As filed with the Securities and Exchange Commission on August 8, 2014

Registration No. 333-197257

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

AMENDMENT NO. 1
TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

IMPERIAL RESOURCES, LLC

(to be converted as described herein to
a corporation named)

EMPIRE ENERGY HOLDINGS, INC.

(Exact name of registrant as specified in its charter)


Delaware	1311	20-4215632
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(IRS Employer Identification Number)

380 Southpointe Boulevard, Suite 130
Canonsburg, Pennsylvania 15317
(724) 483-2070

(Address, including zip code, and telephone number,
including area code, of registrant’s principal executive offices)

Bruce W. McLeod
Chief Executive Officer
380 Southpointe Boulevard, Suite 130
Canonsburg, Pennsylvania 15317
(724) 483-2070

(Name, address, including zip code, and telephone number,
including area code, of agent for service)

Copies to:


William H. Haddad, Esq. Reed Smith LLP 599 Lexington Avenue New York, New York 10022 (212) 521-5400		Barry I. Grossman, Esq. Ellenoff Grossman & Schole LLP 1345 Avenue of the Americas, 11^th Floor New York, New York 10105 (212) 370-1300

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box: x

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

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


Large accelerated filer o		Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company x

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CALCULATION OF REGISTRATION FEE


Title of Each Class of Securities to be Registered	Proposed Maximum Aggregate Offering Price⁽¹⁾⁽²⁾		Amount of Registration Fee
Common Stock, par value $0.01 per share⁽³⁾	$	20,000,000	$	2576
Representative's Warrants to Purchase Common Stock⁽⁴⁾		—		—
Shares of Common Stock underlying Representative's Warrants⁽³⁾⁽⁵⁾	$	1,250,000	$	161
Total	$	21,250,000	$	2737

(1)

Estimated solely for the purpose of computing the amount of the registration fee pursuant to Rule 457(o) under the Securities Act of 1933, as amended.

(2)

Includes the aggregate offering price of additional shares that the underwriters have the right to purchase from us, if any.

(3)

Pursuant to Rule 416 under the Securities Act of 1933, as amended, the securities being registered hereunder include such indeterminate number of additional securities as may be issued after the date hereof as a result of stock splits, stock dividends or similar transactions.

(4)

No registration fee pursuant to Rule 457(g) under the Securities Act of 1933, as amended.

(5)

Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(g) under the Securities Act of 1933, as amended. We have agreed to issue warrants exercisable during the five-year period commencing on the six-month anniversary of the public offering and representing 5.0% of the shares issued in the offering to Maxim Group LLC for nominal consideration (the “Representative’s Warrants”), which are exercisable at a per share exercise price equal to 125% of the public offering price per share. As estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(g) under the Securities Act of 1933, as amended, the proposed maximum aggregate offering price of the Representative’s Warrants is $1,250,000 which is equal to 125% of $1,000,000 (5.0% of $20,000,000). The issuance of the Representative’s warrants is being registered hereby. The shares of Common Stock issuable upon exercise of the Representative’s Warrants are also being registered on a delayed or continuous basis hereby. See “Underwriting.” The Common Stock underlying the Representative’s Warrants is being registered solely in connection with the Securities and Exchange Commission’s Compliance and Disclosure Interpretations for Securities Act Sections, Question 139.05. No “offer” of such common stock exists as defined in Section 2(a)(3) of the Securities Act because the Representative’s Warrants are not exercisable until six months following their issuance.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state or jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED AUGUST 8, 2014

PRELIMINARY PROSPECTUS

[GRAPHIC MISSING]

Common Stock

Empire Energy Holdings, Inc. is offering its common stock, par value $0.01 per share, in a firm commitment underwritten public offering. Prior to this offering, there has been no public market for our common stock. The estimated initial public offering price is between $ and $ per share.

We have applied for the listing of our common stock on The NASDAQ Capital Market under the symbol “EEHI”. We make no representation that such application will be approved or that our common stock will trade on such market either now or at any time in the future.


	Per Share	Total
Initial public offering price	$	$
Underwriting discounts and commissions⁽¹⁾	$	$
Proceeds to us (before expenses)	$	$

(1)

The underwriters will receive compensation in addition to the underwriting discounts and commissions. See “Underwriting” for a description of compensation payable to the underwriters in connection with this offering.

We have granted a 45-day option to the underwriters to purchase up to an additional shares of our common stock solely to cover over-allotments, if any.

We are an “emerging growth company” as that term is used in the Jumpstart Our Business Startups Act of 2012 and, as such, may elect to comply with certain reduced reporting requirements for this preliminary prospectus and future filings. Please see “Prospectus Summary — Implications of Being an Emerging Growth Company.”

Investing in our common stock involves a high degree of risk. See “Risk Factors” beginning on page 18 of this prospectus for a discussion of information that should be carefully considered in connection with an investment in our common stock.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed on the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the shares of common stock to purchasers in the offering on or about , 2014.

Sole Book-Running Manager

Maxim Group LLC

Prospectus dated , 2014

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Total Company

YE13 Proved Reserves: 7,926 MBoe
Percent Oil: 37%
Acreage: 278,527 net acres
Avg. 2013 Daily Production: 1,343 Boe/d

[GRAPHIC MISSING]

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PROSPECTUS SUMMARY			1
RISK FACTORS			18
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS AND INDUSTRY DATA			44
USE OF PROCEEDS			46
DIVIDEND POLICY			47
CAPITALIZATION			48
DILUTION			50
SELECTED CONSOLIDATED FINANCIAL DATA			52
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			54
BUSINESS			75
MANAGEMENT			95
EXECUTIVE COMPENSATION			99
PRINCIPAL STOCKHOLDERS			101
CORPORATE REORGANIZATION			102
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS			105
DESCRIPTION OF CAPITAL STOCK			107
SHARES ELIGIBLE FOR FUTURE SALE			110
MATERIAL U.S. FEDERAL INCOME AND ESTATE TAX CONSIDERATIONS FOR NON-U.S. HOLDERS OF COMMON STOCK			112
UNDERWRITING			115
LEGAL MATTERS			120
EXPERTS			120
WHERE YOU CAN FIND ADDITIONAL INFORMATION			120
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS			F-1
ANNEX A: GLOSSARY OF OIL AND NATURAL GAS TERMS			A-1

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You should rely only on the information contained in this prospectus. Neither we nor any of the underwriters has authorized anyone to provide you with information different from, or in addition to, that contained in this prospectus or any free writing prospectus prepared by or on behalf of us or to which we may have referred you in connection with this offering. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. Neither we nor any of the underwriters is making an offer to sell or seeking offers to buy these securities in any jurisdiction where, or to any person to whom, the offer or sale is not permitted. The information in this prospectus is accurate only as of the date on the front cover of this prospectus, regardless of the time of delivery of this prospectus or of any sale of shares of our common stock, and the information in any free writing prospectus that we may provide you in connection with this offering is accurate only as of the date of that free writing prospectus. Our business, financial condition, results of operations and future growth prospects may have changed since those dates.

This prospectus includes statistical and other industry and market data that we obtained from industry publications and research, surveys and studies conducted by third parties. Industry publications and third-party research, surveys and studies generally indicate that their information has been obtained from sources believed to be reliable, although they do not guarantee the accuracy or completeness of such information. While we believe these industry publications and third-party research, surveys and studies are reliable, we have not independently verified such data.

For investors outside the United States: We have not and the underwriters have not done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in the United States. Persons outside the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of the securities and the distribution of this prospectus outside the United States from sources believed to be reliable.

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus and does not contain all of the information that you should consider in making your investment decision. Before investing in our securities, you should carefully read this entire prospectus, including our financial statements and the related notes and the information set forth under the headings “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” in each case included elsewhere in this prospectus. Unless otherwise stated or the context requires otherwise, references in this prospectus to “Empire,” the “Company,” “we,” “us,” or “our” refer to Empire Energy Holdings, Inc., a Delaware corporation, and, where appropriate, (i) Imperial Resources, LLC, its predecessor prior to the Corporate Reorganization (as defined herein), and (ii) its subsidiaries.

Our Company

We are an independent returns-focused exploration and production company focused on the acquisition, exploration and development of conventional oil and natural gas reserves in the Kansas (Mid-Continent), New York and Pennsylvania (Appalachia) regions. We operate approximately 300 producing wells in the Mid-Continent and approximately 1,700 producing wells in the Appalachian Basin. Our drilling activity is currently focused on the low-risk vertical development of the Arbuckle and Lansing/Kansas City formations located in Central Kansas (Mid-Continent) and the Upper Devonian Bradford Group, which is an oil and liquids-rich producing formation located in Upstate New York (Appalachia). We also have a significant number of natural gas producing Medina formation development locations which are marginally economic at current natural gas prices. Additionally, we have significant acreage in the Marcellus Shale and Utica Shale fairways, value extraction from which is dependent upon the lifting of the New York moratorium on high volume hydraulic fracturing (“fracking”) of horizontal wells. We intend to position ourselves to take advantage of our New York State shale resources if and when the moratorium is lifted.

We were founded in September 2006 by a group of individuals with extensive experience in the oil and gas and finance industries. With an average of over 20 years of industry experience, our expanded management team has a proven track record of working as a team to acquire, develop and exploit oil and natural gas reserves in the Mid-Continent and Appalachian regions.

Our acreage position was 306,476 gross (278,527 net) acres at March 31, 2014, which we group into two primary areas based on geographic locations, Mid-Continent (sometimes also referred to as Mid-Con) and Appalachia, which are comprised of approximately 22,869 gross (17,609 net) acres and 283,607 gross (260,918 net) acres, respectively.

Since our inception, we have completed three significant acquisitions, four bolt-on acquisitions and one divestiture. In December 2006, the Company acquired for $9.2 million DK Gas, located in Hawthorn, Pennsylvania where the Company continues to maintain an operations facility today. The acquisition included approximately 150 operating gas wells and 6,000 leased acres in Jefferson, Clarion and Armstrong Counties in Pennsylvania. In December 2009, the Company purchased approximately 1,600 operating wells (predominantly gas) and 300,000 leased acres located in upstate New York from Range Resources Corporation for $38.0 million. The wells and leases are located in Chautauqua, Cattaraugus, Erie, Wyoming, Ontario, Seneca, Cayuga and Wayne Counties in New York and Erie County in Pennsylvania. The Company maintains an operations facility in Mayville, New York. In December 2010, the Company purchased approximately 300 operating wells (predominantly oil) and 22,000 leased acres located in central Kansas from Amadeus Petroleum for $56.6 million. The Company maintains operations facilities in Great Bend, Plainville, and Wichita, Kansas. With respect to the bolt-on acquisitions, the Company consummated one bolt-on acquisition in the Mid-Con region in June 2012 for $1.7 million and three bolt-on acquisitions in Appalachia in each of September 2011, April 2012 and August 2012 for an aggregate of $0.4 million. With respect to the divestiture, in 2010, the Company sold the deep drilling rights for the acreage acquired from DK Gas to a third party for $24.6 million.

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From the time we began operations in December 2006 through March 31, 2014, we have drilled 37 gross operated vertical wells on our properties with an 88% success rate and we have drilled no horizontal wells.

In 2013, due to our strategy of building up cash reserves for potential proved developed producing (PDP) heavy acquisitions, our development capital was only approximately $1.3 million and we drilled a total of 5 gross (4 net) wells. In 2014, we plan to invest at least $5.0 million of development capital to drill 21 gross (16 net) wells. Following this offering, we would seek to increase the investment of wells drilled in 2014 by at least $2.5 million, which should result in the drilling of an additional 8 gross (5 net) wells.

The following chart shows our average net daily production for each quarter from the fourth quarter of 2006 until the fourth quarter of 2013, which shows an uptrend after acquisitions completed in each of December 2006, December 2009 and December 2010.

[GRAPHIC MISSING]

The following table provides a summary of our acreage, average working interest, producing wells, drilling locations, years of drilling inventory, our average net daily production for the quarter ended March 31, 2014, projected 2014 gross and net wells drilled and projected 2014 drilling and completion capital budget as of December 31, 2013 (not taking into account the proceeds from this offering).


	Acreage⁽¹⁾				Average Working Interest			Producing Wells				Identified Drilling Locations⁽²⁾				Drilling Inventory Years⁽³⁾		Q1 2014 Average Net Daily Production			2014 Projected Wells Drilled				2014 Projected D&C Capex Budget ($ mm)
	Gross		Net		Average Working Interest			Gross		Net		Gross		Net		Drilling Inventory Years⁽³⁾		Q1 2014 Average Net Daily Production			Gross		Net		2014 Projected D&C Capex Budget ($ mm)
Mid-Con		22,869		17,609		77	%		294		226		127		90		13		439	Boe		10		8	$	3.6
Appalachia		283,607		260,918		92	%		1,673		1,540		38		26		3		4,631	Mcf		11		10		1.4
Total		306,476		278,527		91	%		1,967		1,766		165		116		8		1,211	Boe		21		18	$	5.0

(1)

Mid-Con acreage is 98% oil-related. Appalachian acreage is 99% natural gas-related, although the 2014 drilling program relates to one Bass Island Reef (NY) oil well and at least ten Upper Devonian Bradford Group oil and liquids rich wells.

(2)

Based on our reserve reports as of December 31, 2013, we had 165 gross (116 net) locations. Please see “Business — Oil and Natural Gas Reserves — Determination of Identified Drilling Locations” for more information regarding the process and criteria through which these drilling locations were identified. The reserve report of LaRoche Petroleum Consultants, Ltd. as of December 31, 2013 identified 28 PUD drilling locations in Kansas, of which 20 were identified to be drilled in 2014. Due to recent lease acquisitions and additional information, as of July 1, 2014, we have elected to drill six PUDs, one

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possible and three probable locations in Kansas. In New York, all of the acreage was acquired after the Ralph E. Davis Associates, Inc. reserve report was calculated and, therefore, the 11 drilling locations are not part of such reserve report. The drilling locations on which we actually drill will depend on the availability of capital, regulatory approval, commodity prices, costs, actual drilling results and other factors. Please see “Risk Factors — Risks Related to Our Business — Our gross identified drilling locations are scheduled out over a number of years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our identified drilling locations.”

(3)

Calculated by dividing our gross identified drilling locations by the number of wells we expect to drill in 2014.

The following table provides a summary of our drilling results (gross and net) for the first quarter of 2014 and for the years ended December 31, 2013, 2012 and 2011.


	Q1 2014				2013				2012				2011
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Exploratory Wells:
Productive		2		2		—		—		—		—		—		—
Dry		—		—		3		2		2		1		—		—
Total Exploratory		2		2		3		—		2		—		—		—
Development Wells:
Productive		—		—		5		4		6		4		6		4
Dry		—		—		—		—		—		—		—		—
Total Development		—		—		5		4		6		4		6		4
Total Wells:
Productive		2		2		5		4		6		4		6		4
Dry		—		—		3		2		2		1		—		—
Total		2		2		8		6		8		5		6		4

Our estimate of proved reserves is prepared by Ralph E. Davis Associates, Inc. for Appalachia and LaRoche Petroleum Consultants, Ltd. for Mid-Con. As of January 1, 2014, we had 7.7 MBoe of proved reserves, of which 39% was oil and 61% was natural gas. As of January 1, 2014, the PV-10 of our proved reserves was approximately $102.5 million, 88% of which was attributed to proved developed reserves. The following table provides information regarding our reserves and production by area as of January 1, 2014, except as otherwise noted below:


Estimated Total Proved Reserves and Production
	2013
	Reserves								Production
Region	Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)		PV-10⁽¹⁾ (in thousands)		Average Net Daily Production (Boe/D)
Reserve Category
Proved Developed:
Mid-Con		2,599		235		2,638	$	63,361		447
Appalachia		61		27,098		4,577		26,357		896
Undeveloped:
Mid-Con		427		130		449		12,784		—
Appalachia		—		—		—		—		—
Total Proved		3,087		27,463		7,664	$	102,502		1,343
Probable		645		130		667	$	17,732		—
Possible		369		—		369		8,575		—

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(1)

PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure on a pre-tax basis. PV-10 is equal to the standardized measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure. Our PV-10 measure and the standardized measure do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV-10 to the standardized measure for our proved reserves at December 31, 2013, 2012 and 2011:


	Pro Forma As of December 31, 2013	2013		Historical As of December 31, 2012		2011
	(In thousands)
PV-10	$	$	102,502	$	114,351	$	124,944
Present value of future income taxes discounted at 10%			38,826		39,221		37,912
Standardized Measure⁽¹⁾	$	$	68,676	$	75,130	$	87,032

(1)

Standardized measure is calculated in accordance with Accounting Standards Codification (“ASC”) Topic 932, Extractive Activities — Oil and Gas.

Of the more than 2,000 producing wells in the Mid-Con and Appalachian Basins, many of these wells have participating partners, referred to as Working Interest (WI) owners, which were owners prior to our purchase of the particular assets. The rights and obligations of both parties are clearly defined, governed and protected by a Joint Operating Agreement (JOA). Each WI owner participates financially in a well based on their percentage ownership and pays their proportionate share of the costs to drill and operate the well. Their Net Revenue Interest is their WI percentage less their proportionate share of any royalties. We and the existing partners continue to live within the conditions of these JOAs, to prudently produce, develop and operate the asset in a manner that is mutually beneficial to all parties. To date, there have been no disagreements or litigation concerning JOA operations, and none are anticipated.

Competitive Strengths

We possess a number of competitive strengths that we believe will help us to successfully execute our business strategies, including:

•

High caliber management team with substantial technical and operational expertise. Our management team has an average of over 20 years of industry experience. We believe our management and technical team is one of our principal competitive strengths due to our team's industry experience and history of working together in the identification, execution and integration of acquisitions, cost efficient management of profitable, large scale drilling programs and disciplined allocation of capital focused on rates of return.

•

Long lived assets with low development and production risk, generates consistent cash flow. Wells in the Mid-Con and Appalachian have a low development risk and maintain consistent production for a 30 to 40 year time frame. Our natural gas wells are located near end-user markets and consistently receive premium prices over wells located on the Gulf coast and require little maintenance, thus generating consistent cash flows.

•

High quality asset base with significant oil exposure in the Mid-Con. We have intentionally focused on crude oil opportunities to benefit from the relative disparity between oil and natural gas prices on an energy-equivalent basis, which has persisted over the last several years and which we

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expect to continue in the future. Approximately 39% of our proved reserves was oil as of December 31, 2013, and 33% of our daily production for the year ended December 31, 2013 was oil.

•

Attractive returns on relatively low risk, 3D seismic generated oil drilling targets in the Mid-Continent basin. Based on our own drilling experience and wells drilled by the previous owners, a typical Arbuckle well is expected to produce a gross EUR of 20.7 MBbls of oil, an internal rate of return of 66%, with an initial production rate of 642Bbl/month and a well cost of $350,000. The economics are based on the April 28, 2014 NYMEX price strip, and costs based on the Company’s experience with new wells. This excludes any up-hole producing formations (Lansing/Kansas City).

•

Large, concentrated acreage position with significant operational control in Appalachia. We currently have 232,305 acres in the Marcellus Shale fairway and 148,311 acres in the Utica Shale fairway. 84% of it is held by production. These fairways were defined by previous drilling and vertical and geological delineation. Horizontal drilling and fracking technology has continued to advance in other parts of the Marcellus and Utica Shales, resulting in increased EURs and reduced well costs in the shale industry. Fracking has proven to be very successful in major shale plays in the Marcellus and Utica Shales in nearby States of Pennsylvania, West Virginia and Ohio. As a result of the New York fracking moratorium, the Company has not been able to develop the most lucrative aspects of its holdings. A regional study done by Ralph E. Davis Associates, Inc. shows that the Company holds acreage in the Marcellus and Utica fairways that should be favorable for oil and gas exploration.

•

Access to multiple takeaway pipelines. We have the ability to move natural gas to several different pipelines depending upon demand, capacity, and price in order to maximize revenue. Demand for natural gas in local markets is seasonal. When demand is low in these markets, we are able to move gas to interstate markets, thus avoiding the necessity to shut in our wells.

