the second half of 2012. In May 2013, the Superior Court reversed the decision of the Common Pleas Court and remanded the case for further proceedings.
In July 2012, while the Cardinale case was in the midst of the appeals process, counsel for the plaintiffs in the Cardinale case filed two additional lawsuits against us in the Court of Common Pleas of Clearfield County, Pennsylvania: one a proposed class action lawsuit with a different named plaintiff (the “Billotte case”) and another on behalf of a group of individually named plaintiffs (the “Meeker case”). The complaint for the Billotte case contained the same claims as those set forth in the Cardinale case. The Meeker case is not a class action, but the claims are similar to those in Cardinale and the plaintiffs would be included in a class under Cardinale and Billotte if one were certified. These two additional lawsuits were filed for procedural reasons in light of the dismissal of the Cardinale case and the pendency of the appeal. Proceedings in both the Billotte and Meeker cases were stayed pending the outcome of the appeal in the Cardinale case. When the Cardinale case was remanded, we agreed to consolidate the Billotte and Cardinale cases; the cases have proceeded as Cardinale. The Meeker case remains stayed, and has not been consolidated.
In June 2015, the trial court conducted a hearing on plaintiff’s motion for certification of a class in the Cardinale case. In July 2015, the trial court denied plaintiffs’ motion for class certification. Plaintiffs served notice of their appeal of that decision in August 2015 and filed the appeal in September 2015. We continue to vigorously defend against each of these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.
118
The following tables set forth unaudited financial information on a quarterly basis for each of the last two years.
REX ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
($ and Shares in Thousands Except per Share Data)
|
| 2015 |
| |||||||||||||
|
| March |
|
| June |
|
| September |
|
| December |
| ||||
Revenues |
| $ | 54,122 |
|
| $ | 45,772 |
|
| $ | 37,573 |
|
| $ | 34,526 |
|
Impairment Expense |
|
| 7,023 |
|
|
| 117,842 |
|
|
| 139,812 |
|
|
| 81,098 |
|
Other Costs and Expenses |
|
| 65,578 |
|
|
| 81,303 |
|
|
| 27,054 |
|
|
| 51,301 |
|
Net Loss From Continuing Operations |
|
| (18,479 | ) |
|
| (153,373 | ) |
|
| (129,293 | ) |
|
| (97,873 | ) |
Net Income (Loss) From Discontinued Operations, Net of Income Taxes |
|
| 1,962 |
|
|
| 1,570 |
|
|
| 34,617 |
|
|
| (164 | ) |
Net Loss |
|
| (16,517 | ) |
|
| (151,803 | ) |
|
| (94,676 | ) |
|
| (98,037 | ) |
Net Income (Loss) Attributable to Noncontrolling Interests |
|
| 1,297 |
|
|
| 949 |
|
|
| (1 | ) |
|
| — |
|
Net Loss Attributable to Rex Energy |
|
| (17,814 | ) |
|
| (152,752 | ) |
|
| (94,675 | ) |
|
| (98,037 | ) |
Preferred Stock Dividends |
|
| 2,415 |
|
|
| 2,415 |
|
|
| 2,415 |
|
|
| 2,415 |
|
Net Loss Attributable to Common Shareholders |
| $ | (20,229 | ) |
| $ | (155,167 | ) |
| $ | (97,090 | ) |
| $ | (100,452 | ) |
Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic — Continuing Operations |
| $ | (0.38 | ) |
| $ | (2.88 | ) |
| $ | (2.44 | ) |
| $ | (1.85 | ) |
Basic — Discontinued Operations |
|
| 0.01 |
|
|
| 0.01 |
|
|
| 0.64 |
|
|
| — |
|
Basic — Net Loss |
| $ | (0.37 | ) |
| $ | (2.87 | ) |
| $ | (1.80 | ) |
| $ | (1.85 | ) |
Basic — Weighted Average Shares Outstanding |
|
| 54,370 |
|
|
| 54,118 |
|
|
| 53,936 |
|
|
| 54,342 |
|
Diluted — Continuing Operations |
| $ | (0.38 | ) |
| $ | (2.88 | ) |
| $ | (2.44 | ) |
| $ | (1.85 | ) |
Diluted — Discontinued Operations |
|
| 0.01 |
|
|
| 0.01 |
|
|
| 0.64 |
|
|
| — |
|
Diluted — Net Loss |
| $ | (0.37 | ) |
| $ | (2.87 | ) |
| $ | (1.80 | ) |
| $ | (1.85 | ) |
Diluted — Weighted Average Shares Outstanding |
|
| 54,370 |
|
|
| 54,118 |
|
|
| 53,936 |
|
|
| 54,342 |
|
|
| 2014 |
| |||||||||||||
|
| March |
|
| June |
|
| September |
|
| December |
| ||||
Revenues |
| $ | 81,343 |
|
| $ | 72,933 |
|
| $ | 73,466 |
|
| $ | 70,245 |
|
Impairment Expense |
|
| 25 |
|
|
| 16 |
|
|
| 1 |
|
|
| 132,576 |
|
Other Costs and Expenses |
|
| 72,562 |
|
|
| 65,274 |
|
|
| 67,846 |
|
|
| 7,337 |
|
Net Income (Loss) From Continuing Operations |
|
| 8,756 |
|
|
| 7,643 |
|
|
| 5,619 |
|
|
| (69,668 | ) |
Net Income From Discontinued Operations, Net of Income Taxes |
|
| 1,681 |
|
|
| 1,312 |
|
|
| 970 |
|
|
| 1,037 |
|
Net Income (Loss) |
|
| 10,437 |
|
|
| 8,955 |
|
|
| 6,589 |
|
|
| (68,631 | ) |
Net Income Attributable to Noncontrolling Interests |
|
| 1,569 |
|
|
| 877 |
|
|
| 895 |
|
|
| 698 |
|
Net Income (Loss) Attributable to Rex Energy |
| $ | 8,868 |
|
| $ | 8,078 |
|
| $ | 5,694 |
|
| $ | (69,329 | ) |
Preferred Stock Dividends |
|
| - |
|
|
| - |
|
|
| - |
|
|
| 2,335 |
|
Net Income (Loss) Attributable to Common Shareholders |
| $ | 8,868 |
|
| $ | 8,078 |
|
| $ | 5,694 |
|
| $ | (71,664 | ) |
Income (Loss) per Common Share Attributable to Rex Energy Common Shareholders: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic — Continuing Operations |
| $ | 0.17 |
|
| $ | 0.14 |
|
| $ | 0.11 |
|
| $ | (1.35 | ) |
Basic — Discontinued Operations |
|
| - |
|
|
| 0.01 |
|
|
| — |
|
|
| - |
|
Basic — Net Income (Loss) |
| $ | 0.17 |
|
| $ | 0.15 |
|
| $ | 0.11 |
|
| $ | (1.35 | ) |
Basic — Weighted Average Shares Outstanding |
|
| 52,984 |
|
|
| 53,164 |
|
|
| 53,214 |
|
|
| 53,261 |
|
Diluted — Continuing Operations |
| $ | 0.17 |
|
| $ | 0.14 |
|
| $ | 0.10 |
|
| $ | (1.35 | ) |
Diluted — Discontinued Operations |
|
| - |
|
|
| 0.01 |
|
|
| — |
|
|
| - |
|
Diluted — Net Income (Loss) |
| $ | 0.17 |
|
| $ | 0.15 |
|
| $ | 0.10 |
|
| $ | (1.35 | ) |
Diluted — Weighted Average Shares Outstanding |
|
| 53,503 |
|
|
| 53,509 |
|
|
| 57,991 |
|
|
| 53,261 |
|
119
25. | CONDENSED CONSOLIDATING FINANCIAL INFORMATION |
As of December 31, 2015, we had $675.0 million of outstanding Senior Notes, as shown in Note 9, Long-Term Debt, to our Consolidated Financial Statements. The Senior Notes are guaranteed by certain of our wholly-owned subsidiaries, or guarantor subsidiaries. Unless otherwise noted below, each of the following guarantor subsidiaries are wholly-owned by Rex Energy Corporation and have provided guarantees of the Senior Notes that are joint and several and full and unconditional as of December 31, 2015:
| â—Ź | Rex Energy I, LLC |
| â—Ź | Rex Energy Operating Corporation |
| â—Ź | Rex Energy IV, LLC |
| â—Ź | PennTex Resources Illinois, Inc. |
| â—Ź | R.E. Gas Development, LLC |
The non-guarantor subsidiaries include certain consolidated subsidiaries, including Water Solutions, R.E. Disposal, LLC, Rex Energy Marketing, LLC and R.E. Ventures, LLC. We derive much of our business through and derive much of our income through our subsidiaries. Therefore, our ability to make required payments with respect to indebtedness and other obligations depends on the financial results and condition of our subsidiaries and our ability to receive funds from our subsidiaries. As of December 31, 2015, there were no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to us. There may be restrictions for certain non-guarantor subsidiaries.
The following financial statements present condensed consolidating financial data for (i) Rex Energy Corporation, the issuer of the notes, (ii) the combined Guarantors, (iii) the combined other subsidiaries of the Company that did not guarantee the Notes, and (iv) eliminations necessary to arrive at our consolidated financial statements, which include condensed consolidated balance sheets as of December 31, 2015 and 2014, and the condensed consolidating statements of operations and condensed consolidating statements of cash flows for each of the years in the three-year period ended December 31, 2015.