Business Strategies

We maintain a disciplined and analytical approach to investing in which we seek to direct capital in a manner that will maximize our rates of return as we develop our extensive resource base. Key elements of our strategy are:

•

Grow reserves, production and cash flow with low-risk vertical drilling. We have considerable experience managing drilling programs and intend to efficiently develop our acreage position to maximize the value of our resource base. In the Mid-Con by utilizing 3D seismic we are able to accurately generate oil drilling targets. Over 2013 we undertook several 3D seismic programs on existing and new acreage acquired in previous years and commenced investment in a new drilling program. During 2013 we invested $1.3 million of development capital and drilled five gross (four net) development wells and three gross (2.5 net) exploration wells, the latter of which were dry holes. Based on our own development drilling experience, a generic Arbuckle well at a well cost of $350,000 is expected to produce an internal rate of return of around 66% with an initial gross production rate of 640 Bbl/month. This excludes any reserves and production for up-hole producing formations (such as the Lansing/Kansas City formations).

•

Evaluate and pursue oil-weighted acquisitions where we can add value through our technical expertise and knowledge of the Mid-Con basin. We have experience acquiring and developing oil-weighted properties in the Mid-Con region, and we expect to continue to selectively acquire additional properties in the Mid-Con region that meet our rate-of-return objectives. Since our formation, we have completed one significant acquisition that has given us a unique and highly attractive acreage position, underpinned by strong baseline production and proved reserves. We believe our experience as a leading operator and our infrastructure footprint in the Mid-Con region provide us with a competitive advantage in successfully executing and integrating acquisitions.

•

Continuously improve capital and operating efficiency. We continuously focus on optimizing the development of our resource base by seeking ways to maximize our recovery per well relative to the

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cost incurred and to minimize our operating cost per Mcfe produced. We apply an analytical approach to track and monitor the effectiveness of our drilling and completion techniques and service providers. Additionally, we seek to build infrastructure that allows us to achieve economies of scale and reduce operating costs. Specifically, we purchased 166 miles of gathering lines in New York to enhance our New York gas production. We continue to identify opportunities to increase our pipeline networks in New York to ensure transportation cost control and taps into alternative pipeline networks.

•

Strategic natural gas production, pipeline and acreage acquisition in Appalachia. We have experience acquiring and operating natural gas gathering and transportation pipelines in New York and Pennsylvania. Any consolidation of existing conventional gas producers in Appalachia may provide opportunities for us to acquire assets providing our required rate-of-return gas production objectives as well as providing control over the transportation of our own gas to either regional utilities or major pipeline taps.

•

Maintain a disciplined, growth-oriented financial strategy. We intend to fund our growth predominantly with internally generated cash flows while maintaining ample liquidity and access to capital markets. Substantially all of our lease terms allow us to allocate capital among projects in a manner that optimizes both costs and returns, resulting in a highly efficient drilling program. In addition, these terms allow us to adjust our capital spending depending on commodity prices and market conditions. We expect our cash flows from operating activities, availability under our credit agreement and the net proceeds of this offering to be sufficient to fund our capital expenditures and other obligations necessary to execute our business plan in 2014. Furthermore, for future PDP heavy acquisitions, as we have done in the past, we plan to hedge a significant portion of known production in order to stabilize our cash flows and maintain liquidity. This will allow us to sustain a planned debt repayment program and allow a consistent drilling program, with hedging of new production based on circumstances at the time, thereby preserving operational efficiencies that help us achieve our targeted rates of return.

•

Monetize our New York land holdings if the New York fracking moratorium is lifted. We currently have 232,305 acres in the Marcellus Shale fairway and 148,311 acres in the Utica Shale fairway. These fairways were defined by previous drilling and vertical and geological delineation. Horizontal drilling and fracking technology has continued to advance in other parts of the Marcellus and Utica Shales, resulting in increased EURs and reduced well costs. Fracking has proven to be very successful in major shale plays in the Marcellus and Utica Shales in nearby States of Pennsylvania, West Virginia and Ohio. As a result of the New York fracking moratorium, the Company has not been able to develop the most lucrative aspects of its holdings. A regional study done by Ralph E. Davis Associates, Inc. shows that the Company holds acreage in the Marcellus and Utica fairways that should be favorable for oil and gas exploration.

Recent Developments

Our Capital Restructuring Program. Pursuant to a plan of conversion, as soon as practicable after the effectiveness of the registration statement of which this prospectus is a part, Imperial Resources, LLC (“Imperial”) will file a certificate of conversion, the form of which is filed as an exhibit to the registration statement of which this prospectus is part (the “Certificate of Conversion”), with the Secretary of State of the State of Delaware, pursuant to which Imperial will convert into a Delaware corporation and continue in the name of Empire Energy Holdings, Inc. (the “Corporate Reorganization”). Upon the filing of the Certificate of Conversion, the sole membership percentage interest of Empire Energy Group Limited (“Empire Energy Group“) in Imperial issued and outstanding immediately prior to the Corporate Reorganization will be converted automatically into shares of common stock of the Company, par value $0.01, with such shares of common stock having the respective rights, preferences and privileges set forth in the certificate of incorporation of the Company, the form of which is filed as an exhibit to the registration statement of which this prospectus is a part. The membership percentage interest outstanding immediately prior to the effective time of the conversion shall be converted automatically, without any action on the part of the holder thereof, into validly issued, fully paid and non-assessable shares of the Company’s common stock.

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Second Quarter 2014 Drilling and Production. We plan to drill one Bass Island Reef (NY) oil well and at least 10 gross Upper Devonian Bradford Group (NY) oil and liquids rich wells in the Appalachian Basin, in addition to four gross oil wells in the Mid-Con as operator. We expect production in the Mid-Con to be flat to slightly higher in the second quarter, compared to the first quarter. We expect increases to begin to occur in the latter half of the second quarter as newly identified projects are completed. These projects will consist of low cost, clean out and stimulation jobs. The weather in the Appalachian Basin was extremely cold this past winter which caused production issues including well freeze offs. We expect production in the Appalachian Basin to increase slightly in the second quarter because of the warming weather.

Our business is subject to numerous risks, as more fully described in the section entitled “Risk Factors” immediately following this prospectus summary. You should read and carefully consider these risks, together with all of the other information in this prospectus, including the financial statements and the related notes included elsewhere in this prospectus, before deciding whether to invest in our common stock. If any of the risks discussed in this prospectus actually occur, our business, financial condition, operating results or cash flows could be materially adversely affected.

Implications of Being an Emerging Growth Company

We qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012. As an emerging growth company, we may take advantage of specified reduced disclosure and other requirements that are otherwise applicable generally to public companies. See “Risk Factors — For as long as we are an emerging growth company, we will not be required to comply with certain requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.” These provisions include:

•

only two years of audited financial statements in addition to any required unaudited interim financial statements with correspondingly reduced “Management’s Discussion and Analysis of Financial Condition and Results of Operations” disclosure;

•

reduced disclosure about our executive compensation arrangements;

•

no non-binding advisory votes on executive compensation or golden parachute arrangements;

•

waiver of the compliance with any new requirements adopted by the Public Company Accounting Oversight Board, or the “PCAOB”; and

•

exemption from the auditor attestation requirement in the assessment of our internal control over financial reporting.

We may choose to take advantage of some but not all of these exemptions. We have also taken advantage of reduced reporting requirements in this prospectus. Accordingly, the information contained herein may be different than the information you receive from other public companies in which you hold stock.

We have elected to use the extended transition period for complying with new or revised accounting standards under Section 102(b)(1) of the JOBS Act. This election allows us to delay the adoption of new or revised accounting standards that have different effective dates for public and private companies until those standards apply to private companies. As a result of this election, our financial statements may not be comparable to companies that comply with public company effective dates.

We will remain an emerging growth company until the earlier of (1) the last day of the fiscal year (a) following the fifth anniversary of the completion of this offering, (b) in which we have total annual gross revenue of at least $1.0 billion, or (c) in which we are deemed to be a large accelerated filer, which means the market value of our common stock that is held by non-affiliates exceeded $700.0 million as of the prior June 30^th, and (2) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three-year period.

We refer to the Jumpstart Our Business Startups Act of 2012 in this prospectus as the “JOBS Act,” and references in this prospectus to “emerging growth company” have the meaning associated with it in the JOBS Act.

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Notwithstanding the above, we are also currently a “smaller reporting company” meaning that we are not an investment company, an asset-backed issuer, or a majority-owned subsidiary of a parent company that is not a smaller reporting company and have a public float of less than $75 million and annual revenues of less than $50 million during the most recently completed fiscal year. In the event that we are still considered a smaller reporting company, at such time that we cease being an emerging growth company, the disclosure we will be required to provide in our Securities and Exchange Commission (“SEC”) filings will increase, but will still be less than it would be if we were not considered either an emerging growth company or a smaller reporting company. Specifically, similar to emerging growth companies, smaller reporting companies are able to provide simplified executive compensation disclosures in their filings; are exempt from the provisions of Section 404(b) of the Sarbanes-Oxley Act of 2002 requiring that independent registered public accounting firms provide an attestation report on the effectiveness of internal control over financial reporting; and have certain other decreased disclosure obligations in their SEC filings, including, among other things, only being required to provide two years of audited financial statements in annual reports.

Corporate Reorganization

Prior to the completion of the Corporate Reorganization, Imperial is a wholly-owned subsidiary of Empire Energy Group, a corporation listed on the Australian Securities Exchange under the symbol “EEG,” and its American Depository Receipts (“ADRs”) are traded on the OTCQX under the symbol “EEGNY”. While Empire Energy Group will continue to have its ADRs traded on the OTCQX, we desire to separate the U.S. operating assets from the large scale Australian frontier exploration assets and benefit from increased liquidity in the U.S. markets by listing separately on The NASDAQ Capital Market (“NASDAQ”).

The diagram below sets forth our simplified organizational structure prior to the Corporate Reorganization:

[GRAPHIC MISSING]

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Pursuant to a plan of conversion, as soon as practicable after the effectiveness of the registration statement of which this prospectus is a part, Imperial will file a Certificate of Conversion, the form of which is filed as an exhibit to the registration statement of which this prospectus is a part with the Secretary of State of the State of Delaware, pursuant to which Imperial will convert into a Delaware corporation and continue in the name of Empire Energy Holdings, Inc. Upon the filing of the Certificate of Conversion, the sole membership percentage interest of Empire Energy Group in Imperial issued and outstanding immediately prior to the Corporate Reorganization will be converted automatically into shares of common stock of the Company, par value $0.01, with such shares of common stock having the respective rights, preferences and privileges set forth in the certificate of incorporation of the Company, the form of which is filed as an exhibit to the registration statement of which this prospectus is a part. The membership percentage interest outstanding immediately prior to the effective time of the conversion shall be converted automatically, without any action on the part of the holder thereof, into validly issued, fully paid and non-assessable shares of the Company’s common stock.

The certificate of incorporation and bylaws of the Company after the Corporate Reorganization will contain customary provisions for public companies.

The corporate structure of the Company following the Corporate Reorganization and this offering will be as follows:

[GRAPHIC MISSING]

(1)

Will include shares to be beneficially owned by Macquarie Americas Corp. in connection with exercise of its warrants. See “Principal Stockholders.”

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Corporate Information

Our principal executive offices are located at 380 Southpointe Boulevard, Suite 130, Canonsburg, Pennsylvania 15317, and our telephone number is (724) 483-2070. Our website is www.empireenergygroup.net. We expect to make our periodic reports and other information filed with or furnished to the SEC available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. The information contained in, or otherwise accessible through, our website or any other website does not constitute a part of this prospectus.

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THE OFFERING

Common stock offered by us:

shares.

Common stock to be outstanding after the offering⁽¹⁾:

shares.

Underwriters’ over-allotment option:

The Underwriting Agreement provides that we granted to Maxim Group LLC, the sole book-running manager of the offering, an option, exercisable within 45 days after the closing of this offering, to acquire up to an additional shares, solely for the purpose of covering over-allotments.

Use of proceeds:

We estimate that the net proceeds to us from this offering will be approximately $ (or $ if the underwriters exercise their over-allotment option in full), assuming an initial public offering price of $ per share (the midpoint of the price range set forth on the cover page of this prospectus) after deducting the underwriting discounts and commissions and estimated offering expenses payable by us.

We currently expect to use the net proceeds from this offering for future acquisitions and drilling, to fund a portion of our capital expenditure plan and for general corporate purposes. Pending such usage, we expect to invest the proceeds in short-term interest-bearing instruments. See “Use of Proceeds” below.

Dividend policy:

We do not anticipate paying any cash dividends on our common stock. In addition, certain of our debt instruments place restrictions on our ability to pay cash dividends. See “Dividend Policy.”

Risk factors:

You should carefully read and consider the information set forth under the heading “Risk Factors” and all other information set forth in this prospectus before deciding to invest in our common stock.

Lock-up:

We, our directors, executive officers and certain of our existing stockholders have agreed with the underwriters not to offer, issue, sell, contract to sell, encumber, grant any option for the sale of or otherwise dispose of any of our securities for a period of 180 days following the closing of the offering of the common stock, subject to certain exceptions. See “Underwriting” for more information.

Listing and trading symbol:

We have applied for listing of our common stock on The NASDAQ Capital Market under the symbol “EEHI.”

(1)

The number of shares of our common stock that will be outstanding immediately after this offering is based on shares of common stock of the Company outstanding as of , 2014 as if the membership interest percentage outstanding as of such date was converted pursuant to the Corporate Reorganization.

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Except for historical financial information or as otherwise indicated herein, all information in this prospectus, including the number of shares that will be outstanding after this offering, assumes or gives effect to:

•

no exercise by the underwriters of their option to purchase up to additional shares of our common stock from us in this offering;

•

no exercise of the Representative’s Warrants; and

•

our Corporate Reorganization in connection with this offering.

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SUMMARY CONSOLIDATED FINANCIAL DATA

The following table summarizes the historical consolidated balance sheet data, statements of operations data and statements of cash flows data (i) as of and for the years ended December 31, 2012 and 2013 derived from, and qualified by reference to, the audited consolidated financial statements of Imperial included elsewhere in this prospectus, and (ii) as of and for the three months ended March 31, 2013 and 2014 derived from, and qualified by reference to, the unaudited consolidated financial statements of Imperial included elsewhere in this prospectus. The financial data of Imperial, a holding company, are inclusive of its wholly owned subsidiaries Empire Energy USA, LLC and Empire Energy E&P, LLC. The summary financial data presented below should be read in conjunction with the financial statements and notes thereto and “Selected Historical Consolidated Financial Data,” “Capitalization” and “Management's Discussion and Analysis of Financial Condition and Results of Operations.”

The summary unaudited pro forma consolidated balance sheet data as of March 31, 2014 and the statements of operations data and statements of cash flows data for the year ended December 31, 2013 and the three months ended March 31, 2014 have been prepared to give pro forma as adjusted effect to (i) the Corporate Reorganization, pursuant to which Imperial will be converted into the Company and its only direct holdings will be Empire Energy USA, LLC, and (ii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2013 or 2014, as applicable. The summary unaudited pro forma consolidated financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the Corporate Reorganization and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any further date or for any future period.

Revenues in the following table do not include well operations service fees although these fees are included in revenues as disclosed in the financial statements of Imperial included elsewhere in this prospectus.


	Imperial Resources, LLC (Actual)												Empire Energy Holdings, Inc. (Pro Forma)
	Three Months Ended March 31,						Year Ended December 31,						Three Months Ended March 31,	Year Ended December 31,
	2014			2013			2013			2012			2014	2013
	(Unaudited)												(Unaudited)
	(In thousands, except per unit data)
Statement of operations data:
Revenues:
Oil sales	$	3,639		$	3,849		$	15,276		$	16,245
Natural gas sales		1,973			1,831			7,566			5,770
Oil and gas price risk		112			552			2,135			4,259
Total revenues		5,725			6,231			24,977			26,273
Operating expenses:
Lease operating		2,477			2,726			9,257			9,283
Production, severance and ad valorem taxes		98			533			1,163			858
Exploratory dry hole costs		18			—			729			197
General and administrative		593			638			3,463			3,431
Depreciation, depletion and amortization		1,395			1,246			5,854			5,435
Write-down on abandoned leases		—			42			152			1,027
Total operating expenses		4,582			5,185			20,619			20,231
Operating income		1,143			1,046			4,358			6,043
Interest income (expense) — non-cash		(110	)		(662	)		(2,165	)		(6,099	)
Interest income (expense) — cash		(498	)		(578	)		(2,216	)		(2,728	)
Other income (expense)		(225	)		56			143			(243	)
Income tax (expense) benefit		(112	)		46			(30	)		2,188
Net income (loss)	$	198		$	(93	)	$	91		$	(839	)

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	Imperial Resources, LLC (Actual)												Empire Energy Holdings, Inc. (Pro Forma)
	Three Months Ended March 31,						Year Ended December 31,						Three Months Ended March 31,	Year Ended December 31,
	2014			2013			2013			2012			2014	2013
	(Unaudited)												(Unaudited)
	(In thousands, except per unit data)
Net cash provided by (used in):
Operating activities	$	473		$	2,005		$	9,224		$	15,794
Investing activities		(769	)		(434	)		(3,162	)		(4,246	)
Financing activities		959			(2,114	)		(8,226	)		(8,745	)
Other financial data (unaudited):
Adjusted EBITDAX⁽¹⁾	$	2,331		$	2,375		$	11,179		$	12,651
Earnings per unit – basic		—			—			—			—
Earnings per unit – diluted		—			—			—			—


	As of March 31,			As of December 31,
	2014		2014 Pro Forma As Adjusted	2013
	(Unaudited)
	(In thousands)
Balance sheet data:
Cash	$	2,782	$	$	2,118
Total property and equipment, net		97,091			97,518
Total assets		113,608			113,606
Total debt		49,884			49,846
Total members'/Members' capital		41,860			42,273

(1)

Adjusted EBITDAX is a non-GAAP financial measure. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss), see “— Non-GAAP Financial Measures” below.

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Non-GAAP Financial Measures

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies.

We define Adjusted EBITDAX as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion and amortization; amortization of deferred financing costs; equity in (income) loss in a joint venture; non-cash compensation expense; gain from sale of interest in gas properties; and exploration expenses. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

Management believes Adjusted EBITDAX is useful because it allows them to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.

The following tables present a reconciliation of the non-GAAP financial measure of Adjusted EBITDAX to the GAAP financial measure of net income (loss).


	Three Months Ended March 31,					Year Ended December 31,
	2014		2013			2013			2012
	(Unaudited)
	(In thousands)
Consolidated net income (loss)	$	198	$	(93	)	$	91		$	(839	)
Income tax expense		112		(46	)		30			(2,198	)
Interest expense		527		551			3,497			4,750
Depreciation, depletion and amortization		1,194		1,081			5,050			4,734
Accretion		201		165			805			701
Exploration expenses		18		—			729			197
Discount on debt		40		508			579			2,971
Amortization of deferred financing costs		41		182			305			1,106
Equity income in joint ventures		—		(15	)		(86	)		—
Expiration of expired leases		—		42			152			1,027
Loss on disposal of property, plant and equipment		—		—			28			193
Adjusted EBITDAX	$	2,331	$	2,375		$	11,179		$	12,651

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SUMMARY RESERVE AND OPERATING DATA

The tables present, as of the dates indicated, summary data with respect to our estimated net proved oil and natural gas reserves and operating data.

The reserve estimates attributable to our properties at December 31, 2013 and 2012 presented in the table below are based on a reserve report prepared by Ralph E. Davis Associates, Inc. for Appalachia and LaRoche Petroleum Consultants, Ltd. for Mid-Con. All of these reserve estimates were prepared in accordance with the SEC's rules regarding oil and natural gas reserve reporting that are currently in effect. The following tables also contain summary unaudited information regarding production and sales of oil and natural gas with respect to such properties. For more information about our proved reserves as of December 31, 2013 and 2012, please read Ralph E. Davis Associates, Inc.’s and LaRoche Petroleum Consultants, Ltd.’s reports, which have been filed as exhibits to the registration statement of which this prospectus is a part.