120
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
FOR THE YEAR ENDED DECEMBER 31, 2015
($ in Thousands, Except Share and Per Share Data)
|
| Guarantor Subsidiaries |
|
| Non-Guarantor Subsidiaries |
|
| Rex Energy Corporation (Note Issuer) |
|
| Eliminations |
|
| Consolidated Balance |
| |||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
| $ | 1,089 |
|
| $ | — |
|
| $ | 2 |
|
| $ | — |
|
| $ | 1,091 |
|
Accounts Receivable |
|
| 19,423 |
|
|
| 11 |
|
|
| 49 |
|
|
| — |
|
|
| 19,483 |
|
Taxes Receivable |
|
| — |
|
|
| — |
|
|
| 18 |
|
|
| — |
|
|
| 18 |
|
Short-Term Derivative Instruments |
|
| 34,260 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 34,260 |
|
Inventory, Prepaid Expenses and Other |
|
| 3,804 |
|
|
| — |
|
|
| 25 |
|
|
| — |
|
|
| 3,829 |
|
Total Current Assets |
|
| 58,576 |
|
|
| 11 |
|
|
| 94 |
|
|
| — |
|
|
| 58,681 |
|
Property and Equipment (Successful Efforts Method) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Evaluated Oil and Gas Properties |
|
| 1,245,626 |
|
|
| 774 |
|
|
| — |
|
|
| (6,970 | ) |
|
| 1,239,430 |
|
Unevaluated Oil and Gas Properties |
|
| 262,992 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 262,992 |
|
Other Property and Equipment |
|
| 39,217 |
|
|
| 895 |
|
|
| — |
|
|
| — |
|
|
| 40,112 |
|
Wells and Facilities in Progress |
|
| 144,587 |
|
|
| 239 |
|
|
| — |
|
|
| (270 | ) |
|
| 144,556 |
|
Pipelines |
|
| 16,161 |
|
|
| — |
|
|
| — |
|
|
| (2,137 | ) |
|
| 14,024 |
|
Total Property and Equipment |
|
| 1,708,583 |
|
|
| 1,908 |
|
|
| — |
|
|
| (9,377 | ) |
|
| 1,701,114 |
|
Less: Accumulated Depreciation, Depletion and Amortization |
|
| (702,537 | ) |
|
| (880 | ) |
|
| — |
|
|
| 3,518 |
|
|
| (699,899 | ) |
Net Property and Equipment |
|
| 1,006,046 |
|
|
| 1,028 |
|
|
| — |
|
|
| (5,859 | ) |
|
| 1,001,215 |
|
Deferred Financing Costs and Other Assets—Net |
|
| 2,501 |
|
|
| — |
|
|
| 14,043 |
|
|
| — |
|
|
| 16,544 |
|
Equity Method Investments |
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
Long-Term Deferred Tax Asset |
|
| — |
|
|
| — |
|
|
| 12,532 |
|
|
| — |
|
|
| 12,532 |
|
Intercompany Receivables |
|
| — |
|
|
| — |
|
|
| 1,070,548 |
|
|
| (1,070,548 | ) |
|
| — |
|
Investment in Subsidiaries – Net |
|
| (1,907 | ) |
|
| — |
|
|
| 243,331 |
|
|
| (241,424 | ) |
|
| — |
|
Long-Term Derivative Instruments |
|
| 9,534 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 9,534 |
|
Total Assets |
| $ | 1,074,750 |
|
| $ | 1,039 |
|
| $ | 1,340,548 |
|
| $ | (1,317,831 | ) |
| $ | 1,098,506 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Payable |
| $ | 37,874 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 37,874 |
|
Current Maturities of Long-Term Debt |
|
| 590 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 590 |
|
Accrued Liabilities |
|
| 32,601 |
|
|
| — |
|
|
| 11,725 |
|
|
| — |
|
|
| 44,326 |
|
Short-Term Derivative Instruments |
|
| 2,486 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,486 |
|
Current Deferred Tax Liability |
|
| — |
|
|
| — |
|
|
| 12,532 |
|
|
| — |
|
|
| 12,532 |
|
Total Current Liabilities |
|
| 73,551 |
|
|
| — |
|
|
| 24,257 |
|
|
| — |
|
|
| 97,808 |
|
8.875% Senior Notes Due 2020 |
|
| — |
|
|
| — |
|
|
| 350,000 |
|
|
| — |
|
|
| 350,000 |
|
6.25% Senior Notes Due 2022 |
|
| — |
|
|
| — |
|
|
| 325,000 |
|
|
| — |
|
|
| 325,000 |
|
Premium on Senior Notes – Net |
|
| — |
|
|
| — |
|
|
| 2,344 |
|
|
| — |
|
|
| 2,344 |
|
Senior Secured Line of Credit and Other Long-Term Debt |
|
| 28 |
|
|
| — |
|
|
| 111,500 |
|
|
| — |
|
|
| 111,528 |
|
Long-Term Derivative Instruments |
|
| 5,556 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 5,556 |
|
Other Deposits and Liabilities |
|
| 3,156 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 3,156 |
|
Future Abandonment Cost |
|
| 42,443 |
|
|
| 440 |
|
|
| — |
|
|
| — |
|
|
| 42,883 |
|
Intercompany Payables |
|
| 1,070,096 |
|
|
| 452 |
|
|
| — |
|
|
| (1,070,548 | ) |
|
| — |
|
Total Liabilities |
|
| 1,194,830 |
|
|
| 892 |
|
|
| 813,101 |
|
|
| (1,070,548 | ) |
|
| 938,275 |
|
Stockholders’ Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Common Stock |
|
| — |
|
|
| — |
|
|
| 54 |
|
|
| — |
|
|
| 54 |
|
Additional Paid-In Capital |
|
| 177,143 |
|
|
| — |
|
|
| 619,777 |
|
|
| (173,057 | ) |
|
| 623,863 |
|
Accumulated Earnings (Deficit) |
|
| (297,223 | ) |
|
| 147 |
|
|
| (92,385 | ) |
|
| (74,226 | ) |
|
| (463,687 | ) |
Rex Energy Stockholders’ Equity |
|
| (120,080 | ) |
|
| 147 |
|
|
| 527,447 |
|
|
| (247,283 | ) |
|
| 160,231 |
|
121
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| — |
| |
Total Stockholders’ Equity |
|
| (120,080 | ) |
|
| 147 |
|
|
| 527,447 |
|
|
| (247,283 | ) |
|
| 160,231 |
|
Total Liabilities and Stockholders’ Equity |
| $ | 1,074,750 |
|
| $ | 1,039 |
|
| $ | 1,340,548 |
|
| $ | (1,317,831 | ) |
| $ | 1,098,506 |
|
122
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2015
($ in Thousands)
|
| Guarantor Subsidiaries |
|
| Non-Guarantor Subsidiaries |
|
| Rex Energy Corporation (Note Issuer) |
|
| Eliminations |
|
| Consolidated Balance |
| |||||
OPERATING REVENUE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Natural Gas and NGL Sales |
| $ | 171,440 |
|
| $ | 511 |
|
| $ | — |
|
| $ | — |
|
| $ | 171,951 |
|
Other Revenue |
|
| 42 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 42 |
|
TOTAL OPERATING REVENUE |
|
| 171,482 |
|
|
| 511 |
|
|
| — |
|
|
| — |
|
|
| 171,993 |
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
|
| 118,825 |
|
|
| 174 |
|
|
| — |
|
|
| — |
|
|
| 118,999 |
|
General and Administrative Expense |
|
| 22,879 |
|
|
| 52 |
|
|
| 6,504 |
|
|
| — |
|
|
| 29,435 |
|
Gain on Disposal of Asset |
|
| (477 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (477 | ) |
Impairment Expense |
|
| 345,892 |
|
|
| 1,396 |
|
|
| — |
|
|
| (1,513 | ) |
|
| 345,775 |
|
Exploration Expense |
|
| 2,879 |
|
|
| 137 |
|
|
| — |
|
|
| (5 | ) |
|
| 3,011 |
|
Depreciation, Depletion, Amortization and Accretion |
|
| 105,556 |
|
|
| 157 |
|
|
| — |
|
|
| (969 | ) |
|
| 104,744 |
|
Other Operating Expense |
|
| 5,595 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 5,595 |
|
TOTAL OPERATING EXPENSES |
|
| 601,149 |
|
|
| 1,916 |
|
|
| 6,504 |
|
|
| (2,487 | ) |
|
| 607,082 |
|
INCOME (LOSS) FROM OPERATIONS |
|
| (429,667 | ) |
|
| (1,405 | ) |
|
| (6,504 | ) |
|
| 2,487 |
|
|
| (435,089 | ) |
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
| (271 | ) |
|
| — |
|
|
| (47,535 | ) |
|
| — |
|
|
| (47,806 | ) |
Gain on Derivatives, Net |
|
| 59,242 |
|
|
| — |
|
|
| 934 |
|
|
| — |
|
|
| 60,176 |
|
Other Expense |
|
| (115 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (115 | ) |
Loss From Equity Method Investments |
|
| (411 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (411 | ) |
Income (Loss) From Equity in Consolidated Subsidiaries |
|
| (1,324 | ) |
|
| 1,324 |
|
|
| (313,198 | ) |
|
| 313,198 |
|
|
| — |
|
TOTAL OTHER INCOME (EXPENSE) |
|
| 57,121 |
|
|
| 1,324 |
|
|
| (359,799 | ) |
|
| 313,198 |
|
|
| 11,844 |
|
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX |
|
| (372,546 | ) |
|
| (81 | ) |
|
| (366,303 | ) |
|
| 315,685 |
|
|
| (423,245 | ) |
Income Tax Benefit |
|
| 21,122 |
|
|
| 81 |
|
|
| 3,024 |
|
|
| — |
|
|
| 24,227 |
|
NET INCOME (LOSS) FROM CONTINUING OPERATIONS |
|
| (351,424 | ) |
|
| — |