Please read “Management's Discussion and Analysis of Financial Condition and Results of Operations” and “Business — Oil and Natural Gas Reserves” in evaluating the material presented below.


	As of December 31,
	2013			2012
Reserve Data
Estimated proved reserves⁽¹⁾:
Oil (MBbls)		3,087			3,370
Natural gas (MMcf)		27,463			34,730
Total estimated proved reserves (MBoe)		7,664			9,159
Proved developed reserves (MBoe)		7,215			8,571
% proved developed reserves (MBoe)		94	%		94	%
Proved undeveloped reserves (MBoe)		449			588
PV-10 of proved reserves⁽²⁾ (in 000s)	$	102,502		$	114,351

(1)

Our estimated net proved reserves were determined using a 12-month average price for oil and natural gas. The prices used in our reserve reports yield weighted average wellhead prices, which are based on index prices and adjusted for energy content, transportation fees and regional price differentials. The index prices and the equivalent wellhead prices are shown in the table below.

(2)

PV-10 is a non-GAAP financial measure. For a definition of PV-10 and a reconciliation of PV-10 to the standardized measure of discounted future net cash flows, see the Estimated Total Proved Reserves and Production table in “Prospectus Summary — Our Company” on page 3.


	Oil				Natural gas
Mid-Con	Index Price (per Bbl)		Weighted Average Wellhead Price (per Bbl)		Index Price (per MMBtu)		Weighted Average Wellhead Price (per Mcf)
December 31, 2013	$	96.94	$	91.44	$	3.67	$	4.94
December 31, 2012		93.19		82.34		3.56		6.74


	Oil				Natural gas
Appalachia	Index Price (per Bbl)		Weighted Average Wellhead Price (per Bbl)		Index Price (per MMBtu)		Weighted Average Wellhead Price (per Mcf)
December 31, 2013	$	86.11	$	80.62	$	4.21	$	4.76
December 31, 2012		87.74		85.46		4.39		5.27

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Production, Revenues and Price History

The following table sets forth information regarding production, revenues and realized prices, and production costs for the year ended December 31, 2013 and for the three months ended March 31, 2014. Revenues in the following table do not include well operations service fees although these fees are included in revenues as disclosed in the financial statements of Imperial included elsewhere in this prospectus.


	For the Year Ended December 31, 2013		For the Three Months Ended March 31, 2014
Revenues (In thousands):
Oil sales	$	15,276	$	3,639
Natural gas sales		7,566		1,973
Oil and gas price risk		2,135		112
Total revenues	$	24,977	$	5,725
Production and operating data:
Net production volumes:
Oil (MBbls)		165		39
Natural gas (MMcf)		1,954		418
Total (MBoe)		490		109
Average daily production volume:
Oil (Bbls/D)		451		437
Natural gas (Mcf/D)		5,354		4,643
Combined (Boe/D)		1,343		1,210
Average realized price before effects of hedges:⁽¹⁾
Oil ($/Bbl)	$	92.85	$	92.62
Natural gas ($/Mcf)		3.87		4.72
Combined ($/Boe)	$	46.59	$	51.52
Average realized price after effects of hedges:⁽¹⁾
Oil ($/Bbl)	$	86.53	$	86.82
Natural gas ($/Mcf)		5.50		5.54
Combined ($/Boe)	$	50.95	$	52.55
Operating expenses (per Boe):
Production:
Lease operating	$	18.88	$	22.74
Production, severance and ad valorem taxes		2.37		0.90
General and administrative⁽²⁾		7.06		5.45
Depletion, depreciation and amortization		11.94		12.81
Write-down on abandoned leases		0.31		0.00

(1)

Average prices shown in the table reflect prices both before and after the effects of our realized commodity hedging transactions. Our calculation of such effects includes both realized gains or losses on cash settlements for commodity derivative transactions.

(2)

General and administrative expenses do not include additional expenses we would have incurred as a result of being a public company.

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RISK FACTORS

An investment in our common stock involves a high degree of risk. You should consider carefully the specific risk factors described below in addition to the other information contained in this prospectus, including our consolidated financial statements and related notes included elsewhere in the prospectus, before making your investment decision. If any of these risks actually occurs, our business, financial condition, results of operations or prospects could be materially and adversely affected. This could cause the trading price of our common stock to decline and you could lose all or part of your investment. Our actual results could differ materially from those anticipated in the forward-looking statements made throughout this prospectus as a result of different factors, including the risks described below.

Natural gas, NGL and oil prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

The prices we receive for our natural gas, NGL and oil production will heavily influence our revenue, operating results profitability, access to capital, future rate of growth and carrying value of our properties. Natural gas, NGLs and oil are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. This market 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 the following:

•

worldwide and regional economic conditions impacting the global supply of and demand for natural gas, NGLs and oil;

•

the price and quantity of imports of foreign natural gas, including liquefied natural gas;

•

political conditions in or affecting other producing countries, including conflicts in the Middle East, Africa, South America and Russia;

•

the level of global exploration and production;

•

the level of global inventories;

•

prevailing prices on local price indexes in the areas in which we operate and expectations about future commodity prices;

•

the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;

•

localized and global supply and demand fundamentals and transportation availability;

•

severe weather conditions;

•

natural disasters;

•

technological advances affecting energy consumption;

•

the cost of exploring for, developing, producing and transporting reserves;

•

speculative trading in natural gas and crude oil derivative contracts;

•

the price and availability of competitors’ supplies of natural gas and oil and alternative fuels; and

•

domestic, local and foreign governmental regulation and taxes.

Furthermore, the worldwide financial and credit crisis in recent years has reduced the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide resulting in a slowdown in economic activity and recession in parts of the world. This has reduced worldwide demand for energy and resulted in lower natural gas, NGL and oil prices.

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In addition, all of our natural gas production is sold to purchasers under contracts with market-based prices based on New York Mercantile Exchange (“NYMEX”) Henry Hub prices. The actual prices realized from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of location differentials. Location differentials to NYMEX Henry Hub prices, also known as basis differential, result from variances in regional natural gas prices compared to NYMEX Henry Hub prices as a result of regional supply and demand factors. We may experience differentials to NYMEX Henry Hub prices in the future, which may be material.

Also, all of our oil production is sold to purchasers under contracts with market-based prices based on NYMEX — WTI prices. The actual prices realized from the sale of oil differ from the quoted NYMEX — WTI price as a result of location and specific gravity differentials. These differentials to NYMEX — WTI prices, also known as basis differential, result from variances in regional oil prices compared to NYMEX — WTI prices as a result of regional supply and demand factors. We may experience differentials to NYMEX — WTI prices in the future, which may be material.

Lower commodity prices and negative increases in our differentials will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of natural gas, NGLs and oil that we can produce economically.

If commodity prices further decrease or our negative differentials further increase, a significant portion of our development and exploration projects could become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. As a result, a substantial or extended decline in commodity prices or an 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.

Our development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our natural gas reserves.

We make and expect to continue to make substantial capital expenditures for the development and acquisition of oil and natural gas reserves. In 2014, we plan to invest at least $5.0 million in our operations, including $3.6 million for drilling and completion of oil targets in the Mid-Con and $1.4 million for drilling and completion of newly identified oil targets in Appalachia. Our capital budget excludes acquisitions for which we have unutilized revolving and term loan credit facilities availability of up to $160 million, subject to lender approval. We expect to fund our 2014 capital expenditures with cash generated by operations, borrowings under our revolving credit facility and a portion of the net proceeds of this offering. Our 2014 capital expenditure budget also assumes that utilization of around $10 million availability of borrowing base under our revolving credit facility. If our lenders do not make available additional capacity under our borrowing base or other credit facilities available for acquisitions we may seek alternate debt financing or reduce our capital expenditures. In addition, a portion of our 2014 capital budget is projected to be financed with cash flows from operations derived from wells drilled on drilling locations not associated with proved reserves in our 2014 reserve report (see “Recent Developments — Second Quarter 2014 Drilling and Production”). The failure to achieve projected production and cash flows from operations from such wells could result in a reduction to our 2014 capital budget. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil or natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in oil or natural gas prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production. We intend to finance our future capital expenditures primarily through cash flow from operations and through borrowings under our revolving credit facilities; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.

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Our cash flow from operations and access to capital is subject to a number of variables, including:

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our proved reserves;

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the level of hydrocarbons we are able to produce from existing wells;

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the prices at which our production is sold;

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our ability to acquire, locate and produce new reserves;

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the levels of our operating expenses; and

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our ability to borrow under either our revolving credit or term loan facilities.

If our revenues or the borrowing base under our credit facilities decrease as a result of lower oil or 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. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our credit facilities are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could result in a total loss of investment or otherwise adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas production, that we will not recover all or any portion of our investment in such wells or that various characteristics of the well will cause us to plug or abandon the well prior to producing in commercially viable quantities.

Our decisions to purchase, explore or develop 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. For a discussion of the uncertainty involved in these processes, see “— Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

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delays imposed by or resulting from compliance with regulatory requirements including limitations resulting from wastewater disposal, discharge of greenhouse gases, and limitations on fracking;

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pressure or irregularities in geological formations;

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shortages of or delays in obtaining equipment and qualified personnel or in obtaining water for fracking activities;

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equipment failures, accidents or other unexpected operational events;

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inability to deliver produced oil to a refinery;

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lack of available gathering facilities or delays in construction of gathering facilities;

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lack of available capacity on interconnecting transmission pipelines;

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adverse weather conditions, such as blizzards and ice storms;

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issues related to compliance with environmental regulations;

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environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

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declines in oil or natural gas prices;

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limited availability of financing at acceptable terms;

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title problems; and

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limitations in the market for oil, natural gas or any other derivatives.

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties.

We have incurred losses from operations for various periods since our inception and may do so in the future.

We have incurred non-cash net losses for various periods since our inception. Our development of and participation in an increasingly larger number of prospects has required and will continue to require substantial capital expenditures. The uncertainty and factors described throughout this “Risk Factors” section may impede our ability to economically find, develop and acquire oil or natural gas reserves. As a result, we may not be able to sustain profitability or positive cash flows from operating activities in the future, which could adversely affect the trading price of our common stock.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. In addition, any significant reduction in our borrowing base under the Revolver as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our ability to make scheduled payments on or to refinance our indebtedness obligations, including our $50.0 million secured revolving credit facility (the “Revolver”) and our $150.0 million acquisition and development term credit facility (the “Term Facility”), depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The Revolver currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

The Revolver limits the amounts we can borrow up to a borrowing base amount, which the lender, in its sole discretion, determines on a semi-annual basis based upon projected revenues from the natural gas properties securing our loan. The lender can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the Revolver. Any increase in the borrowing base requires the consent of the lender. The additional borrowing base availability under the Revolver is currently $10.0 million. Our next

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scheduled borrowing base redetermination is expected to occur in February 2015 or immediately after any acquisition that we may make. In the future, we may not be able to access adequate funding under the Revolver if the lender does not agree to an increase, or if the lender determines that the borrowing base should be lowered. The borrowing base may be lowered due to declines in commodity prices, issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Outstanding borrowings in excess of the borrowing base must be repaid, or we must pledge other natural gas properties as additional collateral after applicable grace periods. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make mandatory principal prepayments required under the Revolver.

Insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices.

The Appalachian Basin natural gas business environment has historically been characterized by periods in which production has surpassed local takeaway capacity, resulting in discounts in the price received by producers such as us. Although additional Appalachian Basin takeaway capacity has been added in 2012 and 2013, we do not believe the existing and expected capacity will be sufficient to keep pace with the increased production caused by accelerated drilling in the area. If we develop our potential natural gas resources and are unable to secure additional gathering and compression capacity and long-term firm takeaway capacity on major pipelines that are in existence or currently under construction in our core operating area to accommodate our growing production and to manage basis differentials, it could have a material adverse effect on our financial condition and results of operations.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

The Revolver and the Term Facility each contain a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:

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sell assets;

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make loans to others;

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make investments;

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enter into mergers;

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make certain payments;

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hedge future production or interest rates;

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incur liens;

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engage in certain other transactions without the prior consent of the lender; and

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pay dividends.

In addition, our credit facilities require us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of March 31, 2014, we are in compliance with our financial covenants; however, we cannot guarantee that we will be able to comply with such terms at all times in the future. Any failure to comply with the conditions and covenants in our financing agreements that is not waived by our lender or otherwise cured could lead to a termination of our facilities, acceleration of all amounts due under such facilities, or trigger cross-default provisions under other financing arrangements. These restrictions may limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the

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restrictive covenants under our credit facilities impose on us. While we intend to obtain consent from the lender to the Company regarding this offering, we do not have consent yet and we cannot guarantee that such consent will be received. Failure to obtain consent from the lender to the Company may result in a breach under our financing documents, which may have a material adverse impact on us.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

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 current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we must project production rates and 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 natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves will vary from our estimates. As a substantial portion of our reserve estimates are made without the benefit of a lengthy production history, any significant variance from the above assumption could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated natural gas reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.

Reserve estimates for fields that do not have a lengthy production history are less reliable than estimates for fields with lengthy production histories. Less production history may contribute to less accurate estimates of reserves, future production rates and the timing of development expenditures. A material and adverse variance of actual production, revenues and expenditures from those underlying reserve estimates would have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our gross identified drilling locations are scheduled out over a number of years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill our identified drilling locations.

Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the numerous drilling locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other identified drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. Further, certain of the horizontal wells we intend to drill in the future may require unitization with adjacent leaseholds controlled by third parties. If these third parties are unwilling to unitize such leaseholds with ours, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified.

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We are continually seeking to increase our stock of drilling locations through either lease acquisition or an ongoing seismic program. As of March 31, 2014, we had 165 gross (116 net) identified drilling locations. As a result of the limitations described above, we may be unable to drill many of our identified drilling locations. In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements in effect at December 31, 2012 and 2013, we based the discounted future net cash flows from our proved reserves on the 12-month first-day-of-the-month oil and natural gas average prices without giving effect to derivative transactions. Actual future net cash flows from our oil and natural gas properties will be affected by factors such as:

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actual prices we receive for oil and natural gas;

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actual cost of development and production expenditures;

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the amount and timing of actual production; and

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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 and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating standardized measure 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. As a limited liability company, our predecessor was not subject to federal taxation. Accordingly, our standardized measure does not provide for federal corporate income taxes because taxable income was passed through to its members. As a corporation, we will be treated as a taxable entity for federal income tax purposes and our future income taxes will be dependent on our future taxable income. Actual future prices and costs may differ materially from those used in the present value estimates included in this prospectus which could have a material effect on the value of our reserves.

We may incur losses as a result of title defects in the properties in which we invest.

Leases in the Mid-Con and Appalachian Basin are particularly vulnerable to title deficiencies due the long history of land ownership in the area, resulting in extensive and complex chains of title. In the course of acquiring the rights to develop oil and natural gas, it is standard procedure for us and the lessor to execute a lease agreement with payment subject to title verification. In most cases, we incur the expense of retaining lawyers to verify the rightful owners of the oil and gas interests prior to payment of such lease payment to the lessor. There is no certainty, however, that a lessor has valid title to their lease’s oil and gas interests. In those cases, such leases are generally voided and payment is not remitted to the lessor. As such, title failures may result in fewer net acres to us. Prior to the drilling of an oil or natural gas well, however, it is the normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest, which may adversely impact our ability in the future to increase production and reserves. Accordingly, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.

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The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At January 1, 2014, approximately 6% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 449 MBoe of estimated proved undeveloped reserves will require an estimated $10.0 million of development capital. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future natural gas reserves and production, and therefore our future cash flow and results of operations, 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 sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

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

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

Our derivative activities could result in financial losses or could reduce our earnings. In certain circumstances, we may have to purchase commodities on the open market or make cash payments under our hedging arrangements and these payments could be significant and expose us to other risks.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil or natural gas, we enter into derivative instrument contracts for a significant portion of our oil and natural gas production, including fixed-price swaps. As of December 1, 2013, we had entered into natural gas hedging contracts through December 2018 covering a total of approximately 4.9 Bcf (or approximately 53%) of our projected natural gas production at amounts ranging from $4.365 to $6.30 per MMBtu and oil hedging contracts through December 2017 covering a total of 285 MBbls (or approximately 53%) of our projected oil production at prices ranging from $85.23 to $90.00 per Bbl. For the period from January 1, 2014 until December 31, 2014, we have hedged approximately 1.3 Bcf (or approximately 72%) of our projected natural gas production at amounts ranging from $5.27 to $6.30 per MMBtu and 105 MBbls (or approximately 70%) of projected oil production at $90.00 per Bbl. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

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If our production is less than the volume commitments under our hedging arrangements, or if natural gas or oil prices exceed the price at which we have hedged our commodities, there may be an obligation to make cash payments to our hedge counterparties or purchase the volume difference at market prices, which could, in certain circumstances, be significant and expose us to the risk of financial loss. Derivative instruments also expose us to the risk of financial loss in some circumstances, including when there is an increase in the differential between the underlying price in the derivative instrument and actual prices received or there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. Derivatives we have currently entered into do not require cash collateral. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil and natural gas prices and interest rates. Our hedging transactions expose us to risk of financial loss if a counter-party fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counter-party’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract. As of March 31, 2014, the estimated fair value of our commodity derivative contracts was approximately $3.6 million. Any default by the counterparty to these derivative contracts, the lender to the Company, when they become due would have a material adverse effect on our financial condition and results of operations.

In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have an adverse effect on our financial condition.

The inability of our significant customers, on which we depend due to the small number of significant customers, to meet their obligations to us may adversely affect our financial results.

In addition to credit risk related to receivables from commodity derivative contracts, our principal exposures to credit risk are through joint interest receivables ($0.4 million at December 31, 2013) and the sale of our oil and natural gas production ($3.3 million in receivables at December 31, 2013), which we market predominantly to a single oil refinery and to a to a natural gas marketing company, respectively. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leased properties on which we wish to drill. We can do very little to choose who participates in our wells. We are also subject to credit risk due to concentration of our oil and natural gas receivables with an oil refinery and a natural gas marketing company. The largest purchaser of our oil during the three months ended March 31, 2014 purchased approximately 96% of our operated production and the largest purchaser of our natural gas during the three months ended March 31, 2014 purchased approximately 71% of our operated production. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities that could exceed current expectations.

Substantial costs, liabilities, delays and other significant issues could arise from environmental laws and regulations inherent in drilling and well completion, gathering, transportation, and storage, and we may incur substantial costs and liabilities in the performance of these types of operations. Our operations are subject to extensive federal, regional, state and local laws and regulations governing environmental protection, the discharge of materials into the environment and the security of chemical and industrial facilities. These laws include:

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Clean Air Act (“CAA”) and analogous state law, which impose obligations related to air emissions;

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Clean Water Act (“CWA”), and analogous state law, which regulate discharge of wastewaters and storm water from some our facilities into state and federal waters, including wetlands;

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Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), and analogous state law, which regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal;

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Resource Conservation and Recovery Act (“RCRA”), and analogous state law, which impose requirements for the handling and discharge of any solid and hazardous waste from our facilities;

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National Environmental Policy Act (“NEPA”), which requires federal agencies to study likely environmental impacts of a proposed federal action before it is approved, such as drilling on federal lands;

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Safe Drinking Water Act (“SDWA”), and analogous state law, which restrict the disposal, treatment or release of water produced or used during oil and gas development;

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Endangered Species Act (“ESA”), and analogous state law, which seek to ensure that activities do not jeopardize endangered or threatened animals, fish and plant species, nor destroy or modify the critical habitat of such species; and

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Oil Pollution Act (“OPA”) of 1990, which requires oil storage facilities and vessels to submit to the federal government plans detailing how they will respond to large discharges, requires updates to technology and equipment, regulates above ground storage tanks and sets forth liability for spills by responsible parties.

Various governmental authorities, including the EPA, the U.S. Department of the Interior, the Bureau of Indian Affairs and analogous state agencies and tribal governments, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, the imposition of stricter conditions on or revocation of permits, the issuance of injunctions limiting or preventing some or all of our operations, delays in granting permits and cancellation of leases.

There is inherent risk of the incurrence of environmental costs and liabilities in our business, some of which may be material, due to the handling of our products as they are gathered, transported, processed and stored, air emissions related to our operations, historical industry operations, and water and waste disposal practices. Joint and several, strict liability may be incurred without regard to fault under certain environmental laws and regulations, including CERCLA, RCRA and analogous state laws, for the remediation of contaminated areas and in connection with spills or releases of natural gas, oil and wastes on, under, or from our properties and facilities. Private parties may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage arising from our operations. Some sites at which we operate may be located near current or former third-party oil and natural gas operations or facilities, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could materially increase our compliance costs and the cost of any remediation that may become necessary. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us.

In March 2010, the EPA announced its National Enforcement Initiatives for 2011 to 2013, which includes “Assuring Energy Extraction Activities Comply with Environmental Laws.” According to the EPA’s website, “some techniques for natural gas extraction pose a significant risk to public health and the environment.” To address these concerns, the EPA’s goal is to “address incidences of noncompliance from natural gas extraction and production activities that may cause or contribute to significant harm to public health and/or the environment.” This initiative could involve a large scale investigation of our facilities and processes, and could lead to potential enforcement actions, penalties or injunctive relief against us.

Our business may be adversely affected by increased costs due to stricter pollution control equipment requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. Also, we might not be able to obtain or maintain from time to time all required environmental regulatory

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approvals for our operations. If there is a delay in obtaining any required environmental regulatory approvals, or if we fail to obtain and comply with them, the operation or construction of our facilities could be prevented or become subject to additional costs.

We are generally responsible for all liabilities associated with the environmental condition of our facilities and assets, whether acquired or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and divestitures, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses, which may not be covered by insurance. In addition, the steps we could be required to take to bring certain facilities into compliance could be prohibitively expensive, and we might be required to shut down, divest or alter the operation of those facilities, which might cause us to incur losses.

We make assumptions and develop expectations about possible expenditures related to environmental conditions based on current laws and regulations and current interpretations of those laws and regulations. If the interpretation of laws or regulations, or the laws and regulations themselves, change, our assumptions may change, and new capital costs may be incurred to comply with such changes. In addition, new environmental laws and regulations might adversely affect our products and activities, including drilling, processing, storage and transportation, as well as waste management and air emissions. For instance, federal and state agencies could impose additional safety requirements, any of which could affect our profitability. Further, new environmental laws and regulations might adversely affect our customers, which in turn could affect our profitability.

Changes in laws or government regulations regarding fracking could increase our costs of doing business, limit the areas in which we can operate and reduce our oil and natural gas production, which could adversely impact our business.

Fracking is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Fracking involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. Recently, there has been increased public concern regarding an alleged potential for fracking to adversely affect drinking water supplies, and proposals have been made to enact separate federal, state and local legislation that would increase the regulatory burden imposed on fracking. The SDWA regulates the underground injection of substances through the Underground Injection Control (“UIC”) program and exempts fracking from the definition of “underground injection.” Congress has in recent legislative sessions considered legislation to amend the SDWA, including legislation that would repeal the exemption for fracking from the definition of “underground injection” and require federal permitting and regulatory control of fracking, as well as require disclosure of the chemical constituents of the fluids used in the fracturing process. The U.S. Congress may consider similar SDWA legislation in the future.

In addition, EPA has asserted federal regulatory authority pursuant to the SDWA over certain fracking activities involving the use of diesel fuels and published draft permitting guidance in May 2012 addressing the performance of such activities using diesel fuels in those states where EPA is the permitting authority. On May 9, 2014, EPA issued an Advance Notice of Proposed Rulemaking (ANPR) under Section 8 of the Toxic Substances Control Act (TSCA) seeking public comment on the types of chemical information that could be reported and disclosed under TSCA, and the approaches to obtain this information on chemicals and mixtures used in hydraulic fracturing activities, including non-regulatory approaches. Comments must be submitted on or before September 18, 2014. Further, on October 21, 2011, the EPA announced its intention to propose federal Clean Water Act regulations by 2014 governing wastewater discharges from fracking and certain other natural gas operations. In addition, the U.S. Department of the Interior published a revised proposed rule on May 16, 2013, that would update existing regulation of fracking activities on federal lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water. The revised proposed rule was subject to an extended 90-day public comment period, which ended on August 23, 2013. The final rule has not yet been promulgated.

Presently, fracking is regulated primarily at the state level, typically by state oil and natural gas commissions and similar agencies. Along with several other states, Pennsylvania (where we conduct operations) has adopted laws and proposed regulations that require oil and natural gas operators to disclose

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chemical ingredients and water volumes used to frack wells, in addition to more stringent well construction and monitoring requirements. The chemical ingredient information is generally available to the public via online databases, and this may bring more public scrutiny to fracking operations. In addition, local governments may also adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or fracking activities in particular or prohibit the performance of well drilling in general or fracking in particular. The Pennsylvania Supreme Court, in Robinson Township v. Commonwealth of Pennsylvania, recently limited the ability to regulate such ordinances from a state-wide level, as well as the ability to require the enactment of local ordinances aiding drilling activities. Following this decision, local governments in Pennsylvania may increasingly adopt ordinances relating to drilling and fracking activities, especially within residential areas. If new or more stringent federal, state, or local legal restrictions relating to the fracking 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.

The EPA is conducting a study of the potential impacts of fracking activities on drinking water. The EPA issued a Progress Report in December 2012 and a draft final report is anticipated by 2014 for peer review and public comment. The final report has not yet been issued. As part of this study, the EPA requested that certain companies provide them with information concerning the chemicals used in the fracking process. This study or other studies may be undertaken by the EPA or other governmental authorities, and depending on their results, could spur initiatives to regulate fracking under the SDWA or otherwise. If new federal, state or local laws or regulations that significantly restrict fracking are adopted, such legal requirements could result in delays, eliminate certain drilling and injection activities and make it more difficult or costly for our customers to perform fracturing. Any such regulations limiting or prohibiting fracking could reduce oil and natural gas exploration and production activities by our customers and, therefore, adversely affect our business. Such laws or regulations could also materially increase our costs of compliance and doing business by more strictly regulating how fracking wastes are handled or disposed.

We currently own substantial property in New York State and we cannot assure when, or if, the New York State’s Supplemental Generic Environmental Impact Statement (“SGEIS”) will be finally issued, the issuance of which is required in order for us to begin high volumes fracking of horizontal wells.

Value extraction from the Company’s Marcellus and Utica Shale play in New York is dependent on final SGEIS issuance that would allow high volume fracking of horizontal wells. There was some anticipation that the SGEIS would be issued in February 2013. However, there has been further delay in the issuance. Also, the New York State Court of Appeals has ruled that municipalities in New York may ban hydrofracturing and other activities relating to producing oil and gas, which could preclude economic production of oil and gas from the Marcellus and Utica Shales (and other formations) those municipalities which enact such bans.

On February 12, 2013, the New York State Department of Environmental Conservation (“DEC”) was advised by the New York State Department of Health (“DOH”) that they would need “a few more weeks” to complete their health review of the proposed SGEIS. Issuance of the final SGEIS is contingent upon a determination that the SGEIS has adequately addressed health concerns. After issuance of the SGEIS, the DEC can accept and process fracking permit applications ten days thereafter.

Fracking technology has continued to advance in other parts of the Marcellus and Utica Shales, resulting in increased EURs and reduced well costs in the shale industry. Fracking has proven to be very successful in major shale plays in the Marcellus and Utica Shales in nearby States of Pennsylvania, West Virginia and Ohio. As a result of the New York moratorium, the Company has not been able to develop the most lucrative aspects of its holdings. A regional study done by Ralph E. Davis Associates, Inc. shows that this acreage contains possible contingent reserves of oil and natural gas. The Marcellus and Utica Shales both contain fairways that should be favorable for oil and gas exploration in areas in which we currently hold acreage.

Even once the SGEIS is finally issued, projects of the scale that the Company holds, approximately 300,000 gross acres of shale development, will require significant capital investment. Consequently, the Company would seek to work with partners on the development of these assets, following initial de-risking phase.

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Oil and natural gas producers’ operations, especially those using fracking, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may impact our operations.

Water is an essential component of oil and natural gas production during the drilling, and in particular, fracking, process. Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations, could adversely impact our operations.

Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as fracking or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. The CWA imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters. Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands. The CWA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. State and federal discharge regulations prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. Specific to Pennsylvania, sending wastewater to POTWs requires certain levels of pretreatment that may effectively prohibit such disposal as a disposal option and our continued ability to use injection wells as a disposal option not only will depend on federal or state regulations but also on whether available injection wells have sufficient storage capacities. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with current and future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for fracking of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted.

We are subject to risks associated with climate change.

There is a growing belief that emissions of greenhouse gases (“GHGs”) may be linked to climate change. Climate change and the costs that may be associated with its impacts and the regulation of GHGs have the potential to affect our business in many ways, including negatively impacting the costs we incur in providing our products and services, the demand for and consumption of our products and services (due to change in both costs and weather patterns), and the economic health of the regions in which we operate, all of which can create financial risks. In addition, legislative and regulatory responses related to GHGs and climate change creates the potential for financial risk. The U.S. Congress has previously considered legislation related to GHG emissions. There have also been international efforts seeking legally binding reductions in emissions of GHGs. In addition, increased public awareness and concern may result in more state, regional and/or federal requirements to reduce or mitigate GHG emissions.

On September 22, 2009, the EPA finalized a GHG reporting rule that requires large sources of GHG emissions to monitor, maintain records on, and annually report their GHG emissions beginning January 1, 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent (CO₂e) emissions per year and to most upstream suppliers of fossil fuels, as well as manufacturers of vehicles and engines. Subsequently, on November 8, 2010, the EPA issued GHG monitoring and reporting regulations that went into effect on December 30, 2010, specifically for oil and natural gas facilities, including onshore and offshore oil and natural gas production facilities that emit 25,000 metric tons or more of CO₂e per year. The rule requires reporting of GHG emissions by regulated facilities to the EPA by March 2012 for emissions during 2011 and annually thereafter. The EPA also issued a final rule that makes certain stationary sources and newer modification projects subject to permitting requirements for GHG emissions, beginning in 2011, under the CAA. Under a phased-in approach, for most purposes, new permitting provisions are required for new facilities that emit 100,000 tons per year or more of CO₂e and existing facilities that make changes increasing emissions of CO₂e by 75,000 metric tons. The EPA has indicated in rulemakings that it may further reduce these regulatory thresholds in the future, making additional sources subject to permitting.

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The recent actions of the EPA and the passage of any federal or state climate change laws or regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. If we are unable to recover or pass through a significant level of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse effect on our results of operations and financial condition. To the extent financial markets view climate change and GHG emissions as a financial risk, this could negatively impact our cost of and access to capital. Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing natural gas, including the possibility of:

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

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abnormally pressured formations;

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mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

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fires, explosions and ruptures of pipelines;

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personal injuries and death;

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natural disasters; and

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terrorist attacks targeting natural gas and oil related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

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injury or loss of life;

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damage to and destruction of property, natural resources and equipment;

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pollution and other environmental damage;

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regulatory investigations and penalties;

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suspension of our operations; and

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repair and remediation costs.

In accordance with what we believe to be customary industry practice, we maintain insurance against some, but not all, of our business risks. Our insurance may not be adequate to cover any losses or liabilities we may suffer. Also, insurance may no longer be available to us or, if it is, its availability may be at premium levels that do not justify its purchase. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations or cash flows. In addition, we may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial condition. We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance.

Since fracking activities are a part of our operations, they are covered by our insurance against claims made for bodily injury, property damage and clean-up costs stemming from a sudden and accidental pollution event. However, we may not have coverage if we are unaware of the pollution event and unable to report the “occurrence” to our insurance company within the time frame required under our insurance policy. We have

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no coverage for gradual, long-term pollution events. In addition, these policies do not provide coverage for all liabilities, and we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

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

Properties that we decide to drill that do not yield natural gas, NGLs or oil in commercially viable quantities will adversely affect our results of operations and financial condition. Our project areas are in various stages of development, ranging from project areas with current drilling or production activity to project areas that consist of recently acquired leasehold acreage or that have limited drilling or production history. If the wells in the process of being completed do not produce sufficient revenues to return a profit or if we drill dry holes in the future, our business may be materially affected. In addition, there is no way to predict in advance of drilling and testing whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas, NGLs or oil will be present or, if present, whether natural gas, NGLs or oil will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

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unexpected drilling conditions;

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title problems;

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pressure or lost circulation in formations;

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equipment failure or accidents;

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adverse weather conditions;

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compliance with environmental and other governmental or contractual requirements; and

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increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

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In addition, our credit facilities impose certain limitations on our ability to enter into mergers or combination transactions. Our credit facilities also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

Market conditions or operational impediments may hinder our access to natural gas, NGL or oil markets or delay our production.

Market conditions or the unavailability of satisfactory natural gas, NGL or oil transportation arrangements may hinder our access to markets or delay our production. The availability of a ready market for our production depends on a number of factors, including the demand for and supply of natural gas, NGLs or oil 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. We may be required to shut in wells due to lack of a market or inadequacy or unavailability of natural gas, NGL or oil pipeline or gathering system capacity. In addition, if quality specifications for the third-party pipelines with which we connect change so as to restrict our ability to transport product, our access to markets could be impeded. If our production becomes shut in for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our oil and natural gas exploration, production and transportation operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs in order to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. Such costs could have a material adverse effect on our business, financial condition and results of operations.

Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production and transportation of, oil, natural gas and NGLs. Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition and results of operations.

Changes to existing or new regulations may unfavorably impact us, could result in increased operating costs and have a material adverse effect on our financial condition and results of operations. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows. Further, the discharges of oil, natural gas, natural gas liquids and other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties. See “Business — Regulation of Environmental and Occupational Safety and Health Matters” for a further description of laws and regulations that affect us.

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

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. We intend to continue our four-rig drilling program in the Marcellus Shale and to implement a two-rig drilling program in the Utica Shale; however, certain of the rigs performing work for us do so on a well-by-well basis and can refuse to provide such services at the conclusion of drilling on the current well. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has

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increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the Natural Gas Act of 1938 (“NGA”) exempts natural gas gathering facilities from regulation by the Federal Energy Regulatory Commission (“FERC”), as a natural gas company under the NGA. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulation may have on our activities. Such regulations may have a material adverse effect on our financial condition, result of operations and cash flows.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, or EPAct 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC as a natural gas company under the NGA, we are required to report aggregate volumes of natural gas purchased or sold at wholesale to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. In addition, Congress may enact legislation or FERC may adopt regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to further regulation. Failure to comply with those regulations in the future could subject us to civil penalty liability.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas and secure trained personnel.

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 for acquiring properties, marketing oil or natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive oil or 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. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased over the past three years due to competition and may increase substantially in the future. 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, which could have a material adverse effect on our business.

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The loss of senior management or technical personnel could adversely affect operations.

We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations.

We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.

We have grown rapidly over the last several years. Our management believes that our future success depends on our ability to manage the rapid growth that we have experienced and the demands from increased responsibility on management personnel. The following factors could present difficulties:

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increased responsibilities for our executive level personnel;

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increased administrative burden;

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increased capital requirements; and

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increased organizational challenges common to large, expansive operations.

Our operating results could be adversely affected if we do not successfully manage these potential difficulties. The historical financial information incorporated herein is not necessarily indicative of the results that may be realized in the future. In addition, our operating history is limited and the results from our current producing wells are not necessarily indicative of success from our future drilling operations.

Seasonal weather conditions and regulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Oil and natural gas operations in our operating areas can be adversely affected by seasonal weather conditions and regulations designed to protect various wildlife. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.

Increases in interest rates and the lack of availability of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of producing properties requires an assessment of several factors, including:

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recoverable reserves;

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future natural gas, NGL or oil prices and their applicable differentials;

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operating costs; and

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potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently

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familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), enacted on July 21, 2010, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The Dodd-Frank Act requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized some regulations, including critical rulemakings on the definition of “swap,” “swap dealer,” and “major swap participant”, others remain to be finalized and it is not possible at this time to predict when this will be accomplished.

The Dodd-Frank Act authorized the CFTC to establish rules and regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The CFTC’s initial position limits rules were vacated by the U.S. District Court for the District of Columbia in September 2012. However, on November 5, 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.

The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, for un-cleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce our cash available for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to us is uncertain at this time.

The Dodd-Frank Act and regulations may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The Dodd-Frank Act and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures.

Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is lower commodity prices.

Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

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Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

The Fiscal Year 2014 Budget proposed by the President recommends the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies, and legislation has been introduced in Congress that would implement many of these proposals. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities for oil and gas production; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear, however, whether any such changes will be enacted or how soon such changes could be effective.

The passage of this legislation or any other similar change in U.S. federal income tax law could eliminate or postpone certain tax deductions that are currently available with respect to natural gas and oil exploration and development, and any such change could negatively affect our financial condition and results of operations.

State legislators are exploring ways to ensure that communities are reimbursed for the impact that natural gas development may have on infrastructure. A primary approach has been to impose taxes and fees on the extraction, production, and sale of natural gas and oil. These “severance” taxes — taxes applied to materials severed from the ground — tax the extraction or production of oil, gas, and other natural resources. Thirty-two states currently produce natural gas, with Texas, Louisiana, Wyoming, Oklahoma, and Colorado ranking as the top five producers in 2012. Maryland, New York, and Pennsylvania are the only natural gas producers without a severance tax.

Pennsylvania, the largest U.S. natural gas producer, does not impose a severance tax. Instead, it levies an impact fee on every producing gas and oil well in the state, regardless of the volume produced. Studies by the Pennsylvania Budget and Policy Center estimate that the impact fee will generate $237 to $261 million by 2015, compared to an estimated $800 million from a five percent tax on production value. The 5 percent tax is based on proposals by Pennsylvania Governor and is modeled on West Virginia’s severance tax.

The risk that Pennsylvania and New York may enact such legislation in the future and that other states may increase the severance tax in the future exists.

The requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act and the requirements of the Sarbanes-Oxley Act of 2002, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and the requirements of The NASDAQ Capital Market (“NASDAQ”), with which we are not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses. We will need to:

•

institute a more comprehensive compliance function;

•

comply with rules promulgated by NASDAQ;

•

continue to prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

•

establish new internal policies, such as those relating to insider trading; and

•

involve and retain to a greater degree outside counsel and accountants in the above activities.

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Furthermore, while we generally must comply with Section 404 of the Sarbanes Oxley Act of 2002 for our fiscal year ended December 31, 2013, we are not required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until our first annual report subsequent to our ceasing to be an “emerging growth company” within the meaning of Section 2(a)(19) of the Securities Act. Accordingly, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our annual report for the fiscal year ending December 31, 2019. Once it is required to do so, our independent registered public accounting firm may issue a report that is adverse in the event it is not satisfied with the level at which our controls are documented, designed, operated or reviewed. Compliance with these requirements may strain our resources, increase our costs and distract management and we may be unable to comply with these requirements in a timely or cost-effective manner.

In addition, we expect that being a public company subject to these rules and regulations may make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it may be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers. We are currently evaluating these rules, and we cannot predict or estimate the amount of additional costs we may incur or the timing of such costs.

There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected.

We are not currently required to comply with the SEC’s rules implementing Section 404 of the Sarbanes Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded company, we will be required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. The internal control provisions of Section 404 of the Sarbanes-Oxley Act of 2002 require us to identify material weaknesses in internal control over financial reporting, which is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with accounting principles generally accepted in the United States. Our management, including our chief executive officer and chief financial officer, does not expect that our internal controls and disclosure controls will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. In addition, the design of a control system must reflect the fact that there are resource constraints and the benefit of controls must be relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, in our company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple errors or mistakes. Further, controls can be circumvented by individual acts of some persons, by collusion of two or more persons, or by management override of the controls. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, a control may be inadequate because of changes in conditions, such as growth of the company or increased transaction volume, or the degree of compliance with the policies or procedures may deteriorate. Because of inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

In addition, discovery and disclosure of a material weakness, by definition, could have a material adverse impact on our financial statements. Such an occurrence could discourage certain customers or suppliers from doing business with us, cause downgrades in our future debt ratings leading to higher borrowing costs and affect how our stock trades. This could in turn negatively affect our ability to access public debt or equity markets for capital.