|
|
| (363,279 | ) |
|
| 315,685 |
|
|
| (399,018 | ) |
Income (Loss) From Discontinued Operations, Net of Income Tax |
|
| — |
|
|
| 3,908 |
|
|
| 35,269 |
|
|
| (1,192 | ) |
|
| 37,985 |
|
NET INCOME (LOSS) |
|
| (351,424 | ) |
|
| 3,908 |
|
|
| (328,010 | ) |
|
| 314,493 |
|
|
| (361,033 | ) |
Net Income Attributable to Noncontrolling Interests of Discontinued Operations |
|
| — |
|
|
| 2,245 |
|
|
| — |
|
|
| — |
|
|
| 2,245 |
|
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY |
| $ | (351,424 | ) |
| $ | 1,663 |
|
| $ | (328,010 | ) |
| $ | 314,493 |
|
| $ | (363,278 | ) |
Preferred Stock Dividends |
|
| — |
|
|
| — |
|
|
| 9,660 |
|
|
| — |
|
|
| 9,660 |
|
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS |
| $ | (351,424 | ) |
| $ | 1,663 |
|
| $ | (337,670 | ) |
| $ | 314,493 |
|
| $ | (372,938 | ) |
123
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2015
($ in Thousands)
|
| Guarantor Subsidiaries |
|
| Non-Guarantor Subsidiaries |
|
| Rex Energy Corporation (Note Issuer) |
|
| Eliminations |
|
| Consolidated Balance |
| |||||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
| $ | (351,424 | ) |
| $ | 3,908 |
|
| $ | (328,010 | ) |
| $ | 314,493 |
|
| $ | (361,033 | ) |
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on Equity Method Investments |
|
| 411 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 411 |
|
Non-Cash Expenses (Income) |
|
| (201 | ) |
|
| (334 | ) |
|
| 8,184 |
|
|
| — |
|
|
| 7,649 |
|
Depreciation, Depletion, Amortization and Accretion |
|
| 105,555 |
|
|
| 3,230 |
|
|
| — |
|
|
| (3,963 | ) |
|
| 104,822 |
|
Gain on Derivatives |
|
| (59,242 | ) |
|
| — |
|
|
| (934 | ) |
|
| — |
|
|
| (60,176 | ) |
Cash Settlements of Derivatives |
|
| 54,859 |
|
|
| — |
|
|
| 934 |
|
|
| — |
|
|
| 55,793 |
|
Dry Hole Expense |
|
| 199 |
|
|
| 136 |
|
|
| — |
|
|
| (5 | ) |
|
| 330 |
|
Gain on Sale of Asset |
|
| (477 | ) |
|
| (44 | ) |
|
| — |
|
|
| — |
|
|
| (521 | ) |
Gain on Sale of Water Solutions |
|
| — |
|
|
| — |
|
|
| (57,778 | ) |
|
| — |
|
|
| (57,778 | ) |
Impairment Expense |
|
| 345,892 |
|
|
| 1,396 |
|
|
| 345,892 |
|
|
| (347,405 | ) |
|
| 345,775 |
|
Changes in operating assets and liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Receivable |
|
| 24,240 |
|
|
| (453 | ) |
|
| 429 |
|
|
| (2,537 | ) |
|
| 21,679 |
|
Inventory, Prepaid Expenses and Other Assets |
|
| (431 | ) |
|
| (142 | ) |
|
| 5 |
|
|
| — |
|
|
| (568 | ) |
Accounts Payable and Accrued Liabilities |
|
| (20,008 | ) |
|
| (4,969 | ) |
|
| (515 | ) |
|
| 2,537 |
|
|
| (22,955 | ) |
Other Assets and Liabilities |
|
| (2,497 | ) |
|
| (73 | ) |
|
| 27 |
|
|
| — |
|
|
| (2,543 | ) |
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES |
|
| 96,876 |
|
|
| 2,655 |
|
|
| (31,766 | ) |
|
| (36,880) |
|
|
| 30,885 |
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany Loans to Subsidiaries |
|
| 103,212 |
|
|
| (3,362 | ) |
|
| (135,566) |
|
|
| 35,716 |
|
|
| — |
|
Proceeds from Joint Venture Acreage Management |
|
| 58 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 58 |
|
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets |
|
| 9,766 |
|
|
| 560 |
|
|
| 66,900 |
|
|
| — |
|
|
| 77,226 |
|
Proceeds from Joint Venture |
|
| 16,611 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 16,611 |
|
Acquisitions of Undeveloped Acreage |
|
| (27,963 | ) |
|
| (279 | ) |
|
| — |
|
|
| — |
|
|
| (28,242 | ) |
Capital Expenditures for Development of Oil and Gas Properties and Equipment |
|
| (214,450 | ) |
|
| (7,813 | ) |
|
| — |
|
|
| 1,164 |
|
|
| (221,099 | ) |
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES |
|
| (112,766 | ) |
|
| (10,894 | ) |
|
| (68,666) |
|
|
| 36,880 |
|
|
| (155,446 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from Long-Term Debt and Lines of Credit |
|
| — |
|
|
| 35,814 |
|
|
| 193,500 |
|
|
| — |
|
|
| 229,314 |
|
Repayments of Long-Term Debt and Lines of Credit |
|
| — |
|
|
| (26,335 | ) |
|
| (82,000 | ) |
|
| — |
|
|
| (108,335 | ) |
Repayments of Loans and Other Notes Payable |
|
| (999 | ) |
|
| (520 | ) |
|
| — |
|
|
| — |
|
|
| (1,519 | ) |
Debt Issuance Costs |
|
| — |
|
|
| (3 | ) |
|
| (1,411 | ) |
|
| — |
|
|
| (1,414 | ) |
Distributions by the Partners of Consolidated Subsidiary |
|
| — |
|
|
| (830 | ) |
|
| — |
|
|
| — |
|
|
| (830 | ) |
Dividends Paid on Preferred Stock |
|
| — |
|
|
| — |
|
|
| (9,660 | ) |
|
| — |
|
|
| (9,660 | ) |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES |
|
| (999 | ) |
|
| 8,126 |
|
|
| 100,429 |
|
|
| — |
|
|
| 107,556 |
|
NET (DECREASE) IN CASH |
|
| (16,889 | ) |
|
| (113 | ) |
|
| (3 | ) |
|
| — |
|
|
| (17,005 | ) |
CASH – BEGINNING |
|
| 17,978 |
|
|
| 113 |
|
|
| 5 |
|
|
| — |
|
|
| 18,096 |
|
CASH - ENDING |
| $ | 1,089 |
|
| $ | — |
|
| $ | 2 |
|
| $ | — |
|
| $ | 1,091 |
|
124
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEETS
FOR THE YEAR ENDED DECEMBER 31, 2014
($ in Thousands, Except Share and Per Share Data)
|
| Guarantor Subsidiaries |
|
| Non-Guarantor Subsidiaries |
|
| Rex Energy Corporation (Note Issuer) |
|
| Eliminations |
|
| Consolidated Balance |
| |||||
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and Cash Equivalents |
| $ | 17,978 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 17,978 |
|
Accounts Receivable |
|
| 43,726 |
|
|
| 210 |
|
|
| — |
|
|
| — |
|
|
| 43,936 |
|
Taxes Receivable |
|
| — |
|
|
| — |
|
|
| 504 |
|
|
| — |
|
|
| 504 |
|
Short-Term Derivative Instruments |
|
| 29,265 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 29,265 |
|
Assets Held For Sale |
|
| — |
|
|
| 36,794 |
|
|
| — |
|
|
| (2,537 | ) |
|
| 34,257 |
|
Inventory, Prepaid Expenses and Other |
|
| 3,374 |
|
|
| — |
|
|
| 29 |
|
|
| — |
|
|
| 3,403 |
|
Total Current Assets |
|
| 94,343 |
|
|
| 37,004 |
|
|
| 533 |
|
|
| (2,537 | ) |
|
| 129,343 |
|
Property and Equipment (Successful Efforts Method) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Evaluated Oil and Gas Properties |
|
| 1,084,332 |
|
|
| 467 |
|
|
| — |
|
|
| (5,760 | ) |
|
| 1,079,039 |
|
Unevaluated Oil and Gas Properties |
|
| 321,708 |
|
|
| 705 |
|
|
| — |
|
|
| — |
|
|
| 322,413 |
|
Other Property and Equipment |
|
| 45,466 |
|
|
| 895 |
|
|
| — |
|
|
| — |
|
|
| 46,361 |
|
Wells and Facilities in Progress |
|
| 127,759 |
|
|
| 456 |
|
|
| — |
|
|
| (560 | ) |
|
| 127,655 |
|
Pipelines |
|
| 17,555 |
|
|
| — |
|
|
| — |
|
|
| (1,898 | ) |
|
| 15,657 |
|
Total Property and Equipment |
|
| 1,596,820 |
|
|
| 2,523 |
|
|
| — |
|
|
| (8,218 | ) |
|
| 1,591,125 |
|
Less: Accumulated Depreciation, Depletion and Amortization |
|
| (367,224 | ) |
|
| (730 | ) |
|
| — |
|
|
| 1,037 |
|
|
| (366,917 | ) |
Net Property and Equipment |
|
| 1,229,596 |
|
|
| 1,793 |
|
|
| — |
|
|
| (7,181 | ) |
|
| 1,224,208 |
|
Deferred Financing Costs and Other Assets—Net |
|
| 2,421 |
|
|
| — |
|
|
| 14,649 |
|
|
| — |
|
|
| 17,070 |
|
Equity Method Investments |
|
| 17,895 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 17,895 |
|
Long-Term Deferred Tax Asset |
|
| — |
|
|
| — |
|
|
| 8,301 |
|
|
| — |
|
|
| 8,301 |
|
Intercompany Receivables |
|
| — |
|
|
| — |
|
|
| 951,025 |
|
|
| (951,025 | ) |
|
| — |
|
Investment in Subsidiaries – Net |
|
| 4,161 |
|
|
| 1,541 |
|
|
| 258,448 |
|
|
| (264,150 | ) |
|
| — |
|
Long-Term Derivative Instruments |
|
| 4,904 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 4,904 |
|
Total Assets |
| $ | 1,353,320 |
|
| $ | 40,338 |
|
| $ | 1,232,956 |
|
| $ | (1,224,893 | ) |
| $ | 1,401,721 |
|
LIABILITIES AND EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Payable |
| $ | 55,877 |
|
| $ | — |
|
| $ | — |
|
| $ | (2,537 | ) |
| $ | 53,340 |
|
Current Maturities of Long-Term Debt |
|
| 1,176 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 1,176 |
|
Accrued Liabilities |
|
| 46,783 |
|
|
| 571 |
|
|
| 12,124 |
|
|
| — |
|
|
| 59,478 |
|
Short-Term Derivative Instruments |
|
| 421 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 421 |
|
Long-Term Deferred Tax Liability |
|
| — |
|
|
| — |
|
|
| 8,301 |
|
|
| — |
|
|
| 8,301 |
|
Liabilities Related to Assets Held For Sale |
|
| — |
|
|
| 25,115 |
|
|
| — |
|
|
| — |
|
|
| 25,115 |
|
Total Current Liabilities |
|
| 104,257 |
|
|
| 25,686 |
|
|
| 20,425 |
|
|
| (2,537 | ) |
|
| 147,831 |
|
8.875% Senior Notes Due 2020 |
|
| — |
|
|
| — |
|
|
| 350,000 |
|
|
| — |
|
|
| 350,000 |
|
6.25% Senior Notes Due 2022 |
|
|
|
|
|
|
|
|
|
| 325,000 |
|
|
|
|
|
|
| 325,000 |
|
Premium (Discount) on Senior Notes – Net |
|
| — |
|
|
| — |
|
|
| 2,725 |
|
|
| — |
|
|
| 2,725 |
|
Senior Secured Line of Credit and Other Long-Term Debt |
|
| 251 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 251 |
|
Long-Term Derivative Instruments |
|
| 2,377 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,377 |
|
Other Deposits and Liabilities |
|
| 4,018 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 4,018 |
|
Future Abandonment Cost |
|
| 38,097 |
|
|
| 49 |
|
|
| — |
|
|
| — |
|
|
| 38,146 |
|
Intercompany Payables |
|
| 947,114 |
|
|
| 3,911 |
|
|
| — |
|
|
| (951,025 | ) |
|
| — |
|
Total Liabilities |
|
| 1,096,114 |
|
|
| 29,646 |
|
|
| 698,150 |
|
|
| (953,562 | ) |
|
| 870,348 |
|
Stockholders’ Equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred Stock |
|
| — |
|
|
| — |
|
|
| 1 |
|
|
| — |
|
|
| 1 |
|
Common Stock |
|
| — |
|
|
| — |
|
|
| 54 |
|
|
| — |
|
|
| 54 |
|
Additional Paid-In Capital |
|
| 177,144 |
|
|
| 79,743 |
|
|
| 617,826 |
|
|
| (256,887 | ) |
|
| 617,826 |
|
125
|
| 80,062 |
|
|
| (69,253 | ) |
|
| (83,075 | ) |
|
| (18,483 | ) |
|
| (90,749 | ) | |
Rex Energy Stockholders’ Equity |
|
| 257,206 |
|
|
| 10,490 |
|
|
| 534,806 |
|
|
| (275,370 | ) |
|
| 527,132 |
|
Noncontrolling Interests |
|
| — |
|
|
| 202 |
|
|
| — |
|
|
| 4,039 |
|
|
| 4,241 |
|
Total Stockholders’ Equity |
|
| 257,206 |
|
|
| 10,692 |
|
|
| 534,806 |
|
|
| (271,331 | ) |
|
| 531,373 |
|
Total Liabilities and Stockholders’ Equity |
| $ | 1,353,320 |
|
| $ | 40,338 |
|
| $ | 1,232,956 |
|
| $ | (1,224,893 | ) |
| $ | 1,401,721 |
|
126
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2014
($ in Thousands)
|
| Guarantor Subsidiaries |
|
| Non-Guarantor Subsidiaries |
|
| Rex Energy Corporation (Note Issuer) |
|
| Eliminations |
|
| Consolidated Balance |
| |||||
OPERATING REVENUE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Natural Gas and NGL Sales |
| $ | 297,710 |
|
| $ | 159 |
|
| $ | — |
|
| $ | — |
|
| $ | 297,869 |
|
Other Revenue |
|
| 118 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 118 |
|
TOTAL OPERATING REVENUE |
|
| 297,828 |
|
|
| 159 |
|
|
| — |
|
|
| — |
|
|
| 297,987 |
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
|
| 100,261 |
|
|
| 21 |
|
|
| — |
|
|
| — |
|
|
| 100,282 |
|
General and Administrative Expense |
|
| 30,317 |
|
|
| 83 |
|
|
| 5,737 |
|
|
| — |
|
|
| 36,137 |
|
Loss on Disposal of Asset |
|
| 644 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 644 |
|
Impairment Expense |
|
| 126,662 |
|
|
| 5,956 |
|
|
| — |
|
|
| — |
|
|
| 132,618 |
|
Exploration Expense |
|
| 9,165 |
|
|
| 281 |
|
|
| — |
|
|
| — |
|
|
| 9,446 |
|
Depreciation, Depletion, Amortization and Accretion |
|
| 94,643 |
|
|
| 513 |
|
|
| — |
|
|
| (689 | ) |
|
| 94,467 |
|
Other Operating Expense |
|
| 134 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 134 |
|
TOTAL OPERATING EXPENSES |
|
| 361,826 |
|
|
| 6,854 |
|
|
| 5,737 |
|
|
| (689 | ) |
|
| 373,728 |
|
INCOME (LOSS) FROM OPERATIONS |
|
| (63,998 | ) |
|
| (6,695 | ) |
|
| (5,737 | ) |
|
| 689 |
|
|
| (75,741 | ) |
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
| (142 | ) |
|
| — |
|
|
| (36,835 | ) |
|
| — |
|
|
| (36,977 | ) |
Gain on Derivatives, Net |
|
| 37,359 |
|
|
| — |
|
|
| 1,517 |
|
|
| — |
|
|
| 38,876 |
|
Other Income (Expense) |
|
| 90 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 90 |
|
Loss From Equity Method Investments |
|
| (813 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (813 | ) |
Income (Loss) From Equity in Consolidated Subsidiaries |
|
| (4,278 | ) |
|
| 4,278 |
|
|
| (20,204 | ) |
|
| 20,204 |
|
|
| — |
|
TOTAL OTHER INCOME (EXPENSE) |
|
| 32,216 |
|
|
| 4,278 |
|
|
| (55,522 | ) |
|
| 20,204 |
|
|
| 1,176 |
|
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX |
|
| (31,782 | ) |
|
| (2,417 | ) |
|
| (61,259 | ) |
|
| 20,893 |
|
|
| (74,565 | ) |
Income Tax (Expense) Benefit |
|
| 9,928 |
|
|
| 2,417 |
|
|
| 14,570 |
|
|
| — |
|
|
| 26,915 |
|
NET INCOME (LOSS) FROM CONTINUING OPERATIONS |
|
| (21,854 | ) |
|
| - |
|
|
| (46,689 | ) |
|
| 20,893 |
|
|
| (47,650 | ) |
Income From Discontinued Operations, Net of Income Taxes |
|
| — |
|
|
| 9,330 |
|
|
| — |
|
|
| (4,330 | ) |
|
| 5,000 |
|
NET INCOME (LOSS) |
|
| (21,854 | ) |
|
| 9,330 |
|
|
| (46,689 | ) |
|
| 16,563 |
|
|
| (42,650 | ) |
Net Income Attributable to Noncontrolling Interests of Discontinued Operations |
|
| — |
|
|
| 4,039 |
|
|
| — |
|
|
| — |
|
|
| 4,039 |
|
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY |
| $ | (21,854 | ) |
| $ | 5,291 |
|
| $ | (46,689 | ) |
| $ | 16,563 |
|
| $ | (46,689 | ) |
127
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2014
($ in Thousands)
|
| Guarantor Subsidiaries |
|
| Non-Guarantor Subsidiaries |
|
| Rex Energy Corporation (Note Issuer) |
|
| Eliminations |
|
| Consolidated Balance |
| |||||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
| $ | (21,854 | ) |
| $ | 9,330 |
|
| $ | (46,689 | ) |
| $ | 16,563 |
|
| $ | (42,650 | ) |
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on Equity Method Investments |
|
| 813 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 813 |
|
Non-Cash Expenses (Income) |
|
| (273 | ) |
|
| 278 |
|
|
| 6,784 |
|
|
| — |
|
|
| 6,789 |
|
Depreciation, Depletion, Amortization and Accretion |
|
| 94,643 |
|
|
| 4,217 |
|
|
| — |
|
|
| (689 | ) |
|
| 98,171 |
|
Deferred Income Tax Benefit |
|
| (9,928 | ) |
|
| (1,649 | ) |
|
| (14,415 | ) |
|
| — |
|
|
| (25,992 | ) |
Gain on Derivatives |
|
| (37,359 | ) |
|
| — |
|
|
| (1,517 | ) |
|
| — |
|
|
| (38,876 | ) |
Cash Settlements of Derivatives |
|
| 5,969 |
|
|
| — |
|
|
| 1,312 |
|
|
| — |
|
|
| 7,281 |
|
Dry Hole Expense |
|
| 3,797 |
|
|
| 267 |
|
|
| — |
|
|
| — |
|
|
| 4,064 |
|
(Gain) Loss on Sale of Asset |
|
| 644 |
|
|
| (55 | ) |
|
| — |
|
|
| — |
|
|
| 589 |
|
Impairment Expense |
|
| 126,662 |
|
|
| 6,022 |
|
|
| — |
|
|
| — |
|
|
| 132,684 |
|
Changes in operating assets and liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Receivable |
|
| (11,450 | ) |
|
| (6,090 | ) |
|
| 4,686 |
|
|
| (766 | ) |
|
| (13,620 | ) |
Inventory, Prepaid Expenses and Other Assets |
|
| (1,283 | ) |
|
| (74 | ) |
|
| (2 | ) |
|
| — |
|
|
| (1,359 | ) |