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The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

Prior to this offering, our common stock was not traded on any market. An active, liquid and orderly trading market for our common stock may not develop or be maintained after this offering. Active, liquid and orderly trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. The market price of our common stock could vary significantly as a result of a number of factors, some of which are beyond our control. In the event of a drop in the market price of our common stock, you could lose a substantial part or all of your investment in our common stock. The initial public offering price will be negotiated between us and representatives of the underwriters, based on numerous factors which we discuss in “Underwriting,” and may not be indicative of the market price of our common stock after this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering, or at all.

The following factors could affect our stock price:

•

our operating and financial performance and drilling locations, including reserve estimates;

•

quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;

•

the public reaction to our press releases, our other public announcements and our filings with the SEC;

•

strategic actions by our competitors;

•

our failure to meet revenue, reserves or earnings estimates by research analysts or other investors;

•

changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

•

speculation in the press or investment community;

•

the failure of research analysts to cover our common stock;

•

sales of our common stock by us or our stockholders, or the perception that such sales may occur;

•

changes in accounting principles, policies, guidance, interpretations or standards;

•

additions or departures of key management personnel;

•

actions by our stockholders;

•

general market conditions, including fluctuations in commodity prices;

•

domestic and international economic, legal and regulatory factors unrelated to our performance; and

•

the realization of any risks describes under this “Risk Factors” section.

The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. Securities class action litigation has often been instituted against companies following periods of volatility in the overall market and in the market price of a company’s securities. Such litigation, if instituted against us, could result in very substantial costs, divert our management’s attention and resources and harm our business, operating results and financial condition.

Empire Energy Group will hold a substantial majority of our common stock.

Immediately following the completion of this offering, Empire Energy Group will hold approximately [•]% of our common stock. Empire Energy Group will have the voting power to elect all of the members of our board of directors and thereby control our management and affairs. In addition, it will be able to determine the outcome of all matters requiring stockholder approval, including mergers and other material transactions, and will be able to cause or prevent a change in the composition of our board of directors or a

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change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their common stock as part of a sale of our company. The existence of significant stockholders may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.

So long as Empire Energy Group continues to control a significant amount of our common stock, it will continue to be able to strongly influence all matters requiring stockholder approval, regardless of whether or not other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interest of Empire Energy Group may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our common stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling stockholder.

The stockholders’ agreement we expect to enter into in connection with the completion of this offering will permit our principal stockholder to designate a majority of the members of our board of directors.

In connection with the completion of this offering, we will enter into a stockholders’ agreement with Empire Energy Group, a form of which is filed as an exhibit to the registration statement of which this prospectus is a part. Pursuant to the stockholders’ agreement, Empire Energy Group will be provided with certain rights relative to designated director nominees and will agree to vote its shares of common stock in accordance with the stockholders’ agreement, including as it relates to the election of directors.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

The certificate of incorporation that we will adopt in connection with the Corporate Reorganization authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

•

limitations on the removal of directors;

•

limitations on the ability of our stockholders to call special meetings;

•

establishing advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and

•

providing that the Board of Directors is expressly authorized to adopt, or to alter or repeal our bylaws.

Investors in this offering will experience immediate and substantial dilution of $ per share.

Based on an assumed initial public offering price of $ per share (the midpoint of the range set forth on the cover of this prospectus), purchasers of our common stock in this offering will experience an immediate and substantial dilution of $ per share in the as adjusted net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of March 31, 2014 on a pro forma basis would be $ per share. This dilution is due in large part to earlier investors having paid substantially less than the initial public offering price when they purchased their shares. See “Dilution.”

We may invest or spend the proceeds of this offering in ways with which you may not agree or in ways which may not yield a return.

A portion of the net proceeds from this offering are expected to be used to fund a portion of our acquisition or capital expenditure plans. Our management will have considerable discretion in the application of the net proceeds, and you will not have the opportunity, as part of your investment decision, to assess

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whether the proceeds are being used appropriately. The net proceeds may be used for corporate purposes that do not increase our operating results or market value. Until the net proceeds are used, they may be placed in investments that do not produce significant income or that may lose value.

We do not intend to pay dividends on our common stock, and our credit facilities place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We do not plan to declare dividends on shares of our common stock in the foreseeable future. Additionally, our credit facilities place certain restrictions on our ability to pay cash dividends. Consequently, your only opportunity to achieve a return on your investment in us will be if you sell your common stock at a price greater than you paid for it. There is no guarantee that the price of our common stock that will prevail in the market will ever exceed the price that you pay in this offering.

Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of common stock in subsequent public offerings. We may also issue additional shares of common stock or convertible securities. After the completion of this offering, we will have outstanding shares of common stock. This number includes shares that we are selling in this offering and shares that we may sell in this offering if the underwriters’ option to purchase additional shares is fully exercised, which may be resold immediately in the public market. Following the completion of this offering, assuming an initial public offering price equal to the midpoint of the range set forth on the cover of this prospectus and no exercise of the underwriters’ option to purchase additional shares, Empire Energy Group will own shares of our common stock, or approximately % of our total outstanding shares, all of which are restricted from immediate resale under the federal securities laws and are subject to the lock-up agreements with the underwriters described in “Underwriting” but may be sold into the market in the future. Certain employees will be subject to restrictions on the sale of their shares for 180 days after the date of this prospectus; however, after such period, and subject to compliance with the Securities Act or exemptions therefrom, these employees may sell such shares into the public market. See “Shares Eligible for Future Sale”.

In connection with this offering, we intend to file a registration statement with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our stock incentive plan. Subject to the satisfaction of vesting conditions, the expiration of lock-up agreements and the requirements of Rule 144, shares registered under the registration statement on Form S-8 will be available for resale immediately in the public market without restriction.

We cannot predict the size of future issuances of our common stock or securities convertible into common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We, Empire Energy Group, the lender to the Company, all of our directors and executive officers and certain of our employees have entered into lock-up agreements with respect to their common stock, pursuant to which they are subject to certain resale restrictions for a period of 180 days following the effectiveness date of the registration statement of which this prospectus forms a part. Maxim Group LLC, at any time and without notice, may release all or any portion of the common stock subject to the foregoing lock-up agreements. If the restrictions under the lock-up agreements are waived, then common stock will be available for sale into the public markets, which could cause the market price of our common stock to decline and impair our ability to raise capital.

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We expect to be a “controlled company” within the meaning of the NASDAQ rules and, as a result, will qualify for and could rely on exemptions from certain corporate governance requirements.

Upon completion of this offering, Empire Energy Group will beneficially control a majority of the voting power of all classes of our outstanding voting stock. In connection with the completion of this offering, we will enter into a stockholders’ agreement with Empire Energy Group pursuant to which Empire Energy Group will be provided with certain rights relative to designated director nominees and will agree to vote its shares of common stock in accordance with the stockholders’ agreement, including as it relates to the election of directors. For additional information regarding the stockholders’ agreement, please read “Certain Relationships and Related Party Transactions — Stockholders’ Agreement.” As a result, we expect to be a controlled company within the meaning of the NASDAQ corporate governance standards. Under the NASDAQ rules, a company of which more than 50% of the voting power for the election of directors is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain NASDAQ corporate governance requirements, including the requirements that:

•

a majority of the board of directors consist of independent directors;

•

the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities;

•

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

•

there be an annual performance evaluation of the nominating and governance and compensation committees.

These requirements will not apply to us as long as we remain a controlled company. Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. See “Management.”

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

In April 2012, President Obama signed into law the JOBS Act. We are classified as an “emerging growth company” under the JOBS Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we will not be required to, among other things, (1) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (2) comply with any new requirements adopted by the PCAOB requiring mandatory audit firm rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (3) provide certain disclosure regarding executive compensation required of larger public companies or (4) hold nonbinding advisory votes on executive compensation. We will remain an emerging growth company for up to five years, although we will lose that status sooner if we have more than $1.0 billion of revenues in a fiscal year, have more than $700 million in market value of our common stock held by non-affiliates, or issue more than $1.0 billion of non-convertible debt over a three-year period.

Pursuant to Section 102(b)(1) of the JOBS Act, as an emerging growth company, we are able to use the extended transition period for complying with new or revised accounting standards.

Pursuant to the Section 102(b)(1) of the JOBS Act, for as long as the Company is an “emerging growth company” we are exempted from adopting new or revised accounting standards that are effective for public companies and may instead wait until the effective dates for private companies to adopt such standards unless we opt out of this exemption. We have not elected to opt out of this exemption and, as a result, our financial statements may not be comparable to companies that comply with public company effective dates.

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We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

If securities or industry analysts do not publish research or reports about our business, if they adversely change their recommendations regarding our common stock or if our operating results do not meet their expectations, our stock price could decline.

The trading market for our common stock will be influenced by the research and reports that industry or securities analysts publish about us or our business. If one or more of these analysts cease coverage of our company or fail to publish reports on us regularly, we could lose visibility in the financial markets, which in turn could cause our stock price or trading volume to decline. Moreover, if one or more of the analysts who cover our company downgrades our common stock or if our operating results do not meet their expectations, our stock price could decline.

Our certificate of incorporation will designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our certificate of incorporation will provide that unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the Delaware General Corporation Law (the “DGCL”), our certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
AND INDUSTRY DATA

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this prospectus, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this prospectus. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

•

business strategy;

•

reserves;

•

financial strategy, liquidity and capital required for our development program;

•

realized natural gas, NGL and oil prices;

•

timing and amount of future production of natural gas, NGLs and oil, including with respect to the timing and results of initial wells in the Utica Shale;

•

hedging strategy and results;

•

future drilling plans;

•

competition and government regulations;

•

pending legal or environmental matters;

•

marketing of natural gas, NGLs and oil;

•

leasehold or business acquisitions;

•

costs of developing our properties and conducting our gathering and other midstream operations;

•

general economic conditions;

•

credit markets;

•

uncertainty regarding our future operating results; and

•

plans, objectives, expectations and intentions contained in this prospectus that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under “Risk Factors” in this prospectus.

Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were

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made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, and NGLs and oil that are ultimately recovered.

Should one or more of the risks or uncertainties described in this prospectus occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this prospectus are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this prospectus.

This prospectus also includes statistical and other industry and market data that we obtained from industry publications and research, surveys and studies conducted by third parties. Industry publications and third party research, surveys and studies generally indicate that their information has been obtained from sources believed to be reliable, although they do not guarantee the accuracy or completeness of such information. While we believe these industry publications and third party research, surveys and studies are reliable, we have not independently verified such data.

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USE OF PROCEEDS

We estimate that the net proceeds to us from our issuance and sale of shares of common stock in this offering will be approximately $ million (or approximately $ million if the underwriters exercise their over-allotment option in full), assuming an initial public offering price of $ per share, which is the midpoint of the price range listed on the cover page of this prospectus, after deducting estimated underwriting discounts and commissions and offering expenses payable by us.

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) our net proceeds from this offering by approximately $ million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and offering expenses payable by us.

The principal purposes of this offering are to increase our capitalization and financial flexibility, create a public market for our common stock and enable access to the public equity markets for us and our stockholders. We intend to use the net proceeds from this offering for general corporate purposes, including working capital, operating expenses and capital expenditures. We estimate that we will use the net proceeds from this offering as follows:

•

approximately $ million for drilling;

•

approximately $ million for future acquisitions;

•

approximately $ million for general capital expenditures⁽¹⁾; and

•

approximately $ million for general corporate purposes.;

(1)

General capital expenditures shall include computers, leasehold improvements, gathering systems, and equipment.

Investors are cautioned, however, that expenditures may vary substantially from these uses. Investors will be relying on the judgment of our management, who will have broad discretion regarding the application of the proceeds of this offering. We are reserving the right to change our use of proceeds. The overall corporate strategy is to develop our existing assets through our drilling program and to acquire producing assets with development opportunities (“New Assets”). If any New Assets are identified that meet our acquisition metrics, we may reallocate proceeds from this offering to acquire New Assets. The amounts and timing of our actual expenditures will depend upon numerous factors, including the amount of cash generated by our operations, the amount of competition and other operational factors. We may find it necessary or advisable to use portions of the proceeds from this offering for other purposes.

From time to time, we evaluate these and other factors and we anticipate continuing to make such evaluations to determine if the existing allocation of resources, including the proceeds of this offering, is being optimized. Circumstances that may give rise to a change in the use of proceeds include:

•

a change in the size of this offering;

•

a change in our acquisition plan or strategy;

•

technical delays;

•

delays or difficulties with our capital expenditure plan;

•

the availability and operating cost of drilling rigs;

•

oil and gas pricing;

•

cost of oil and gas extraction;

•

availability and market for existing production;

•

failure to achieve sales as anticipated; and

•

the availability of other sources of cash, including cash flow from operations and new bank debt financing arrangements, if any.

Pending our use of the net proceeds from this offering, we intend to invest the net proceeds in a variety of capital preservation investments, including short-term, investment grade, interest bearing instruments and U.S. government securities.

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DIVIDEND POLICY

We do not anticipate declaring or paying any cash dividends to holders of our common stock in the foreseeable future. We currently intend to retain future earnings, if any, to finance the growth of our business. Our future dividend policy is within the discretion of our board of directors and will depend upon then-existing conditions, including our results of operations, financial condition, capital requirements, investment opportunities, statutory restrictions on our ability to pay dividends and other factors our board of directors may deem relevant. In addition, certain of our debt instruments place restrictions on our ability to pay cash dividends.

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CAPITALIZATION

The following table sets forth the cash and capitalization as of March 31, 2014 of:

•

Imperial on an actual basis;

•

the Company on a pro forma basis to give effect to the reorganization transactions described under “Corporate Reorganization” and, in connection therewith, the conversion of the outstanding percentage interest issued and outstanding immediately prior to the conversion into an aggregate of shares of common stock; and

•

the Company on a pro forma as adjusted basis to give effect to the sale of shares of our common stock in this offering at an assumed initial public offering price of $ per share (which is the midpoint of the price range set forth on the cover page of this prospectus), our receipt of an estimated $ million of net proceeds from this offering after deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us and the use of those net proceeds as described under the caption “Use of Proceeds.”

This table should be read in conjunction with, and is qualified in its entirety by reference to, “Use of Proceeds” and our historical audited and unaudited consolidated financial statements and the accompanying notes appearing elsewhere in this prospectus.


	As of March 31, 2014
	Actual			Pro Forma⁽⁵⁾		Pro Forma As Adjusted⁽⁵⁾
	Imperial Resources, LLC			Empire Energy Holdings, Inc.		Empire Energy Holdings, Inc.
	(Unaudited)
	(In thousands)
Cash and cash equivalents⁽¹⁾	$	2,782		$
Long term debt:
Term facility⁽²⁾		39,364
Revolver⁽³⁾		3,000
Related party payable⁽⁴⁾		7,478
Other		42
Total indebtedness		49,884			—
Equity:
Common stock, $0.01 par value; [•] shared authorized (as adjusted); [•] shares issued and outstanding (as adjusted)		29,775
Non-controlling interest		(198	)
Warrants		3,413
Accumulated other comprehensive income		1,877
Accumulated earnings		6,993
Total equity		41,860			—
Total capitalization	$	91,745		$	—

(1)

As of March 31, 2014, we had cash and cash equivalents of $2.8 million.

(2)

As of March 31, 2014, we had $39.4 million in outstanding borrowings under our term credit facility, which matures in February, 2016 and bears interest at a variable rate, which was approximately 4.59% as of March 31, 2014. This amount is net of discounts on debt of $0.3 million.

(3)

As of March 31, 2014, we had $3.0 million in outstanding borrowings under our revolving credit facility, which matures in February, 2016 and bears interest at a variable rate, which was approximately 2.69% as of March 31, 2014.

(4)

As of March 31, 2014, we had $7.5 million debt due to Empire Energy Group, our parent company.

(5)

The pro forma and pro forma as adjusted information is illustrative only and following the completion of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.

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A $1.00 increase or decrease in the assumed initial public offering price of $ per share, which is the midpoint of the range set forth on the cover of this prospectus, would increase or decrease each of cash and cash equivalents, total equity and total capitalization on a pro forma as adjusted basis by approximately $ million, assuming that the number of shares offered by us, as set forth on the cover of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us. We may also increase or decrease the number of shares we are offering. Each increase of 1.0 million shares in the number of shares offered by us at an assumed offering price of $ per share, which is the midpoint of the estimated offering price range set forth on the cover of this prospectus, would increase each of our pro forma as adjusted cash and cash equivalents, total equity and total capitalization by approximately $ million. Similarly, each decrease of 1.0 million shares in the number of shares offered by us, at an assumed offering price of $ per share, which is the midpoint of the estimated offering price range set forth on the cover of this prospectus, would decrease each of our pro forma as adjusted cash and cash equivalents, total equity and total capitalization by approximately $ million.

The number of shares of our common stock that will be outstanding immediately after this offering is based on shares of common stock of the Company outstanding as of , 2014 as if the membership interest percentage outstanding as of , 2014 was converted pursuant to the Corporate Reorganization, and excludes the following:

•

shares of our common stock reserved for future issuance under our stock incentive plans as of , 2014;

•

up to additional shares of common stock issuable upon exercise of the underwriters’ over-allotment option; and

•

shares of our common stock issuable upon exercise of the Representative’s Warrants upon completion of this offering.

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DILUTION

If you invest in our common stock in this offering, your ownership interest will be immediately and substantially diluted to the extent of the difference between the public offering price per share of our common stock and our pro forma net tangible book value per share of our common stock after giving effect to this offering.

Our historical net tangible book value as of March 31, 2014 was $[•], or $[•] per share of our common stock. Historical net tangible book value per share represents the amount of our total tangible assets less total liabilities, divided by [•] shares of our common stock outstanding as of March 31, 2014.

Our pro forma net tangible book value as of March 31, 2014 was $[•], or $[•] per share of our common stock. Pro forma net tangible book value per share represents the amount of our total tangible assets less our total liabilities, divided by the pro forma number of shares of our common stock outstanding as of March 31, 2014 (with the number of shares of common stock calculated as if the membership interest percentage outstanding as of March 31, 2014 was converted pursuant to the Corporate Reorganization).

After giving effect to the sale of the shares in this offering at the assumed initial public offering price of $ per share, which is the midpoint of the price range set forth on the cover page of this prospectus, after deducting underwriting discounts and commissions and other estimated offering expenses payable by us, our pro forma as adjusted net tangible book value at March 31, 2014 would have been approximately $ , or $ per share. This represents an immediate increase in pro forma net tangible book value of approximately $ per share to our existing stockholders, and an immediate dilution of $ per share to investors purchasing shares of common stock in this offering.

Dilution in pro forma net tangible book value per share represents the difference between the amount per share paid by purchasers of our common stock in this offering and the pro forma net tangible book value per share of our common stock immediately after this offering.

The following table illustrates the per share dilution to investors purchasing shares in the offering:


Assumed initial public offering price per share						$
Pro forma net tangible book value per share as of March 31, 2014, before giving effect to this offering						$
Increase in net tangible book value per share attributable to new investors in this offering
Pro forma as adjusted net tangible book value per share after this offering
Dilution per share to new investors						$

A $1.00 increase (decrease) in the assumed initial public offering price of $ per share would increase (decrease) the pro forma as adjusted net tangible book value by $ , the pro forma as adjusted net tangible book value per share by $ per share, and the dilution in pro forma as adjusted net tangible book value per share to new investors in this offering by $ per share, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting the estimated underwriting discounts and commissions and estimated offering expenses payable by us.

The information above assumes that the underwriters do not exercise their over-allotment option or the Representative’s Warrants. If the underwriters exercise their over-allotment option in full, the pro forma as adjusted net tangible book value will increase to $ per share, representing an immediate increase in pro forma as adjusted net tangible book value to existing stockholders of $ per share and an immediate dilution of $ per share to new investors in this offering. If any shares are issued upon exercise of outstanding options or warrants, new investors will experience further dilution.

The following table summarizes, on a pro forma as adjusted basis as of March 31, 2014, the differences between the number of shares of common stock purchased from us, the total consideration and the average

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price per share paid by existing stockholders and by new investors participating in this offering, at an assumed initial public offering price of $ per share, the midpoint of the estimated price range shown on the cover page of this prospectus.


	Shares Purchased				Total Consideration				Average Price Per Share
	Number	Percentage			Amount	Percentage
Existing stockholders					$				$
New investors
Total			100	%	$		100	%	$

The number of shares of our common stock that will be outstanding immediately after this offering is based on shares of common stock of the Company outstanding as of , 2014 as if the membership interest percentage outstanding as of , 2014 was converted pursuant to the Corporate Reorganization and excludes the following:

•

shares of our common stock reserved for future issuance under our stock incentive plans as of , 2014; and

•

shares of our common stock issuable upon exercise of the Representative’s Warrants upon completion of this offering.

If the underwriters exercise their over-allotment option in full, the number of shares held by new investors will increase to , or % of the total number of shares of common stock outstanding after this offering, and the shares held by existing stockholders will be but the percentage of shares held by existing stockholders will decrease to % of the total shares outstanding.

To the extent that the underwriters’ over-allotment option is exercised, any warrants or options are granted and exercised or existing warrants (including the Representative’s Warrants) or options are exercised, there will be further dilution to new investors.

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SELECTED CONSOLIDATED FINANCIAL DATA

The following selected historical consolidated balance sheet data, statements of operations data and statements of cash flows data (i) as of and for the years ended December 31, 2012 and 2013 are derived from, and qualified by reference to, the audited consolidated financial statements of Imperial included elsewhere in this prospectus, and (ii) as of and for the three months ended March 31, 2013 and 2014 are derived from, and qualified by reference to, the unaudited consolidated financial statements of Imperial included elsewhere in this prospectus. The financial data of Imperial, a holding company, are inclusive of its wholly owned subsidiary Empire Energy USA, LLC and Empire Energy E&P, LLC. The selected financial data presented below should be read in conjunction with the financial statements and notes thereto, as well as “Capitalization” and “Management's Discussion and Analysis of Financial Condition and Results of Operations.” Our historical results of operations are not necessarily indicative of results to be expected for any future periods.

The selected unaudited pro forma consolidated balance sheet data as of March 31, 2014 and the statements of operations data and statements of cash flows for the year ended December 31, 2013 and the three months ended March 31, 2014 has been prepared to give pro forma as adjusted effect to (i) the Corporate Reorganization, pursuant to which Imperial will be converted into the Company and its only direct holdings will be Empire Energy USA, LLC, and (ii) this offering and the application of the net proceeds from this offering as if they had been completed as of January 1, 2013 or 2014, as applicable. The selected unaudited pro forma consolidated financial data are presented for informational purposes only and should not be considered indicative of actual results of operations that would have been achieved had the Corporate Reorganization and this offering been consummated on the dates indicated, and do not purport to be indicative of statements of financial position or results of operations as of any further date or for any future period.


	Imperial Resources, LLC (Actual)												Empire Energy Holdings, Inc. (Pro Forma)
	Three Months Ended March 31,						Year Ended December 31,						Three Months Ended March 31,	Year Ended December 31,
	2014			2013			2013			2012			2014	2013
	(Unaudited)												(Unaudited)
	(In thousands, except per unit data)
Statement of operations data:
Revenues:
Oil sales	$	3,639		$	3,849		$	15,276		$	16,245
Natural gas sales		1,973			1,831			7,566			5,770
Oil and gas price risk		112			552			2,135			4,259
Total revenues		5,725			6,231			24,977			26,273
Operating expenses:
Lease operating		2,477			2,726			9,257			9,283
Production, severance and ad valorem taxes		98			533			1,163			858
Exploratory dry hole costs		18			—			729			197
General and administrative		593			638			3,463			3,431
Depreciation, depletion and amortization		1,395			1,246			5,854			5,435
Write-down on abandoned leases		—			42			152			1,027
Total operating expenses		4,582			5,185			20,619			20,231
Operating income		1,143			1,046			4,358			6,043
Interest income (expense) – non-cash		(110	)		(662	)		(2,165	)		(6,099	)
Interest income (expense) – cash		(498	)		(578	)		(2,216	)		(2,728	)
Other income (expense)		(225	)		56			143			(243	)

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	Imperial Resources, LLC (Actual)												Empire Energy Holdings, Inc. (Pro Forma)
	Three Months Ended March 31,						Year Ended December 31,						Three Months Ended March 31,	Year Ended December 31,
	2014			2013			2013			2012			2014	2013
	(Unaudited)												(Unaudited)
	(In thousands, except per unit data)
Income tax (expense) benefit		(112	)		46			(30	)		2,188
Net income (loss)	$	198		$	(93	)	$	91		$	(839	)
Net cash provided by (used in):
Operating activities	$	473		$	2,005		$	9,224		$	15,794
Investing activities		(769	)		(434	)		(3,162	)		(4,246	)
Financing activities		959			2,114			(8,226	)		(8,745	)
Other financial data (unaudited):
Adjusted EBITDAX⁽¹⁾	$	2,331		$	2,375		$	11,179		$	12,651
Earnings per unit – basic		—			—			—			—
Earnings per unit – diluted		—			—			—			—


	As of March 31,			As of December 31,
	2014		Pro Forma As Adjusted 2014	2013
	(Unaudited)
	(In thousands)
Balance sheet data:
Cash	$	2,782	$	$	2,118
Total property and equipment, net		97,091			97,518
Total assets		113,608			113,606
Total debt		49,884			49,846
Total members’/Members’ capital		41,860			42,273

(1)

Adjusted EBITDAX is a Non-GAAP “Financial Measures”. For a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net income (loss), see “Summary Consolidated Financial Data” below.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes appearing elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results and the differences can be material. Some of the key factors which could cause actual results to vary from our expectations include changes in natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below and elsewhere in this prospectus, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements and Industry Data.” Also, see the risk factors and other cautionary statements described under the heading “Risk Factors” included elsewhere in this prospectus. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law. Unless otherwise indicated, the information presented in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” does not give pro forma effect to our corporate reorganization described in “Corporate Reorganization” and “— Creation of Empire Energy Holdings, Inc.”

Overview

We are an independent returns-focused exploration and production company focused on the acquisition, development and exploitation of conventional oil and natural gas reserves in the Kansas (Mid-Continent), New York and Pennsylvania (Appalachia). We operate approximately 300 wells in the Mid-Continent and approximately 1,700 wells in the Appalachian Basin. Our drilling activity is currently focused on the low-risk vertical oil development of the Arbuckle and Lansing/Kansas City formations located in Central Kansas (Mid-Continent) where a typical Arbuckle well at a well cost of $350,000 is expected to produce an internal rate of return of around 66% with an initial gross production rate of 640 Bbl/month. This excludes any reserves and production for up-hole producing formations (such as the Lansing/Kansas City formations). In Upstate New York (Appalachia) we are targeting the Upper Devonian Bradford Group formation oil production. Although in Appalachia we mainly produce natural gas from the Medina formation at current gas prices development of these formations is breakeven. We are a returns-focused organization and have targeted these oil formations in Kansas and New York because of their favorable operating environment, long-lived reserve characteristics and high drilling success rates.

We were founded in September 2006 by a group of individuals with extensive experience in the oil and gas and finance industries. As we have grown we have been able to attract additional experienced operating and financial personal. With an average of over 20 years of industry experience, our management team has a proven track record of working as a team to acquire, develop and exploit oil and natural gas reserves in the Mid-Continent and Appalachian regions. Our strategy is to: (i) develop assets where we are the operator and have high revenue interests; and (ii) to acquire producing assets with additional development opportunity, with a focus on accretive acquisitions in regions in which we are already operating, again where we are the operator. This enables us to control the pace of development and allocation of our capital resources. As at March 31, 2014, we operated approximately 99% of our developed acreage with an average working interest of 84%.

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Our acreage position was 306,476 gross (278,527 net) acres at March 31, 2014, which we group into two primary areas based on geographic locations — Mid-Continent and Appalachia.

The following table summarizes our leasehold position by primary geographic area as of March 31, 2014:


	Gross		Net
Mid-Continent		22,869		17,609
Appalachia		283,607		260,918
Total		306,476		278,527

Since our inception, we have completed three significant acquisitions, four bolt-on acquisitions and one divestiture. In December 2006, the Company acquired DK Gas for $9.2 million. Located in Hawthorn, Pennsylvania the Company continues to maintain an operations facility today, with 150 operating gas wells and 6,000 leased acres in Jefferson, Clarion and Armstrong Counties in Pennsylvania. In December 2009, the Company purchased approximately 1,600 operating wells (predominantly gas) and 300,000 leased acres located in upstate New York from Range Resources Corporation for $38.0 million. The wells and leases are located in Chautauqua, Cattaraugus, Erie, Wyoming, Ontario, Seneca, Cayuga and Wayne Counties in New York and Erie County Pennsylvania. The Company maintains an operations facility in Mayville, New York. In December 2010, the Company purchased approximately 300 operating wells (predominantly oil) and 22,000 leased acres located in central Kansas from Amadeus Petroleum for $56.6 million. The Company maintains operations facilities in Great Bend, Plainville, and Wichita, Kansas. With respect to the divestiture, in 2010, the Company sold the deep drilling rights for the acreage acquired from DK Gas to a third party for $24.6 million.


Estimated Total Proved Reserves and Production
	2013
	Reserves								Production
Region	Oil (MBbls)		Natural Gas (MMcf)		Total (MBoe)		PV-10⁽¹⁾ (in thousands)		Average Net Daily Production (Boe/D)
Reserve Category
Proved Developed:
Mid-Con		2,599		235		2,638	$	63,361		447
Appalachia		61		27,098		4,577		26,357		896
Undeveloped:
Mid-Con		427		130		449		12,784		—
Appalachia		—		—		—		—		—
Total Proved		3,087		27,463		7,664	$	102,502		1,343
Probable		645		130		667	$	17,732		—
Possible		369		—		369		8,575		—

(1)

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We derive substantially all of our revenues from the sale of oil and natural gas that is produced from our interests in properties located in the Mid-Con and in the Appalachian Basin. Our revenues, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Oil and natural gas prices have historically been volatile and may fluctuate widely in the future due to a variety of factors, including, but not limited to, prevailing economic conditions, supply and demand of hydrocarbons in the marketplace and geopolitical events such as wars or natural disasters. Sustained periods of low oil or natural gas prices could materially and adversely affect our financial condition, our results of operations, the quantities of natural gas that we can economically produce and our ability to access capital.

We use NYMEX commodity contracts to manage and reduce price volatility and other market risks associated with our oil and natural gas production. These arrangements are structured to reduce our exposure to commodity price decreases, but they can also limit the benefit we might otherwise receive from commodity price increases. We have currently sold oil and natural gas NYMEX contracts at a fixed price. The prices contained in these derivative contracts are based on NYMEX WTI prices for oil and NYMEX Henry Hub prices for natural gas. The NYMEX prices are widely used benchmark for the pricing of oil and natural gas in the United States. The actual prices realized from the sale of natural gas differ from the quoted NYMEX prices as a result of location differentials. Location differentials to NYMEX prices, also known as basis differential, result from variances in regional oil or natural gas prices compared to NYMEX prices as a result of regional supply and demand factors. Historically, we have not hedged basis differentials associated with our oil or natural gas production. We have elected to designate our current portfolio of commodity derivative contracts as hedges for accounting purposes. Therefore only cash settlements are recognized as earnings. All other changes in fair value of these derivative instruments are recognized as Cumulative Other Comprehensive Income on the Balance Sheet. Please read “— Commodity Hedging Activities” for additional discussion of our commodity derivative contracts.

Like other businesses engaged in the exploration and production of oil and natural gas, we face the challenge of natural production declines. As initial reservoir pressures are depleted, oil and natural gas production from a given well naturally decreases. Thus, an oil and natural gas exploration and production company depletes part of its asset base with each unit of oil or natural gas it produces. We attempt to overcome this natural decline by drilling to find additional reserves and acquiring more reserves than we produce. Our future growth will depend on our ability to enhance production levels from our existing reserves and to continue to add reserves in excess of production in a cost effective manner. Our ability to make capital expenditures to increase production from our existing reserves and to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to access capital in a cost effective manner and to timely obtain drilling permits and regulatory approvals.

Our financial condition and results of operations, including the growth of production, cash flows and reserves, are driven by several factors, including:

•

success in drilling new wells;

•

oil or natural gas prices;

•

the availability of attractive acquisition opportunities and our ability to execute them;

•

the amount of capital we invest in the leasing and development of our properties;

•

facility or equipment availability and unexpected downtime;

•

delays imposed by or resulting from compliance with regulatory requirements; and

•

the rate at which production volumes on our wells naturally decline.

Formation of Empire Energy Holdings, Inc.

Pursuant to a plan of conversion, as soon as practicable after the effectiveness of the registration statement of which this prospectus is a part, Imperial will file a certificate of conversion, the form of which is filed as an exhibit to the registration statement of which this prospectus is part (the “Certificate of Conversion”), with the Secretary of State of the State of Delaware, pursuant to which Imperial will convert

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into a Delaware corporation and continue in the name of Empire Energy Holdings, Inc. (“Corporate Reorganization”). Upon the filing of the Certificate of Conversion, the sole membership percentage interest of Empire Energy Group Limited (“Empire Energy Group”) in Imperial issued and outstanding immediately prior to the Corporate Reorganization will be converted automatically into shares of common stock of the Company, par value $0.01, with such shares of common stock having the respective rights, preferences and privileges set forth in the restated certificate of incorporation of the Company, the form of which is filed as an exhibit to the registration statement of which this prospectus is a part. The membership percentage interest outstanding immediately prior to the effective time of the conversion shall be converted automatically, without any action on the part of the holder thereof, into validly issued, fully paid and non-assessable shares of the Company’s common stock.

The financial data of Imperial, a holding company, are inclusive of its wholly-owned subsidiaries Empire Energy USA, LLC and Empire Energy E&P, LLC and are included in this prospectus in this discussion and analysis of our financial condition and results of operations.

Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations

Our historical financial condition and results of operations for the periods presented may not be comparable, either from period to period or going forward, for the following reasons:

Public Company Expenses. Upon completion of this offering, we expect to incur direct, incremental general and administrative (“G&A”) expenses as a result of being a publicly traded company, including, but not limited to, costs associated with annual and quarterly reports to stockholders, tax return preparation, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and independent director compensation. We estimate these direct, incremental G&A expenses will be approximately $0.5 million per year. These direct, incremental G&A expenses are not included in our historical results of operations.

Income Taxes. Imperial, our accounting predecessor, is a limited liability company taxed as a C Corporation for federal and state income taxes, subject to federal and state income taxes at statutory rates. Accordingly, a provision for federal and state income taxes has been provided.

Financing Arrangements.

Imperial, through Empire Energy E&P, LLC and Empire Energy USA, LLC, maintains a facility consisting of the following, which was extended in 2013 to mature in February 2016 with the same terms:

•

A $50.0 million revolving line-of-credit facility (the “Revolver”) was used to refinance existing debt and to undertake future acquisitions. The Revolver is subject to a borrowing base consistent with normal and customary oil and gas lending practices of the bank. The borrowing base limit at the time of the extension was $3.0 million and is re-determined from time to time in accordance with the Revolver. With only $3.0 million currently drawn on the Revolver we have additional borrowing base availability under the Revolver of $10.0 million. Interest accrues on the outstanding borrowings at rate options selected by the Company and based on the prime lending rate (3.25% at March 31, 2014) or the London Inter-Bank Offered Rate (60-Day LIBOR) (0.19855% at March 31, 2014) plus 2.5%. At March 31, 2014, the Company’s rate option was LIBOR. At the last review of the Revolver by the lender in February 2014, there is additional borrowing base availability under the Revolver of around $10.0 million. However, the borrowing base limit changes with operations and opportunities; and

•

A $150.0 million acquisition and development term credit facility (the “Term Facility”) was used to refinance an existing facility, undertake acquisitions and support capital expenditures under an agreed development plan for oil and gas properties and services companies in the United States. Drawdown on the Term Facility is based on predefined benchmarks. Interest accrues on the outstanding borrowings at rate options selected by the Company and based on the prime lending rate (3.25% at March 31, 2014) or the London Inter-Bank Offered Rate (60-Day LIBOR) (0.19855% at March 31, 2014) plus 2.5%. At March 31, 2014, the Company’s rate option was LIBOR.

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Loans under the facilities are secured by the assets of the Company. Under the terms of the facilities, the Company is required to maintain financial ratios customary for the oil and gas industry. Beginning in March 2008, the Company started to repay the facilities monthly to the extent of an applicable percentage of net operating cash flow and capital transactions. The Revolver and Term Facility loans are guaranteed by Empire Energy Group.

Imperial has a related party payable with Empire Energy Group. The outstanding balance on this line is $7.4 million at March 31, 2014.

Revenue

We market our oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets. To mitigate the potential negative impact on our cash flow caused by changes in oil and natural gas prices, we have entered into financial commodity derivative contracts in the form of NYMEX based futures contracts for approximately 70% of our future oil and natural gas production when management believes that favorable future prices can be secured.

Oil. The NYMEX-WTI futures price is a widely used benchmark in the pricing of domestic and imported oil in the United States. The actual prices realized from the sale of oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (1) the oil’s American Petroleum Institute, or API, gravity and (2) the oil’s percentage of sulfur content by weight. In general, lighter oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, normally sells at a higher price than heavier oil. Oil with low sulfur content (“sweet” oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content oil (“sour” oil). Our oil is Kansas Mid-grade which is considered “sour”.

Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the produced oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to oil that is produced farther from such markets. Consequently, oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).

The oil produced from our properties is a combination of sweet and sour oil, varying by location. We sell our oil at the NYMEX-WTI price, which is adjusted for quality and transportation differential, depending primarily on location and purchaser. The differential varies, but our oil normally sells at a discount to the NYMEX-WTI price.

Natural Gas. The NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. Similar to oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (1) the Btu content of natural gas, which measures its heating value, and (2) the percentage of sulfur, CO and other inert content by volume. Wet natural gas with a high Btu content sells at a premium to low Btu content dry natural gas because it yields a greater quantity of NGLs. Natural gas with low sulfur and CO content sells at a premium to natural gas with high sulfur and CO content because of the added cost to separate the sulfur and CO from the natural gas to render it marketable. All of the Company’s natural gas production is dry and is generally sold based on NYMEX-Henry Hub prices plus a differential in the region from which it is produced.

Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the

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form of percentage of proceeds. Generally, these differentials have historically been at a premium to NYMEX-Henry Hub natural gas prices. Because of the increase in shale gas production the location differentials are currently at a discount to NYMEX-Henry Hub natural gas prices.


	Three Months Ended March 31,						Year Ended December 31,
	2014			2013			2013			2012
Oil
NYMEX WTI High	$	104.92		$	97.94		$	110.53		$	109.77
NYMEX WTI Low		91.66			90.12			86.68			77.69
Differential to Average NYMEX WTI		(5.99	)		(5.12	)		(5.20	)		(5.68	)
Natural Gas
NYMEX Henry Hub High	$	6.14		$	4.06		$	4.46		$	3.90
NYMEX Henry Hub Low		4.00			3.11			3.11			1.90
Differential to Average NYMEX Henry Hub		0.00			0.39			0.14			0.06

We sell substantially all of our oil and natural gas to two customers. In 2013, sales to Coffeyville Resources Refining & Marketing, LLC comprised 95% of our oil sales, and sales to National Fuel Resources, Inc. comprised 81% of our natural gas sales. If any significant customer decided to stop purchasing oil and natural gas from us, our revenues could decline and our operating results and financial condition could be harmed. However, based on the current demand for oil and natural gas, and the availability of other purchasers, we believe that the loss of any one or all of our significant customers would not have a material adverse effect on our financial condition and results of operations, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers.