Accounts Payable and Accrued Liabilities |
|
| 23,768 |
|
|
| 3,488 |
|
|
| 9,252 |
|
|
| 766 |
|
|
| 37,274 |
|
Other Assets and Liabilities |
|
| (2,127 | ) |
|
| (335 | ) |
|
| - |
|
|
| — |
|
|
| (2,462 | ) |
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES |
|
| 172,022 |
|
|
| 15,399 |
|
|
| (40,589 | ) |
|
| 15,874 |
|
|
| 162,706 |
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany Loans to Subsidiaries |
|
| 397,382 |
|
|
| (5,412 | ) |
|
| (371,768 | ) |
|
| (20,202 | ) |
|
| — |
|
Proceeds from Joint Venture Acreage Management |
|
| 263 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 263 |
|
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets |
|
| 254 |
|
|
| 292 |
|
|
| — |
|
|
| — |
|
|
| 546 |
|
Acquisitions of Undeveloped Acreage |
|
| (168,713 | ) |
|
| (710 | ) |
|
| — |
|
|
| — |
|
|
| (169,423 | ) |
Capital Expenditures for Development of Oil and Gas Properties and Equipment |
|
| (382,889 | ) |
|
| (12,861 | ) |
|
| — |
|
|
| 4,328 |
|
|
| (391,422 | ) |
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES |
|
| (153,703 | ) |
|
| (18,691 | ) |
|
| (371,768 | ) |
|
| (15,874 | ) |
|
| (560,036 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from Long-Term Debt and Lines of Credit |
|
| — |
|
|
| 38,895 |
|
|
| 171,000 |
|
|
| — |
|
|
| 209,895 |
|
Repayments of Long-Term Debt and Lines of Credit |
|
| — |
|
|
| (33,152 | ) |
|
| (230,000 | ) |
|
| — |
|
|
| (263,152 | ) |
Repayments of Loans and Other Notes Payable |
|
| (1,727 | ) |
|
| (994 | ) |
|
| — |
|
|
| — |
|
|
| (2,721 | ) |
Proceeds from Senior Notes, net of Discounts and Premiums |
|
| — |
|
|
| — |
|
|
| 325,000 |
|
|
| — |
|
|
| 325,000 |
|
Debt Issuance Costs |
|
| — |
|
|
| (8 | ) |
|
| (6,816 | ) |
|
| — |
|
|
| (6,824 | ) |
Proceeds from Issuance of Preferred Stock, Net |
|
| — |
|
|
| — |
|
|
| 154,988 |
|
|
| — |
|
|
| 154,988 |
|
Proceeds from the Exercise of Stock Options |
|
| — |
|
|
| — |
|
|
| 515 |
|
|
| — |
|
|
| 515 |
|
Purchase of Non-Controlling Interests |
|
| — |
|
|
| (1,840 | ) |
|
| — |
|
|
| — |
|
|
| (1,840 | ) |
Dividends Paid on Preferred Stock |
|
| — |
|
|
| — |
|
|
| (2,335 | ) |
|
| — |
|
|
| (2,335 | ) |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES |
|
| (1,727 | ) |
|
| 2,901 |
|
|
| 412,352 |
|
|
| — |
|
|
| 413,526 |
|
NET INCREASE (DECREASE) IN CASH |
|
| 16,592 |
|
|
| (391 | ) |
|
| (5 | ) |
|
| — |
|
|
| 16,196 |
|
CASH – BEGINNING |
|
| 1,386 |
|
|
| 504 |
|
|
| 10 |
|
|
| — |
|
|
| 1,900 |
|
CASH - ENDING |
| $ | 17,978 |
|
| $ | 113 |
|
| $ | 5 |
|
| $ | — |
|
| $ | 18,096 |
|
128
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2013
($ in Thousands)
|
| Guarantor Subsidiaries |
|
| Non-Guarantor Subsidiaries |
|
| Rex Energy Corporation (Note Issuer) |
|
| Eliminations |
|
| Consolidated Balance |
| |||||
OPERATING REVENUE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil, Natural Gas and NGL Sales |
| $ | 213,919 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 213,919 |
|
Other Revenue |
|
| 200 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 200 |
|
TOTAL OPERATING REVENUE |
|
| 214,119 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 214,119 |
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and Lease Operating Expense |
|
| 62,138 |
|
|
| 12 |
|
|
| — |
|
|
| — |
|
|
| 62,150 |
|
General and Administrative Expense |
|
| 25,376 |
|
|
| 43 |
|
|
| 5,420 |
|
|
| — |
|
|
| 30,839 |
|
Loss on Disposal of Asset |
|
| 1,601 |
|
|
| 1 |
|
|
| — |
|
|
| — |
|
|
| 1,602 |
|
Impairment Expense |
|
| 32,072 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 32,072 |
|
Exploration Expense |
|
| 11,395 |
|
|
| 13 |
|
|
| — |
|
|
| — |
|
|
| 11,408 |
|
Depreciation, Depletion, Amortization and Accretion |
|
| 62,540 |
|
|
| 46 |
|
|
| — |
|
|
| (200 | ) |
|
| 62,386 |
|
Other Operating Expense |
|
| 592 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 592 |
|
TOTAL OPERATING EXPENSES |
|
| 195,714 |
|
|
| 115 |
|
|
| 5,420 |
|
|
| (200 | ) |
|
| 201,049 |
|
INCOME (LOSS) FROM OPERATIONS |
|
| 18,405 |
|
|
| (115 | ) |
|
| (5,420 | ) |
|
| 200 |
|
|
| 13,070 |
|
OTHER INCOME (EXPENSE) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest Expense |
|
| (64 | ) |
|
| — |
|
|
| (22,612 | ) |
|
| — |
|
|
| (22,676 | ) |
Gain on Derivatives, Net |
|
| (2,703 | ) |
|
| — |
|
|
| (205 | ) |
|
| — |
|
|
| (2,908 | ) |
Other Income (Expense) |
|
| 6,739 |
|
|
| — |
|
|
| - |
|
|
| — |
|
|
| 6,739 |
|
Loss From Equity Method Investments |
|
| (763 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (763 | ) |
Income (Loss) From Equity in Consolidated Subsidiaries |
|
| (33 | ) |
|
| 33 |
|
|
| 5,703 |
|
|
| (5,703 | ) |
|
| — |
|
TOTAL OTHER INCOME (EXPENSE) |
|
| 3,176 |
|
|
| 33 |
|
|
| (17,114 | ) |
|
| (5,703 | ) |
|
| (19,608 | ) |
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAX |
|
| 21,581 |
|
|
| (82 | ) |
|
| (22,534 | ) |
|
| (5,503 | ) |
|
| (6,538 | ) |
Income Tax (Expense) Benefit |
|
| (14,409 | ) |
|
| (1,841 | ) |
|
| 20,404 |
|
|
| — |
|
|
| 4,154 |
|
NET INCOME (LOSS) FROM CONTINUING OPERATIONS |
|
| 7,172 |
|
|
| (1,923 | ) |
|
| (2,130 | ) |
|
| (5,503 | ) |
|
| (2,384 | ) |
Income From Discontinued Operations, Net of Income Taxes |
|
| — |
|
|
| 4,385 |
|
|
| — |
|
|
| (2,574 | ) |
|
| 1,811 |
|
NET INCOME (LOSS) |
|
| 7,172 |
|
|
| 2,462 |
|
|
| (2,130 | ) |
|
| (8,077 | ) |
|
| (573 | ) |
Net Income Attributable to Noncontrolling Interests of Discontinued Operations |
|
| — |
|
|
| 1,557 |
|
|
| — |
|
|
| — |
|
|
| 1,557 |
|
NET INCOME (LOSS) ATTRIBUTABLE TO REX ENERGY |
| $ | 7,172 |
|
| $ | 905 |
|
| $ | (2,130 | ) |
| $ | (8,077 | ) |
| $ | (2,130 | ) |
129
REX ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
FOR THE YEAR ENDING DECEMBER 31, 2013
($ in Thousands)
|
| Guarantor Subsidiaries |
|
| Non-Guarantor Subsidiaries |
|
| Rex Energy Corporation (Note Issuer) |
|
| Eliminations |
|
| Consolidated Balance |
| |||||
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) |
| $ | 7,172 |
|
| $ | 2,462 |
|
| $ | (2,130 | ) |
| $ | (8,077 | ) |
| $ | (573 | ) |
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on Equity Method Investments |
|
| 763 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 763 |
|
Non-Cash Expenses |
|
| (194 | ) |
|
| 55 |
|
|
| 6,369 |
|
|
| — |
|
|
| 6,230 |
|
Depreciation, Depletion, Amortization and Accretion |
|
| 62,540 |
|
|
| 1,604 |
|
|
| — |
|
|
| (200 | ) |
|
| 63,944 |
|
Deferred Income Tax Expense (Benefit) |
|
| 14,409 |
|
|
| 2,210 |
|
|
| (14,340 | ) |
|
| — |
|
|
| 2,279 |
|
Gain on Derivatives |
|
| 2,703 |
|
|
| — |
|
|
| 205 |
|
|
| — |
|
|
| 2,908 |
|
Cash Settlements of Derivatives |
|
| 7,128 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 7,128 |
|
Dry Hole Expense |
|
| 2,993 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 2,993 |
|
(Gain) Loss on Sale of Asset |
|
| (5,289 | ) |
|
| (922 | ) |
|
| — |
|
|
| — |
|
|
| (6,211 | ) |
Impairment Expense |
|
| 32,072 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 32,072 |
|
Changes in operating assets and liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts Receivable |
|
| (5,877 | ) |
|
| (6,515 | ) |
|
| 1,241 |
|
|
| (1,575 | ) |
|
| (12,726 | ) |
Inventory, Prepaid Expenses and Other Assets |
|
| (826 | ) |
|
| (59 | ) |
|
| — |
|
|
| — |
|
|
| (885 | ) |
Accounts Payable and Accrued Liabilities |
|
| 8,554 |
|
|
| 874 |
|
|
| 1,481 |
|
|
| 1,982 |
|
|
| 12,891 |
|
Other Assets and Liabilities |
|
| (2,272 | ) |
|
| (88 | ) |
|
| (137 | ) |
|
| — |
|
|
| (2,497 | ) |
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES |
|
| 123,876 |
|
|
| (379 | ) |
|
| (7,311 | ) |
|
| (7,870 | ) |
|
| 108,316 |
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany Loans to Subsidiaries |
|
| 186,089 |
|
|
| 1,619 |
|
|
| (193,015 | ) |
|
| 5,307 |
|
|
| — |
|
Proceeds from Joint Venture Acreage Management |
|
| 458 |
|
|
| — |
|
|
| — |
|
|
| — |
|
|
| 458 |
|
Contributions to Equity Method Investments |
|
| (2,493 | ) |
|
| — |
|
|
| — |
|
|
| — |
|
|
| (2,493 | ) |
Proceeds from the Sale of Oil and Gas Properties, Prospects and Other Assets |
|
| 8,071 |
|
|
| 3,234 |
|
|
| — |
|
|
| — |
|
|
| 11,305 |
|
Acquisitions of Undeveloped Acreage |
|
| (41,782 | ) |
|
| (2 | ) |
|
| — |
|
|
| — |
|
|
| (41,784 | ) |
Capital Expenditures for Development of Oil and Gas Properties and Equipment |
|
| (275,697 | ) |
|
| (7,870 | ) |
|
| — |
|
|
| 2,563 |
|
|
| (281,004 | ) |
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES |
|
| (125,354 | ) |
|
| (3,019 | ) |
|
| (193,015 | ) |
|
| 7,870 |
|
|
| (313,518 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds from Long-Term Debt and Lines of Credit |
|
| — |
|
|
| 7,249 |
|
|
| 65,000 |
|
|
| — |
|
|
| 72,249 |
|
Repayments of Long-Term Debt and Lines of Credit |
|
| — |
|
|
| (2,480 | ) |
|
| (6,000 | ) |
|
| — |
|
|
| (8,480 | ) |
Repayments of Loans and Other Notes Payable |
|
| (1,363 | ) |
|
| (642 | ) |
|
| — |
|
|
| — |
|
|
| (2,005 | ) |
Proceeds from Senior Notes, net of Discounts and Premiums |
|
| — |
|
|
| — |
|
|
| 105,000 |
|
|
| — |
|
|
| 105,000 |
|
Debt Issuance Costs |
|
| — |
|
|
| (8 | ) |
|
| (3,126 | ) |
|
| — |
|
|
| (3,134 | ) |
Proceeds from the Exercise of Stock Options |
|
| — |
|
|
| — |
|
|
| 533 |
|
|
| — |
|
|
| 533 |
|
Purchase of Non-Controlling Interests |
|
| — |
|
|
| (150 | ) |
|
| — |
|
|
| — |
|
|
| (150 | ) |
Distributions by the Partners of Consolidated Subsidiary |
|
| — |
|
|
| (886 | ) |
|
| — |
|
|
| — |
|
|
| (886 | ) |
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES |
|
| (1,363 | ) |
|
| 3,083 |
|
|
| 161,407 |
|
|
| — |
|
|
| 163,127 |
|
NET INCREASE (DECREASE) IN CASH |
|
| (2,841 | ) |
|
| (315 | ) |
|
| (38,919 | ) |
|
| — |
|
|
| (42,075 | ) |
CASH – BEGINNING |
|
| 4,227 |
|
|
| 819 |
|
|
| 38,929 |
|
|
| — |
|
|
| 43,975 |
|
CASH - ENDING |
| $ | 1,386 |
|
| $ | 504 |
|
| $ | 10 |
|
| $ | — |
|
| $ | 1,900 |
|
130
Exchange Offer
On February 3, 2016, we announced the commencement of an exchange offer and consent solicitation related to our outstanding Senior Notes, and on March 14, 2016, we revised those terms and re-announced the exchange offer. We are offering to exchange any and all of the Senior Notes held by eligible holders for up to (i) $675.0 million in new senior secured second lien notes (“New Notes”), plus the amount of additional New Notes, not to exceed $6.0 million, resulting solely from any exchange participant’s election to receive additional New Notes in lieu of shares of common stock under the exchange offering, and (ii) 10.125 million shares of our common stock. The New Notes will bear interest at a rate of 0.0% per annum for the first three bi-annual interest payments after issuance and 8.0% per annum payable in cash thereafter, paid on a bi-annual basis; provided, however, that if greater than 85% of the Senior Notes are tendered in the exchange, the New Notes will bear interest at a rate of 1.0% per annum payable in cash for the first three interest payments after issuance and 8.0% per annum payable in cash thereafter. The New Notes will mature on October 1, 2020; provided, however, that if greater than 85% of the Senior Notes are tendered in the exchange, the New Notes will mature on October 1, 2021. In addition to the exchange offer, we are soliciting consents from the eligible holders to proposed amendments to the indentures governing the Senior Notes that would eliminate or modify certain restrictive covenants and modify certain defined terms. The aggregate principal amount of our Senior Notes as of December 31, 2015 was $675.0 million.
Senior Credit Facility Amendment
On February 3, 2016, we amended our Senior Credit Facility, in part to permit the aforementioned exchange offer. The amendment contemplated the following changes:
| · | Decreases our borrowing base from $350.0 million to $200.0 million; |
| · | Amends the definition of net senior secured debt to exclude undrawn letters of credit related to firm transportation contracts and second lien exchange notes; |
| · | Amends the calculation of current ratio to exclude current assets and current liabilities related to deferred taxes; |
| · | Increases pricing from 150-250 basis points to 225-325 basis points; and |
| · | Increases the commitment fee to 50 basis points. |
On March 14, 2016, we entered into another amendment to our Senior Credit Facility, in part to revise the terms of the exchange offering. The amendment contemplated the following changes:
| · | Allows for the issuance of up to $675.0 million of New Notes, plus an additional amount of New Notes, not to exceed $6.0 million, resulting solely from any exchange participant’s election to receive additional New Notes in lieu of shares of common stock under the exchange offering; |
| · | In the event that holders of at least 80% of the Company’s Senior Notes exchange such notes for New Notes, amends the calculation of the Company’s maximum 3.0x Ratio of Net Senior Secured Debt to EBITDAX to become 2.75 to 1.00; |
| · | Increases the requirement for mortgages on oil and gas properties from 90% to 95%, and for certain properties in the Moraine East and Warrior North Areas, to 100%; |
| · | Restricts cash and cash equivalents held on the balance sheet to a maximum of $15.0 million, with any excess used to pay down the outstanding Senior Credit Facility balance, however we retain the right to draw on the Senior Credit Facility so long as there are amounts available under our borrowing base; |
| · | Provides in the event that any letter of credit which secures obligations under a firm transportation contract expires without renewal or replacement, or is cancelled, terminated or otherwise ceases to remain outstanding, then the borrowing base then in effect shall be automatically reduced immediately by an amount equal to the product of 0.50 multiplied by the undrawn amount of such letter of credit; |
| · | Restricts the Company’s ability to pay cash dividends to its holders of Series A Preferred Stock until after the Company delivers its audited financial statements for the fiscal year 2016 to the Lenders as required under the Senior Credit Facility, and thereafter permits such cash payments only if certain parameters are met relating to outstanding borrowings and interest expense; and |
| · | Provides for an additional redetermination of the borrowing base under the Senior Credit Facility on July 1, 2016. |
After the July 1, 2016 redetermination, our Senior Credit Facility will resume its normal semi-annual redetermination schedule, with the next redetermination expected to take place in the third quarter of 2016.