Principal Components of our Cost Structure

•

Lease operating expense. These are the day to day operating costs incurred to maintain production of our natural gas and oil producing wells. Such costs include produced water disposal, maintenance and repairs. Cost levels for these expenses can vary based on supply and demand for services.

•

Production, Severance and Ad Valorem Taxes. Certain local jurisdictions in New York and Kansas currently impose an Ad valorem tax generally tied to the value of the oil and natural gas properties.

•

Exploration expense. These include geological and geophysical costs, seismic costs and delay rental payments.

•

General and administrative expense. We expect that we will incur additional general and administrative expenses as a result of being a publicly-traded company. Please see “— Factors That Significantly Affect Comparability of Our Financial Condition and Results of Operations — Public Company Expenses.”

•

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas. As a “successful efforts” company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts and allocate these costs to each unit of production using the units of production method.

•

Write-down on abandoned leases. These write-downs include the cost of expensing certain lease acquisition costs associated with properties that we no longer expect to drill and therefore have allowed to expire.

•

Interest expense. We have financed property acquisitions with borrowings under our revolving credit facility and term loan. As a result, we incur interest expense that is affected by the level of acquisition activities, as well as fluctuations in interest rates and our financing decisions. We will likely continue to incur significant interest expense as we continue to grow.

•

Income tax expense. Imperial, our accounting predecessor, is a limited liability company taxed as a C Corporation for federal and state income taxes, subject to federal and income taxes at a statutory rates. Accordingly, a provision for federal and state income taxes has been provided.

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How We Evaluate Our Operations

In evaluating our financial results, we focus on production, revenues, per unit cash production, G&A and our Adjusted EBITDAX. We define Adjusted EBITDAX as net income (loss) before interest expense or interest income; income taxes; write-down of abandoned leases; impairments; depreciation, depletion and amortization; amortization of deferred financing costs; equity in (income) loss in a joint venture; non-cash compensation expense; gain from sale of interest in gas properties; and exploration expenses. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles, or GAAP.

Management believes that the presentation of our Adjusted EBITDAX provides information useful in assessing our financial condition and results of operations and that Adjusted EBITDAX is a widely accepted financial indicator of a company’s results of operations.

Adjusted EBITDAX may not be comparable to similarly titled measures used by other companies and should be considered in conjunction with net income (loss) and other performance measures prepared in accordance with GAAP, such as operating income or cash flows from operating activities. Adjusted EBITDAX has important limitations as an analytical tool because it excludes certain items that affect net income (loss) attributable to common stockholders. Adjusted EBITDAX should not be considered in isolation or as a substitute for an analysis of our results as reported under GAAP.

We also evaluate our rates of return on invested capital in our wells. We believe the quality of our assets combined with our technical and managerial expertise can generate attractive rates of return as we develop our core acreage position in Mid-Con and Appalachia. Additionally, by focusing on concentrated acreage positions, we can build and own centralized midstream infrastructure, including low- and high-pressure gathering lines, compression facilities, which enable us to reduce reliance on third-party operators, minimize costs and increase our returns.

We measure the expected return of our wells based on return on investment (ROI) based on investment costs, anticipated flow rates, and projected sales prices, and lifting costs. To maintain positive internal cash flow, our plans are to drill low cost, low risk vertical wells that have a short payback period. If the New York fracking moratorium is lifted, our plans would be to drill horizontal wells based on ROI.

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Results of Operations

Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

Revenues in the following tables do not include well operations service fees although these fees are included in revenues as disclosed in the financial statements of Imperial included elsewhere in this prospectus.

The following tables set forth selected operating data for the three months ended March 31, 2014 compared to the three months ended March 31, 2013:


	Three Months Ended March 31,						Increase/(Decrease)
	2014			2013			$			%
	(Unaudited) (In thousands, except percentages)
Statement of Operations Data:
Revenues:
Oil sales	$	3,639		$	3,849		$	(209	)		-5	%
Natural gas sales		1,973			1,831			142			8	%
Oil and gas price risk		112			552			(439	)		-80	%
Total revenues		5,725			6,231			(506	)		-8	%
Operating Expenses:
Lease operating		2,477			2,726			(249	)		-9	%
Production, severance and ad valorem taxes		98			533			(435	)		-82	%
Exploratory dry hole costs		18			—			18
General and administrative		593			638			(45	)		-7	%
Depreciation, Depletion and amortization		1,395			1,246			149			12	%
Write-down on abandoned leases		—			42			(42	)		-99	%
Total operating expenses		4,582			5,185			(603	)		-12	%
Operating income		1,143			1,046			97			9	%
Interest expense		(608	)		(1,241	)		633			-51	%
Other income (expense)		(225	)		56			(281	)		-505	%
Income tax expense		(112	)		46			(158	)		-342	%
Net income	$	198		$	(93	)	$	291			-313	%
Revenues (In thousands, except percentages):
Oil sales	$	3,639		$	3,849		$	(209	)		-5	%
Natural gas sales		1,973			1,831			142			8	%
Oil and gas price risk		112			552			(439	)		-80	%
Total revenues	$	5,725		$	6,231		$	(506	)		-8	%
Average realized price before effects of hedges:⁽¹⁾
Oil ($/Bbl)	$	92.62		$	89.24		$	3.38			4	%
Natural gas ($/Mcf)		4.72			3.87			0.85			22	%
Combined ($/Boe)	$	51.52		$	46.57		$	4.95			11	%
Average realized price after effects of hedges:⁽¹⁾
Oil ($/Bbl)	$	86.82		$	87.02		$	(0.20	)		0	%
Natural gas ($/Mcf)		5.54			5.24			0.30			6	%
Combined ($/Boe)	$	52.55		$	51.10		$	1.45			3	%
Total production volumes:
Oil (MBbls)		39			43			(4	)		-9	%
Natural gas (MMcf)		418			473			(55	)		-12	%
Total (MBoe)		108.94			121.95			(13	)		-11	%
Average daily production volume:
Oil (Bbls/D)		437			479			(43	)		-9	%
Natural gas (Mcf/D)		4,643			5,255			(612	)		-12	%
Combined (Boe/d)		1,210			1,355			(145	)		-11	%

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	Three Months Ended March 31,				Increase/(Decrease)
	2014		2013		$			%
	(Unaudited) (In thousands, except percentages)
Operating Expenses (In thousands, except percentages):
Lease operating	$	2,477	$	2,726	$	(249	)		-9	%
Production, severance and ad valorem taxes		98		533		(435	)		-82	%
General and administrative		593		638		(45	)		-7	%
Exploratory dry hole costs		18		—		18
Depletion, depreciation and amortization		1,295		1,246		149			12	%
Write-down on abandoned leases		—		42		(42	)		-99	%
Total operating expenses		4,582		5,185		(603	)		-12	%
Interest expense		608		1,241		(633	)		-51	%
Total expenses	$	5,190	$	6,426	$	(1,236	)		-19	%
Operating Expenses (per Boe):
Lease operating	$	22.74	$	22.35	$	0.39			2	%
Production, severance and ad valorem taxes		0.90		4.37		(3.47	)		-79	%
Exploratory dry hole costs		0.17		—		0.17
General and administrative		5.45		5.23		0.22			4	%
Depletion, depreciation and amortization		12.81		10.22		2.59			25	%
Write-down on abandoned leases		0.00		0.35		(0.34	)		-99	%
Total operating expenses		42.06		42.52		(0.46	)		-1	%
Interest expense		5.58		10.17		(4.60	)		-45	%
Total expenses	$	47.64	$	52.69	$	(5.05	)		-10	%

Revenues:

Oil sales. Oil revenue decreased from $3.8 million for the quarter ended March 31, 2013 to $3.6 million for the same period in 2014. The $0.2 million decrease was a result of a decrease in production of 4.0 Mbbls for the three month period ended March 31, 2014 compared to the prior year partially offset by a $3.38/Bbl increase in price. The decrease in production was a result of the natural decline in production.

Natural gas sales. The increase of $0.2 million from $1.8 million for the quarter ended March 31, 2013 to $2.0 million for the same quarter in 2014 was a result of a 22%, or $0.85/Mcf, increase in average prices before the effect of hedges partially offset by a decrease in production of 55 MMcf compared to the prior year’s period. The decrease in production was a result of well shut-ins due to inclement weather during the first quarter of 2014.

Oil and gas price risk. Gain on derivative instruments was $0.6 million for the quarter ended March 31, 2013 compared to $0.1 million for the same period in 2014, resulting in a $0.4 million decrease in gains in derivative instruments in 2014. The $0.1 million gain on settled derivatives contracts for the quarter ended March 31, 2014 was comprised of a $0.2 million loss for oil contracts and a $0.3 million gain for gas contracts.

Operating Expenses:

Lease operating. The decrease in lease operating expenses from $2.7 million for the quarter ended March 31, 2013 to $2.5 million for the same period in 2014 was due to a decrease in non-recurring repair expenses in 2014. Expenses increased from $22.35/Boe to $22.74/Boe due to a decrease in production.

Production, severance, and ad valorem taxes. Taxes decreased by $0.4 million from $0.5 million to $0.1 million due to a change to an accrual basis from a cash basis. Taxes decreased from $4.37/Boe to $0.90/Boe.

General and administrative. The decrease of $0.1 million for the quarter ended March 31, 2014 versus the same period in 2013 was primarily attributable to a decrease in professional service fees. G&A increased from $6.23/Boe to $5.45/Boe due to a decrease in production.

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Depreciation, depletion, and amortization. The increase of $0.4 million or $1.45/Boe was a result of higher average capitalized costs in 2013 compared to 2012.

Write-down on abandoned leases. There were no write downs of abandoned leases for the quarter ended March 31, 2014 compared to the same period in 2013 resulting in a $0.04 million decrease in the write down of abandoned leases in 2014.

Interest expense. Interest expense was $0.6 million for the quarter ended March 31, 2014 compared to $1.2 million for the same period in 2013, resulting in a decrease of $0.6 million in 2014 that was primarily attributable to lower levels of average borrowings outstanding and the reduction of deferred financing costs during the period.

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Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

The following tables set forth selected operating data for the year ended December 31, 2013 compared to the year ended December 31, 2012:


	Year Ended December 31,						Increase/(Decrease)
	2013			2012			$			%
	(In thousands, except percentages)
Statement of Operations Data:
Revenues:
Oil sales	$	15,276		$	16,245		$	(968	)		-6	%
Natural gas sales		7,566			5,770			1,796			31	%
Oil and gas price risk		2,135			4,259			(2,124	)		-50	%
Total revenues		24,977			26,273			(1,296	)		-5	%
Operating Expenses:
Lease operating		9,257			9,283			(26	)		0	%
Production, severance and ad valorem taxes		1,163			858			305			36	%
Exploratory dry hole costs		729			197			532			270	%
General and administrative		3,463			3,431			32			1	%
Depreciation, depletion and amortization		5,855			5,435			419			8	%
Write-down on abandoned leases		152			1,027			(875	)		-85	%
Total operating expenses		20,619			20,231			388			2	%
Operating income		4,358			6,043			(1,684	)		-28	%
Interest expense		(4,381	)		(8,827	)		4,446			-50	%
Other income (expense)		143			(243	)		386			-159	%
Income tax expense		(30	)		2,188			(2,218	)		-101	%
Net income	$	91		$	(839	)	$	930			-111	%
Revenues (In thousands, except percentages):
Oil sales	$	15,276		$	16,245		$	(968	)		-6	%
Natural gas sales		7,566			5,770			1,796			31	%
Oil and gas price risk		2,135			4,259			(2,124	)		-50	%
Total revenues	$	24,977		$	26,273		$	(1,296	)		-5	%
Average realized price before effects of hedges:⁽¹⁾
Oil ($/Bbl)	$	92.85		$	88.47		$	4.38			5	%
Natural gas ($/Mcf)		3.87			2.88			0.99			35	%
Combined ($/Boe)	$	46.59		$	42.52		$	4.08			10	%
Average realized price after effects of hedges:⁽¹⁾
Oil ($/Bbl)	$	86.53		$	85.14		$	1.39			2	%
Natural gas ($/Mcf)		5.50			5.31			0.19			4	%
Combined ($/Boe)	$	50.95		$	50.74		$	0.21			0	%
Total production volumes:
Oil (MBbls)		165			184			(19	)		-10	%
Natural gas (MMcf)		1,954			2,005			(51	)		-3	%
Total (Boe)		490.26			517.78			(28	)		-5	%

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	Year Ended December 31,				Increase/(Decrease)
	2013		2012		$			%
	(In thousands, except percentages)
Average daily production volume:
Oil (Bbls/D)		451		503		(52	)		-10	%
Natural gas (Mcf/D)		5,354		5,493		(139	)		-3	%
Combined (Boe/d)		1,343		1,419		(75	)		-5	%
Operating expenses (In thousands, except percentages):
Lease operating	$	9,257	$	9,283	$	(26	)		0	%
Production, severance and ad valorem taxes		1,163		858		305			36	%
Exploratory dry hole costs		729		197		532			270	%
General and administrative		3,463		3,431		32			1	%
Depreciation, depletion and amortization		5,855		5,435		419			8	%
Write-down on abandoned leases		152		1,027		(875	)		-85	%
Total operating expenses		20,619		20,231		388			2	%
Interest expenses		4,381		8,827		(4,446	)		-50	%
Total expenses	$	24,999	$	29,057	$	(4,058	)		-14	%
Operating expenses (per Boe):
Lease operating	$	18.88	$	17.93	$	0.95			5	%
Production, severance and ad valorem taxes		2.37		1.66		0.72			43	%
Exploratory dry hole costs		1.49		0.38		1.11			291	%
General and administrative		7.06		6.63		0.44			7	%
Depreciation, depletion and amortization		11.94		10.49		1.45			7.5	%
Write-down on abandoned leases		0.31		1.98		(1.67	)		-84	%
Total operating expenses		42.06		39.07		2.99			8	%
Interest expenses		8.94		17.05		(8.11	)		-48	%
Total expenses	$	50.99	$	56.12	$	(5.13	)		-9	%

Revenues:

Oil revenue. Oil revenue decreased from $16.2 million for the year ended December 31, 2012 to $15.3 million in 2013. The $1.0 million decrease was a result of a decrease in production of 19 MBbls in 2013 compared to the prior year, partially offset by a 5% increase in average prices before the effect of hedges. The decrease in production was a result of the natural decline in production.

Natural gas sales. The $1.8 million increase from $5.8 million in 2012 to $7.6 million in 2013 was a result of a 35% increase in average prices before the effect of hedges partially offset by a decrease in production of 51 MMcf compared to the prior year. The decrease in production was a result of gathering line repairs during the summer months and the natural decline in production.

Oil and gas price risk. Gain on derivative instruments was $4.3 million in 2012 versus $2.1 million in 2013 resulting in a $2.1 million decrease in gains on settled derivatives contracts in 2013. The gain on settled derivatives contracts in 2013 was comprised of $1.0 million loss for oil contracts offset by a $3.1 million gain for gas contracts.

Operating Expenses:

Lease operating. The $0.03 million decrease in lease operating expenses was primarily due to decreased production volumes in 2013 compared to 2012, partially offset by certain non-recurring repair expenses.

Production, severance and ad valorem taxes. Taxes increased by $0.3 million or $0.72/Boe due to an increase in tax rates and a decrease in production.

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General and administrative. The increase of $0.03 million was primarily attributable to an increase in professional service fees.

Depreciation, depletion and amortization. The increase of $0.4 million or $1.45/Boe was a result of higher average capitalized costs in 2013 compared to 2012.

Write-down on abandoned leases. The $0.2 million write-off in 2013 versus the write-off of $1.0 million in 2012 was attributable to our abandonment of certain leases that are outside our core areas of drilling focus.

Interest expense. The decrease of $4.4 million in interest expense from $8.8 million in 2012 to $4.4 million in 2013 was primarily attributable to lower levels of average borrowings outstanding and the reduction of deferred financing costs during the 2013 period.

Liquidity and Capital Resources

Our primary sources of liquidity have been from our borrowings under bank credit facilities and our positive cash flow from operations. Our primary use of capital has been the acquisition and development of oil and natural gas properties. As we pursue reserve and production growth, we monitor which capital resources, including equity and debt financings, are available to us to meet our future financial obligations, planned capital expenditure activities and liquidity requirements. We also expect to fund a portion of these requirements with cash flow from operations as we continue to bring additional production online.

Our future success in growing proved reserves and production will be highly dependent on the capital resources available to us. We expect to fund our 2014 capital expenditures with cash generated by operations, borrowings under our revolving credit facility and a portion of the net proceeds of this offering. If our lenders do not increase our borrowing base, we may seek alternate debt financing or reduce our capital expenditures. The failure to achieve projected production and cash flows from operations from such wells could result in a reduction to our 2014 capital budget. Our 2014 capital budget may be further adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil or natural gas prices decline to levels below our acceptable levels, or costs increase to levels above our acceptable levels, we could choose to defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe will have the highest expected rates of return and potential to generate near-term cash flow. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flow and other factors both within and outside our control.

We believe that operating cash flows, available borrowings under our revolving credit facility and the proceeds to us from this offering should be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies. However, to the extent that we consider market conditions favorable, we may access the capital markets to raise capital from time to time to fund acquisitions, pay down our revolving credit facility and for general working capital purposes.

Planned 2014 capital expenditures are not dependent on an increase in borrowing base. There already exists capacity under our existing facility, plus cash flow being generated to undertake the current 2014 development program. This may change if the Company wishes to undertake certain actions, such as an acquisition, for example.

See “Debt Agreements” below for additional details on our outstanding borrowings and available liquidity under our various financing arrangements.

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Cash Flows

The following table summarizes our cash flows for the periods indicated:


	Three Months Ended March 31,						Year Ended December 31,
	2014			2013			2013			2012
	(Unaudited)
	(In thousands)
Net cash provided by (used in):
Operating activities	$	473		$	2,005		$	9,224		$	15,794
Investing activities		(769	)		(434	)		(3,162	)		(4,246	)
Financing activities		959			(2,114	)		(8,226	)		(8,745	)
Net increase (decrease) in cash	$	663		$	(543	)	$	(2,164	)	$	2,803

Cash Flow Provided by Operating Activities

Net cash provided by operating activities was $0.5 million for the three months ended March 31, 2014, compared to $2.0 million of net cash provided by operating activities for the three month period ended March 31, 2013. The change in operating cash flow was the result of a $0.3 million increase in net income and a $1.5 million net decrease in accounts receivable items offset by a decrease in depreciation, depletion and amortization of $0.5 million.

For the full year 2013, net cash provided by operating activities was $9.2 million compared to net cash provided by operating activities of $15.8 million for the year ended December 31, 2012. The decrease in cash flow from operations for the year ended December 31, 2013 compared to 2012 was primarily due to a decrease in accounts payable and accrued liabilities.

Cash Flow Used In Investing Activities

During the three months ended March 31, 2014 and 2013, cash flows used in investing activities were $0.8 million and $0.4 million, respectively. The increase was primarily related to our capital expenditures for drilling and leasing activities.

During the years ended December 31, 2013 and 2012, cash flows used in investing activities were $3.2 million and $4.2 million, respectively, primarily related to our capital expenditures for drilling, development and leasing activities.

Cash Flow Provided by Financing Activities

Net cash provided by financing activities was $1.0 million during the three months ended March 31, 2014, compared to $2.1 million used in financing activities for the three months ended March 31, 2013, and was the result of the repayment of debt borrowings in 2013. There was a $1.0 million borrowing for the three months ended March 31, 2014.

Net cash used in financing activities of $8.2 million and $8.7 million during the years ended December 31, 2013 and 2012, respectively, was primarily the result of the repayment of debt borrowings.

Capital Resources

In 2014, we anticipate making capital expenditures for drilling excluding any acquisitions, of up to approximately $5.0 million. Based on expenditures to date and forecasted for the remainder of 2014, we expect to allocate 72% of our capital expenditures to the Mid-Con region and 28 percent to the Appalachian region. This allocation includes approximately 96% for drilling and completions, and the remainder for miscellaneous capital items. The forecast assumes we will have two rigs running in the Mid-Con and one rig running in the Appalachian region.