131
Joint Exploration and Development Agreement
On March 1, 2016, we entered into a Joint Exploration and Development Agreement (the “Joint Development Agreement”) with OhPa Drillco (“Drillco”), an affiliate of Benefit Street Partners, L.L.C. to jointly develop 58 specifically designated wells in our Moraine East and Warrior North operated areas. Under the Joint Development Agreement, Drillco has committed to fund 15% of various drilling, completing and equipping costs (“well costs”) for the first 16 wells in Moraine East at a specified rate, 12 of which have already been drilled and completed, and 65% of the well costs of six wells in Warrior North at a specified rate, three of which have already been drilled and completed. In return for Drillco’s funding of the well costs, we will assign to Drillco a working interest of 15% in the funded wells located in Moraine East and 65% in the funded wells in Warrior North, together with the rights to real and personal property, permits, licenses, and other rights that are necessary or required to operate and produce oil, gas and other hydro carbons and all associated substances from the wellbores of such wells. Drillco will also have the option to participate in the next 36 wells within the joint development areas for a 65% working interest. In addition, Drillco will earn a 15% - 20% assignment in Moraine East and Warrior North for all acreage within each unit they participate in.
Total consideration for the transaction is expected to be $175.0 million, with $37.3 million committed at closing for the first 22 wells. Once the first 15 wells within the joint development areas are flowing into sales, we will receive reimbursement of approximately $19.5 million.
Commodity Derivatives
We continue to be opportunistic in adding commodity derivatives as market conditions warrant. To date in 2016 we have added derivatives covering approximately 380,000 barrels of oil, 2,740,000 mcf of natural gas and 120,000 barrels of NGLs for volumes related to 2016. The oil derivatives added include collars, three-way collars and cap swap contracts. The natural gas derivatives added included swap and put spread contracts. The NGL derivatives added consisted of swap contracts.
132
Not applicable.
Evaluation of Disclosure Controls and Procedures. We have established disclosure controls and procedures to ensure that material information relating to the company is made known to the officers who certify the financial statements and to other members of senior management and the audit committee of our board of directors. As of December 31, 2015, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer (the “CEO”) and the Chief Financial Officer (the “CFO”), of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e), and 15d-15(e) under the Securities Exchange Act of 1934). An evaluation was conducted to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms. Our CEO and CFO have concluded that our disclosure controls and procedures were effective as of the date of such evaluation.
Changes in Internal Control over Financial Reporting. No change to our internal control over financial reporting occurred during the year ended December 31, 2015 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f), and 15d-15(f) under the Securities Exchange Act of 1934). Management has used the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission entitled Internal Control-Integrated Framework (2013) to evaluate the effectiveness of our internal control over financial reporting. Internal control over financial reporting refers to the process designed by, or under the supervision of, our CEO and CFO, and overseen by our board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:
| â—Ź | Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; |
| â—Ź | Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with general accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and |
| ● | Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements. |
Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, however, neither internal control over financial reporting nor disclosure controls and procedures can provide absolute assurance of achieving financial reporting objectives because of their inherent limitations. Internal control over financial reporting and disclosure controls are processes that involve human diligence and compliance, and are subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting and disclosure controls also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented, detected or reported on a timely basis by internal control over financial reporting or disclosure controls. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design safeguards for these processes that will reduce, although may not eliminate, these risks.
Management has concluded that our internal controls over financial reporting and our disclosure controls and procedures were effective as of December 31, 2015. Management reviewed the results of their assessment with our Audit Committee. The effectiveness of our internal control over financial reporting as of December 31, 2015 has been audited by KPMG, LLP an independent registered public accounting firm, as stated in their report which is set forth below.
133
Report of Independent Registered Public Accounting Firm
The Board of Directors
Rex Energy Corporation:
We have audited Rex Energy and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Rex Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Rex Energy Corporation and subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, changes in noncontrolling interests and stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015, and our report dated March 15, 2016 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
Pittsburgh, Pennsylvania
March 15, 2016
134
Not applicable.
The information required by this item is incorporated by reference to such information as set forth in our definitive Proxy Statement (the “2015 Proxy Statement”) for our 2016 annual meeting of stockholders. The 2016 Proxy statement will be filed with the SEC not later than 120 days subsequent to December 31, 2015.
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement for the 2016 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2015.
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement for the 2016 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2015.
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement for the 2016 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2015.
The information required by this item is incorporated herein by reference to the 2016 Proxy Statement for the 2016 annual meeting of stockholders, which will be filed with the SEC not later than 120 days subsequent to December 31, 2015.
135
(a)(1) Financial Statements
(a)(2) Financial Statement Schedules
All other schedules are omitted because they are not applicable, not required, or because the required information is included in the financial statements or related notes.
136
Exhibit |
| Exhibit Title | ||
2.1- |
|
Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.2 |
|
Form of Area One Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.3 |
|
Form of Area Two Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.3 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.4 |
|
Form of Area Three Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.4 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.5 |
|
Form of Area Four Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.5 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.6 |
|
Form of Parent Guaranty of Rex Energy Corporation attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.6 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.7 |
|
Form of Parent Guaranty of Sumitomo Corporation attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.7 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.8 |
|
First Amendment to Participation and Exploration Agreement, dated September 30, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on October 6, 2010). | ||
2.9 |
| Participation Agreement, dated March 30, 2015, by and between R.E. Gas Development, LLC and AL Marcellus Holdings, LLC (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 10-Q filed with the SEC on May 11, 2015). | ||
2.10 |
| Membership Interest Purchase Agreement, dated June 18, 2015, by and between Rex Energy Corporation and Sand Hills Management, LLC, as Sellers, and American Industrial Water, LLC, as Purchaser (incorporated by reference to Exhibit 2.1 to our Amendment No. 1 to Quarterly Report on Form 8-K filed with the SEC on October 9, 2015). | ||
2.11 |
| Amendment to Membership Interest Purchase Agreement, dated July 8, 2015, by and between Rex Energy Corporation and Sand Hills Management, LLC, as Sellers, and American Industrial Water, LLC, as Purchaser (incorporated by reference to Exhibit 2.2 to our Amendment No. 1 to Quarterly Report on Form 8-K filed with the SEC on October 9, 2015). |
137
138
10.8+ |
|
Form of Stock Appreciation Right Award Agreement under Rex Energy 2007 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.30 to our Annual Report on Form 10-K filed with the SEC on March 31, 2008). | ||
10.9+ |
|
Form of Restricted Stock Award Agreement for employee restricted stock awards under Rex Energy 2007 Long-Term Incentive Plan (prior to December 2011) (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on March 31, 2010). | ||
10.10+ |
|
Form of Performance-Based Restricted Stock Award for employee restricted stock awards under Rex Energy 2007 Long Term Incentive Plan (first effective for awards granted in December 2011) (incorporated by reference to Exhibit 10.32 to our Annual Report on Form 10-K filed with the SEC on March 15, 2012). | ||
10.11+ |
|
Form of Time/Service Based Restricted Stock Award Agreement for employee restricted stock awards under Rex Energy 2007 Long-Term Incentive Plan (first effective for awards granted in December 2011) (incorporated by reference to Exhibit 10.33 to our Annual Report on Form 10-K filed with the SEC on March 15, 2012). | ||
10.12 |
|
Operating Agreement of Charlie Brown Air II, LLC dated as of June 26, 2008 (incorporated by reference to Exhibit 10.35 to our Annual Report on Form 10-K/A filed with the SEC on October 9, 2009). | ||
10.13 |
|
Participation and Exploration Agreement dated June 18, 2009 by and among Williams Production Company, LLC, Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on June 24, 2009). | ||
10.14 |
|
Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement dated June 18, 2009 by and among Williams Production Company, LLC, Williams Production Appalachia, LLC, Rex Energy I, LLC and R.E. Gas Development, LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on June 24, 2009). | ||
10.15 |
|
Limited Liability Company Agreement of RW Gathering, LLC effective as of June 18, 2009 (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed with the SEC on June 24, 2009). | ||
10.16 |
|
Settlement Agreement and Release by and between Julia Leib and Lisa Thompson, individually and on behalf of the certified class, on the one hand, and Rex Energy Operating Corp. and PennTex Resources Illinois, Inc., on the other hand, effective December 17, 2009 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on December 22, 2009). | ||
10.17- |
|
Contribution Agreement, dated December 21, 2009, by and among R.E. Gas Development, LLC, Stonehenge Energy Resources, L.P. and Keystone Midstream Services, LLC (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed with the SEC on December 28, 2009). | ||
10.18- |
|
Gas Gathering, Compression and Processing Agreement, dated December 21, 2009, by and between R.E. Gas Development, LLC, Keystone Midstream Services, LLC and Rex Energy Corporation (incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed with the SEC on December 28, 2009). | ||
10.19- |
|
Master Crude Purchase Agreement by and among certain direct and indirect wholly owned subsidiaries of Rex Energy Corporation and CountryMark Cooperative, dated December 30, 2009. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on January 5, 2010). | ||
10.20 |
|
Independent Director Agreement by and between Rex Energy Corporation and Eric L. Mattson effective as of April 30, 2010 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on April 30, 2010). | ||
10.21 |
|
Purchase and Sale Agreement dated June 28, 2010 by and between Rex Energy Rockies, LLC and Duncan Oil Partners, LLC (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on July 7, 2010). | ||
10.22+ |
|
Employment Agreement by and between Patrick McKinney and Rex Energy Operating Corp. dated October 1, 2010 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K as filed with the SEC on October 7, 2008). |
139
140
141
* | Filed herewith. |
** | Furnished herewith. |
+ | Indicates management contract or compensation plan or arrangement. |
- | Portions of this exhibit are subject to a request for confidential treatment and have been redacted and filed separately with the Securities and Exchange Commission. |
142
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a description of the meanings of some of the oil and gas industry terms used in this report:
Basin. A large natural depression on the earth’s surface in which sediments accumulate.
Bbl. One stock tank barrel, of 42 U.S. gallons liquid volume, of crude oil.