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Debt Agreements

The Company, through Empire Energy USA, LLC and Empire Energy E&P, LLC, maintains a facility consisting of the following, which was extended in 2013 to mature in February 2016 with the same terms:

A $150.0 million acquisition and development term credit facility (the “Term Facility” and, together with the “Revolver”, the “Facilities”) was used to refinance an existing facility, undertake acquisitions and support capital expenditure under an agreed development plan for oil and gas properties and services companies in the United States. Drawdown on the Term Facility is based on predefined benchmarks. Interest accrues on the outstanding borrowings at rate options selected by the Company and based on the prime lending rate (3.25% at March 31, 2014) or the London Inter-Bank Offered Rate (60-Day LIBOR) (0.19855% at March 31, 2014) plus 2.5%. At March 31, 2014, the Company’s rate option was LIBOR.

Loans under the Facilities are secured by the assets of the Company. Under terms of the Facilities, the Company is required to maintain financial ratios customary for the oil and gas industry. Beginning in March 2008, the Company started to repay the Facilities monthly to the extent of an applicable percentage of net operating cash flow and capital transactions. The Revolver and Term Facility are guaranteed by Empire Energy Group.

We do not currently have any derivatives in place to mitigate the effects of interest rate risk. We may implement an interest rate hedging strategy in the future.

The Facilities are secured by liens on substantially all of our properties and guarantees from our subsidiaries. The Facilities contain restrictive covenants that may limit our ability to, among other things:

•

incur additional indebtedness;

•

sell assets;

•

make loans to others;

•

make investments;

•

enter into mergers;

•

make or declare dividends;

•

hedge future production or interest rates;

•

incur liens; and

•

engage in certain other transactions without the prior consent of the lender.

The Facilities also require us to maintain the following four financial ratios, which are measured at the end of each calendar quarter:

•

a current ratio, which is the ratio of our consolidated current assets (includes unused commitment under the credit facility and excludes derivative assets) to our consolidated current liabilities, of not less than 1.0 at the end of each fiscal quarter thereafter;

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•

a minimum interest coverage ratio, which is the ratio of consolidated EBITDAX based on the trailing twelve month period to consolidated interest expense, of not less than 3.0;

•

an asset coverage ratio, which is the ratio of the present value of our oil and gas reserves (discounted at 10% per annum) to the sum of all our secured debt of not less than 1.5 so long as any debt is outstanding under the term loan facility; and

•

a working capital ratio of not less than zero.

We were in compliance with such covenants and ratios as of March 31, 2014.

Commodity Hedging Activities

Our primary market risk exposure is in the prices we receive for our oil and natural gas production. Realized pricing is primarily driven by the NYMEX contract prices applicable to our oil and natural gas production. Pricing for oil and natural gas production have been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price.

To mitigate the potential negative impact on our cash flow caused by changes in oil and natural gas prices, we have entered into financial commodity derivative contracts in the form of NYMEX based futures contracts for approximately 70% of our future oil and natural gas production when management believes that favorable future prices can be secured.

Our hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to natural gas price fluctuations. The counterparty is required to make a payment to us for the difference between the floor price specified in the contract and the settlement price, which is based on market prices on the settlement date, if the settlement price is below the floor price. We are required to make a payment to the counterparty for the difference between the ceiling price and the settlement price if the ceiling price is below the settlement price.

By using derivative instruments to hedge exposures to changes in commodity prices, we expose ourselves to the credit risk of our counterparties. Credit risk is the potential failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. We have derivative instruments in place with the lender to the Company.

Contractual Obligations. A summary of our contractual obligations as of March 31, 2014 is provided in the following table, which does not reflect this offering or the use of proceeds therefrom.


	Apr – Dec		Payments due by period For the Years Ended December 31
	2014		2015		2016		2017		2018		Thereafter		Total
	(In thousands)
Revolver	$	—	$	—	$	3,000	$	—	$	—	$	—	$	3,000
Term facility		—		—		39,364		—		—		—		39,364
Related party payable		—		—		—		—		—		7,478		7,478
Asset retirement obligation		—		—		—		—		—		30,684		30,684
Other		26		14		2		—		—		—		43
	$	26	$	14	$	42,366	$	—	$	—	$	38,162	$	80,569

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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 of the notes to the audited consolidated financial statements for an expanded discussion of our significant accounting policies and estimates made by management.

We qualify as an “emerging growth company” as defined in Section 101 of the Jumpstart our Business Startups Act (“JOBS Act”) as we do not have more than $1,000,000,000 in annual gross revenue and did not have such amount as of December 31, 2013, our last fiscal year. We are electing to use the extended transition period for complying with new or revised accounting standards under Section 102(b)(1) of the JOBS Act. As a result of this election, our financial statements may not be comparable to companies that comply with public company effective dates.

Sales of oil and natural gas are recognized when the product has been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured, and the sales price is fixed or determinable. Natural gas is sold by the Company under contracts with terms ranging from one month up to the life of the well. Oil is sold by the Company under annually reviewed contracts. Virtually all of the Company contracts’ pricing provisions are tied to a market index with certain adjustments based on, among other factors, for natural gas whether a well delivers to a gathering or transmission line, quality of natural gas and prevailing supply and demand conditions, so that the price of the natural gas fluctuates to remain competitive with other available natural gas suppliers and for oil the API delivered at each sales point. As a result, the Company’s revenues from the sale of oil and natural gas will suffer if market prices decline and benefit if they increase. The Company believes that the pricing provisions both of its oil and natural gas contracts are customary in the industry. Because there are timing differences between the delivery of oil and natural gas and the Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and the Company’s estimates of the related transportation and compression fees, which are, in turn, based upon applicable product prices. The Company currently uses the “net-back” method of accounting for transportation arrangements of its natural gas and oil sales. The Company sells gas and oil at the wellhead and collects a price and recognizes revenues based on the wellhead sales price, since transportation costs downstream of the wellhead are incurred by the customers and reflected in the wellhead price.

Derivatives

The Company utilizes interest rate swap agreements and oil and gas forward contracts to manage the exposure to interest rate changes on certain variable rate credit agreements and price volatility, respectively. The Company recognizes its derivatives on the consolidated balance sheets at fair value at the end of each period. Changes in the fair value of the interest rate swaps oil and gas forward contracts that are designated and meet the required criteria for a cash flow hedge are reported in accumulated other comprehensive income.

Oil and Gas Properties

The Company uses the successful efforts method of accounting for oil and gas-producing activities. Costs to acquire mineral interests in oil and gas properties, drill and equip exploratory wells that find proved reserves, and drill and equip development wells and related asset retirement costs are capitalized. Depletion is based on cost less estimated salvage value using the unit-of-production method. The process of estimating and

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evaluating oil and gas reserves is complex, requiring significant decisions in the evaluation of geological, geophysical, engineering and economic data. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed.

Unproved oil or gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Capitalized costs of producing oil and gas properties and support equipment directly related to such properties, after considering estimated residual salvage values, are depreciated and depleted by the units of production method. Support equipment and other property and equipment not directly related to oil or gas properties are depreciated over their estimated useful lives.

Management’s estimates of proved reserves are based on quantities of oil and natural gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic conditions. External engineers prepare the annual reserve and economic evaluation of all properties on a well-by-well basis. Additionally, we adjust oil and natural gas reserves for major well rework or abandonment during the year as needed. The process of estimating and evaluating oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have a material effect on our net income or loss.

On the sale of an entire interest in an unproved property for cash, a gain or loss on the sale is recognized, taking into consideration the amount of any recorded impairment if the property had been assessed individually. If a partial interest in an unproved property is sold, the amount received is treated as a reduction of the cost of the interest retained unless the proceeds received are in excess of the cost basis which would result in gain on sale.

Oil and Natural Gas Reserves

Our estimates of proved reserves are based on the quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions and operating methods. Our independent petroleum engineers, Ralph E. Davis Associates, Inc. and LaRoche Petroleum Consultants, Ltd., prepare a reserve and economic evaluation of all of our properties on a well-by-well basis. The accuracy of reserve estimates is a function of the:

•

quality and quantity of available data;

•

interpretation of that data;

•

accuracy of various mandated economic assumptions; and

•

judgment of the independent reserve engineer.

Estimating reserves is subjective and actual quantities of oil and natural gas ultimately recovered can differ from estimates for many reasons. Future prices received for production and future production costs may vary, perhaps significantly, from the prices and costs assumed for purposes of calculating reserve estimates. We may not be able to develop proved reserves within the periods estimated. Actual production may not equal the estimated amounts used in the preparation of reserve projections. As these estimates change, calculated reserves change. Any change in reserves directly impacts our estimate of future cash flows from the property, the property's fair value and our DD&A rate.

Our independent petroleum engineers, Ralph E. Davis Associates, Inc. and LaRoche Petroleum Consultants, Ltd., estimate our proved reserves annually on December 1 and December 31, respectively. This results in a new DD&A rate which we use for the preceding fourth quarter after adjusting for fourth quarter

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production. We internally estimate reserve additions and reclassifications of reserves from unproved to proved at the end of the second and fourth quarters for use in determining a DD&A rate for the respective half year and year.

For a discussion of the preparation of reserve estimates, internal controls and qualification of responsible technical persons, see “Business — Our Properties — Oil & Natural Gas Reserves — Preparation of Reserve Estimates”, “— Internal Controls,” and “— Qualification of Responsible Technical Persons.”

Depletion

Capitalized amounts attributable to proved oil and gas properties are depleted by the unit-of-production method over proved reserves. Depletion of the costs of wells and related equipment and facilities, including capitalized asset retirement costs, is computed using proved developed reserves. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves.

Asset Retirement Obligations

The Company accounts for its asset retirement obligations as required by the Asset Retirement and Environmental Obligations topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification (Codification), which requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. For the Company, asset retirement obligations primarily relate to the plugging and abandonment of gas-producing facilities.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted, risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulations enact new plugging and abandonment requirements.

Income Taxes

Imperial is a limited liability company taxed as a C Corporation for federal and state income tax purposes. The liability method is used to account for income taxes, which requires deferred taxes to be recorded at the statutory rate expected to be in effect when the taxes are paid. Deferred income taxes are provided for the tax effect of temporary differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements. Valuation allowances are provided for a deferred tax asset when it is more likely than not that the asset will not be realized. Income tax penalties and interest are included in the provision for income taxes.

Unproved Properties and Impairments

Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment by providing an impairment allowance. Management determined that no impairment allowance was necessary at the end of 2013 and 2012. Long-lived assets to be held and used or disposed of other than by sale are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount might not be recoverable. When required, impairment losses on assets to be held and used or disposed of other than by sale are recognized based on the fair value of the asset. Long-lived assets to be disposed of by sale are reported at the lower of their carrying amount or fair value less cost to sell. As of 2013 and 2012, no impairment expense was recorded.

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Internal Controls and Procedures

We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes-Oxley Act of 2002, and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a public company, we will be required to comply with the SEC's rules implementing Section 302 of the Sarbanes-Oxley Act of 2002, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. We will not be required to make our first assessment of our internal control over financial reporting under Section 404 until the year following our first annual report required to be filed with the SEC.

Recent Accounting Pronouncements

Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. The amendments do not change the current requirements for reporting net income or other comprehensive income in financial statements. However, the amendments require an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. The adoption of this topic had no impact on the Company.

Quantitative and Qualitative Disclosure about Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for hedging purposes, rather than for speculative trading.

Commodity price risk and hedges

For a discussion of how we use financial commodity derivative contracts to mitigate some of the potential negative impact on our cash flow caused by changes in oil and natural gas prices, see “— Commodity Hedging Activities.”

Interest rate risks

The Company maintains a facility consisting of the following, which was extended in 2013 to mature in February 2016 with the same terms:

A $150.0 million acquisition and development term credit facility (Term Facility) was used to refinance an existing facility, undertake acquisitions and support capital expenditure under an agreed development plan for oil and gas properties and services companies in the United States. Drawdown on the Term Facility is

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based on predefined benchmarks. Interest accrues on the outstanding borrowings at rate options selected by the Company and based on the prime lending rate (3.25% at March 31, 2014) or the London Inter-Bank Offered Rate (60-Day LIBOR) (0.19855% at March 31, 2014) plus 2.5%. At March 31, 2014, the Company’s rate option was LIBOR.

Loans under the facilities are secured by the assets of the Company. Under terms of the facilities, the Company is required to maintain financial ratios customary for the oil and gas industry. Beginning in March 2008, the Company started to repay the facilities monthly to the extent of an applicable percentage of net operating cash flow and capital transactions. The Revolver and Term loans are guaranteed by Empire Energy Group.

Imperial has a related party payable with Empire Energy Group. The outstanding balance on this line is $7.5 million at March 31, 2014.

We do not currently have any derivatives in place to mitigate the effects of interest rate risk. We may implement an interest rate hedging strategy in the future.

Counterparty and customer credit risk

Our principal exposures to credit risk are through joint interest receivables ($0.4 million at March 31, 2014) and the sale of our oil and natural gas production ($3.3 million in receivables at March 31, 2014). We market a majority of our production to a single oil refinery and to a single natural gas marketing company. Joint interest receivables arise from billing entities who own partial interest in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we wish to drill. We are also subject to credit risk due to concentration of our oil and natural gas receivables with two natural gas marketing companies. We do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Off-Balance Sheet Arrangements

We do not currently have any off-balance sheet arrangements.

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BUSINESS

Unless the context indicates or otherwise requires, the estimated proved reserve information and other operating data included in this prospectus reflects the combination of our estimated proved reserve information and production data. The estimated proved reserve information for our properties contained in this prospectus are based on reserve reports relating thereto prepared by the independent petroleum engineers of Ralph E. Davis Associates, Inc. for Appalachia and LaRoche Petroleum Consultants, Ltd. for Mid-Continent. We refer to these reports collectively as our “reserve reports.”

Our Company

We are an independent returns-focused exploration and production company focused on the acquisition, exploration and development of conventional oil and natural gas reserves in the Kansas (Mid-Continent), New York and Pennsylvania (Appalachia) regions. We operate approximately 300 producing wells in the Mid-Continent and approximately 1,700 producing wells in the Appalachian Basin. Our drilling activity is currently focused on the low-risk vertical development of the Arbuckle and Lansing/Kansas City formations located in Central Kansas (Mid-Continent) and the Upper Devonian Bradford Group, which is an oil and liquids-rich producing formation located in Upstate New York (Appalachia). We also have a significant number of natural gas producing Medina formation development locations which are marginally economic at current natural gas prices. Additionally, we have significant acreage in the Marcellus Shale and Utica Shale fairways, value extraction from which is dependent upon the lifting of the New York moratorium on high volume fracking of horizontal wells. We intend to position ourselves to take advantage of our New York State shale resources if and when the moratorium is lifted.

Our acreage position was 306,476 gross (278,527 net) acres at March 31, 2014, which we group into two primary areas based on geographic locations, Mid-Continent and Appalachia, which are comprised of approximately 22,869 gross (17,609 net) acres and 283,607 gross (260,918 net) acres, respectively.

The following table summarizes our leasehold position by state as of March 31, 2014:

Developed

Registration No. 333-197257

UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549

AMENDMENT NO. 1TOFORM S-1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

IMPERIAL RESOURCES, LLC

EMPIRE ENERGY HOLDINGS, INC.

380 Southpointe Boulevard, Suite 130 Canonsburg, Pennsylvania 15317 (724) 483-2070

Bruce W. McLeod Chief Executive Officer 380 Southpointe Boulevard, Suite 130 Canonsburg, Pennsylvania 15317 (724) 483-2070

CALCULATION OF REGISTRATION FEE

SUBJECT TO COMPLETION, DATED AUGUST 8, 2014

PRELIMINARY PROSPECTUS

Shares

Common Stock

Maxim Group LLC

Total Company

TABLE OF CONTENTS

PROSPECTUS SUMMARY

Our Company

Competitive Strengths

Business Strategies

Recent Developments

Risks Related to Our Business

Implications of Being an Emerging Growth Company

Corporate Reorganization

Corporate Information

THE OFFERING

SUMMARY CONSOLIDATED FINANCIAL DATA

Non-GAAP Financial Measures

SUMMARY RESERVE AND OPERATING DATA

Production, Revenues and Price History

RISK FACTORS

Risks Related to Our Business and Industry

Natural gas, NGL and oil prices are volatile. A substantial or extended decline in commodity prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.

Our development and exploration projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our natural gas reserves.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could result in a total loss of investment or otherwise adversely affect our business, financial condition or results of operations.

We have incurred losses from operations for various periods since our inception and may do so in the future.

Insufficient takeaway capacity in the Appalachian Basin could cause significant fluctuations in our realized natural gas prices.

Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The standardized measure of discounted future net cash flows from our proved reserves will not be the same as the current market value of our estimated oil and natural gas reserves.

We may incur losses as a result of title defects in the properties in which we invest.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

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

Our derivative activities could result in financial losses or could reduce our earnings. In certain circumstances, we may have to purchase commodities on the open market or make cash payments under our hedging arrangements and these payments could be significant and expose us to other risks.

The inability of our significant customers, on which we depend due to the small number of significant customers, to meet their obligations to us may adversely affect our financial results.

Our operations are subject to governmental laws and regulations relating to the protection of the environment, which may expose us to significant costs and liabilities that could exceed current expectations.

Changes in laws or government regulations regarding fracking could increase our costs of doing business, limit the areas in which we can operate and reduce our oil and natural gas production, which could adversely impact our business.

Oil and natural gas producers’ operations, especially those using fracking, are substantially dependent on the availability of water. Restrictions on the ability to obtain water may impact our operations.

We are subject to risks associated with climate change.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

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

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

Market conditions or operational impediments may hinder our access to natural gas, NGL or oil markets or delay our production.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

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

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market natural gas and secure trained personnel.

The loss of senior management or technical personnel could adversely affect operations.

We are susceptible to the potential difficulties associated with rapid growth and expansion and have a limited operating history.

Seasonal weather conditions and regulations adversely affect our ability to conduct drilling activities in some of the areas where we operate.

Increases in interest rates and the lack of availability of capital could adversely affect our business.

We may be subject to risks in connection with acquisitions of properties.

The enactment of derivatives legislation, and the promulgation of regulations pursuant thereto, could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.

Certain federal income tax deductions currently available with respect to natural gas and oil exploration and development may be eliminated, and additional state taxes on natural gas extraction may be imposed, as a result of future legislation.

Risks Related to the Offering and our Common Stock

There are inherent limitations in all control systems, and misstatements due to error or fraud may occur and not be detected.

The initial public offering price of our common stock may not be indicative of the market price of our common stock after this offering. In addition, an active, liquid and orderly trading market for our common stock may not develop or be maintained, and our stock price may be volatile.

Empire Energy Group will hold a substantial majority of our common stock.

The stockholders’ agreement we expect to enter into in connection with the completion of this offering will permit our principal stockholder to designate a majority of the members of our board of directors.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

Investors in this offering will experience immediate and substantial dilution of $ per share.

We may invest or spend the proceeds of this offering in ways with which you may not agree or in ways which may not yield a return.

We do not intend to pay dividends on our common stock, and our credit facilities place certain restrictions on our ability to do so. Consequently, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

The underwriters of this offering may waive or release parties to the lock-up agreements entered into in connection with this offering, which could adversely affect the price of our common stock.

We expect to be a “controlled company” within the meaning of the NASDAQ rules and, as a result, will qualify for and could rely on exemptions from certain corporate governance requirements.

For as long as we are an emerging growth company, we will not be required to comply with certain reporting requirements, including those relating to accounting standards and disclosure about our executive compensation, that apply to other public companies.

Pursuant to Section 102(b)(1) of the JOBS Act, as an emerging growth company, we are able to use the extended transition period for complying with new or revised accounting standards.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

AMENDMENT NO. 1
TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

380 Southpointe Boulevard, Suite 130
Canonsburg, Pennsylvania 15317
(724) 483-2070

Bruce W. McLeod
Chief Executive Officer
380 Southpointe Boulevard, Suite 130
Canonsburg, Pennsylvania 15317
(724) 483-2070

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
AND INDUSTRY DATA

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

IMPERIAL RESOURCES, LLC S-1/A