Bcf. Billion cubic feet, determined using the ratio of six Mcf of gas to one Bbl of crude oil, condensate or gas liquids.
Bopd. Barrels of oil per day.
Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or gas.
Development or Developmental well. A well drilled within the proved boundaries of an oil or gas reservoir with the intention of completing the stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses, taxes and the royalty burden.
Estimated proved reserves. Those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geosciences and engineering data.
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geosciences, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geosciences, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Exploitation. A drilling or other project which may target proved or unproved reserves (such as probable or possible reserves), but generally is expected to have lower risk.
Exploration or Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.
143
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation usually yields a well which has the ability to produce higher volumes than a vertical well drilled in the same formation.
Injection well or Injection. A well which is used to place liquids or gases into the producing zone during secondary/tertiary recovery operations to assist in maintaining reservoir pressure and enhancing recoveries from the field.
Lease operating expenses. The expenses of lifting oil or gas from a producing formation to the surface, and the transportation and marketing thereof, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, ad valorem taxes and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBOE. One thousand barrels of oil equivalent.
Mcf. One thousand cubic feet of natural gas.
Mcfd. One thousand cubic feet of natural gas per day.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of gas.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of gas to one Bbl of oil, condensate or gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.
NYMEX. New York Mercantile Exchange.
PV-10 or present value of estimated future cash flows. An estimate of the present value of the estimated future cash flows from proved oil and gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of federal income taxes. The estimated future cash flows are discounted at an annual rate of 10%, in accordance with the Securities and Exchange Commission’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future cash flows are made using oil and gas prices and operating costs at the date indicated and held constant for the life of the reserves.
Primary recovery. The period of production in which oil and natural gas is produced from its reservoir through the wellbore without enhanced recovery technologies, such as water floods or ASP floods.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
144
Proved developed non-producing reserves or PDNP. Proved developed reserves expected to be recovered from zones behind casing in existing wells.
Proved developed producing reserves or PDP. Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.
Proved developed reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate
Proved undeveloped reserves or PUD. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.
Recompletion. The addition of production from another interval or formation in an existing wellbore.
Reserve life index. An index calculated by dividing year-end estimated proved reserves by the average production during the past year to estimate the number of years of remaining production.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Secondary recovery. An artificial method or process used to restore or increase production from a reservoir after the primary production by the natural producing mechanism and reservoir pressure has experienced partial depletion. Gas injection and waterflooding are examples of this technique.
Tertiary recovery. The third stage of hydrocarbon production during which sophisticated techniques that alter the original properties of the oil are used. Chemical flooding (including ASP flooding), miscible displacement and thermal flooding are examples of this technique.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas, regardless of whether or not such acreage contains estimated proved reserves.
Waterflooding. A secondary recovery operation in which water is injected into the producing formation in order to maintain reservoir pressure and force oil toward and into the producing wells.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
Workover. Operations on a producing well to restore or increase production.
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Dated: March 15, 2016
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| REX ENERGY CORPORATION |
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| By: |
|
/s/ THOMAS C. STABLEY |
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| Thomas C. Stabley |
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|
| Chief Executive Officer |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ LANCE T. SHANER
Lance T. Shaner |
|
Chairman of the Board |
| March 15, 2016 |
/s/ THOMAS C. STABLEY
Thomas C. Stabley |
|
Chief Executive Officer and Director (Principal Executive Officer) |
|
March 15, 2016 |
/s/ THOMAS G. RAJAN
Thomas G. Rajan |
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Chief Financial Officer (Principal Financial Officer) |
| March 15, 2016 |
/s/ CURTIS J. WALKER
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Chief Accounting Officer (Principal Accounting Officer) |
| March 15, 2016 |
Curtis J. Walker |
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| ||
/s/ ERIC L. MATTSON
Eric L. Mattson |
| Director |
| March 15, 2016 |
/s/ JOHN W. HIGBEE
John W. Higbee |
| Director |
| March 15, 2016 |
/s/ JOHN A. LOMBARDI
John A. Lombardi |
| Director |
| March 15, 2016 |
/s/ JOHN J. ZAK
John J. Zak |
| Director |
| March 15, 2016 |
/s/ TODD N. TIPTON
Todd N. Tipton |
| Director |
| March 15, 2016 |
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/s/ JACK N. AYDIN |
| Director |
| March 15, 2016 |
Jack N. Aydin |
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146
Exhibit |
| Exhibit Title | ||
2.1- |
|
Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.2 |
|
Form of Area One Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.2 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.3 |
|
Form of Area Two Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.3 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.4 |
|
Form of Area Three Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.4 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.5 |
|
Form of Area Four Tax Partnership Agreement attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.5 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.6 |
|
Form of Parent Guaranty of Rex Energy Corporation attached and made a part of the Participation and Exploration Agreement, dated August 31, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.6 to our Current Report on Form 8-K filed with the SEC on September 3, 2010). | ||
2.7 |
|
First Amendment to Participation and Exploration Agreement, dated September 30, 2010, by and among Summit Discovery Resources II, LLC, Rex Energy I, LLC, R.E. Gas Development, LLC, joined therein by Rex Energy Operating Corp., and for the limited purposes set forth therein, Rex Energy Corporation and Sumitomo Corporation (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K filed with the SEC on October 6, 2010). | ||
2.8- |
| Participation Agreement, dated March 30, 2015, by and between R.E. Gas Development, LLC and AL Marcellus Holdings, LLC (incorporated by reference to Exhibit 2.1 to our Quarterly Report on Form 10-Q filed with the SEC on May 11, 2015). | ||
2.9- |
| Membership Interest Purchase Agreement, dated June 18, 2015, by and between Rex Energy Corporation and Sand Hills Management, LLC, as Sellers, and American Industrial Water, LLC, as Purchaser (incorporated by reference to Exhibit 2.1 to our Amendment No. 1 to Quarterly Report on Form 8-K filed with the SEC on October 9, 2015). | ||
2.10- |
| Amendment to Membership Interest Purchase Agreement, dated July 8, 2015, by and between Rex Energy Corporation and Sand Hills Management, LLC, as Sellers, and American Industrial Water, LLC, as Purchaser (incorporated by reference to Exhibit 2.2 to our Amendment No. 1 to Quarterly Report on Form 8-K filed with the SEC on October 9, 2015). | ||
3.1 |
|
Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007). | ||
3.2 |
|
Certificate of Amendment to Certificate of Incorporation of Rex Energy Corporation (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-142430) as filed with the SEC on April 27, 2007). |
147
148
149
150
10.41 |
|
Fourth Amendment to Amended and Restated Credit Agreement, effective as of August 15, 2014, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and the other lenders signatory thereto (incorporated by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q filed with the SEC on November 5, 2014). | ||
10.42 |
|
Fifth Amendment to Amended and Restated Credit Agreement effective as of September 12, 2014, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.5 to our Quarterly Report on Form 10-Q filed with the SEC on November 5, 2014). | ||
10.43 |
|
Sixth Amendment to Amended and Restated Credit Agreement effective as of December 16, 2014, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto, (incorporated by reference to Exhibit 10.49 to our Annual Report on Form 10-K filed with the SEC on March 2, 2015). | ||
10.44+ |
| Separation Agreement and Complete Release by and between Michael L. Hodges and Rex Operating Corp. dated January 1, 2015 (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q filed with the SEC on May 11, 2015). | ||
10.45+ |
| Seventh Amendment to Amended and Restated Credit Agreement effective as of December 16, 2014, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q filed with the SEC on May 11, 2015). | ||
10.46+ |
| Independent Director Agreement by and between Jack N. Aydin and Rex Energy Corporation dated June 1, 2015 (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the SEC on May 26, 2015). | ||
10.47+ |
| Separation Agreement and Complete Release by and between Patrick M. McKinney and Rex Operating Corp. dated August 1, 2015 (incorporated by reference to Exhibit 99.2 to our Current Report on Form 8-K filed with the SEC on August 4, 2015). | ||
10.48 |
| Waiver to Amended and Restated Credit Agreement effective as of June 15, 2015, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q filed with the SEC on August 10, 2015). | ||
10.49 |
| Eighth Amendment to Amended and Restated Credit Agreement effective as of September 4, 2015, by and among Rex Energy Corporation, Royal Bank of Canada, as Administrative Agent, and other lenders signatory thereto (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q filed with the SEC on November 9, 2015). | ||
12.1* |
|
Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividend. | ||
21.1* |
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Subsidiaries of the Registrant. | ||
23.1* |
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Consent of KPMG, LLP. | ||
23.2* |
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Consent of Netherland, Sewell & Associates, Inc. | ||
31.1* |
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Certification of Chief Executive Officer (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act. | ||
31.2* |
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Certification of Chief Financial Officer (Principal Financial Officer) pursuant to Section 302 of the Sarbanes-Oxley Act. | ||
32.1* |
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Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act. | ||
32.2* |
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Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act. | ||
99.1* |
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Report of Netherland, Sewell & Associates, Inc. | ||
101.INS* |
|
XBRL Instance Document | ||
101.SCH* |
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XBRL Taxonomy Extension Schema Document | ||
101.CAL* |
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XBRL Taxonomy Extension Calculation Linkbase Document |
151
|
| |||
101.LAB* |
|
XBRL Taxonomy Extension Label Linkbase Document | ||
101.PRE* |
|
XBRL Taxonomy Extension Presentation Linkbase Document |
* | Filed herewith. |
** | Furnished herewith. |
+ | Indicates management contract or compensation plan or arrangement. |
- | Portions of this exhibit are subject to a request for confidential treatment and have been redacted and filed separately with the Securities and Exchange Commission. |
152