UNITED
STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
| (Mark One) | ||
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2012
or
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File No. — 001-35097
EMERALD OIL, INC.
(Exact Name of Registrant as Specified in Its Charter)
| Montana | 77-0639000 | |
| (State or Other Jurisdiction of Incorporation or Organization) |
(I.R.S. Employer Identification No.) |
| 1600 Broadway, Suite 1360 | ||
| Denver, CO | 80202 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (303) 323-0008
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class | Name of Each Exchange On Which Registered | |
| Common Stock, $0.001 par value | NYSE MKT |
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a small reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
| Large Accelerated Filer ¨ | Accelerated Filer x | Non-Accelerated Filer ¨ (Do not check if a smaller reporting company) |
Smaller Reporting Company ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of the registrant’s voting and non-voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sale price as reported by the NYSE MKT Equities) was approximately $83 million.
As of March 18, 2013, the registrant had 25,899,658 shares of common stock issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant’s 2013 Annual Meeting of Shareholders, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2012, are incorporated by reference into Part III of this report.
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.
From time to time, our management or persons acting on our behalf may make forward-looking statements to inform existing and potential security holders about our company. All statements other than statements of historical facts included in this report regarding our financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this report, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “target,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about, actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.
Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: general economic or industry conditions, nationally and/or in the communities in which our company conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, our ability to raise capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, other economic, competitive, governmental, regulatory and technical factors affecting our company’s operations, products, services and prices.
We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, results actually achieved may differ materially from expected results in these statements. Forward-looking statements speak only as of the date they are made. You should consider carefully the statements in Item 1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. We do not undertake, and specifically disclaim, any obligation to update any forward-looking statements to reflect events or circumstances occurring after the date of such statements.
Readers are urged not to place undue reliance on these forward-looking statements, which speak only as of the date of this report. We assume no obligation to update any forward-looking statements in order to reflect any event or circumstance that may arise after the date of this report, other than as may be required by applicable law or regulation. Readers are urged to carefully review and consider the various disclosures made by us in our reports filed with the United States Securities and Exchange Commission (the “SEC”) which attempt to advise interested parties of the risks and factors that may affect our business, financial condition, results of operation and cash flows. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, our actual results may vary materially from those expected or projected.
GLOSSARY OF OIL AND NATURAL GAS TERMS
The definitions set forth below apply to the indicated terms as used in this report. All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.
3-D seismic. The method by which a three dimensional image of the earth’s subsurface is created through the interpretation of reflection seismic data collected over a surface grid. 3-D seismic surveys allow for a more detailed understanding of the subsurface than do conventional surveys and contribute significantly to field appraisal, exploitation and production.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.
Boe. Barrels of oil equivalent in which six Mcf of natural gas equals one Bbl of oil.
Boe/d. Boe per day.
BTU. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
Completion. The installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Development well. A well drilled within the proved areas of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Held by production. A provision in an oil and gas lease that extends a company’s right to operate a lease as long as the property produces a minimum quantity of oil and natural gas.
Mcf. One thousand cubic feet of natural gas.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NYMEX. The New York Mercantile Exchange, which is a designated contract market that facilitates and regulates the trading of oil and natural gas contracts subject to NYMEX rules and regulations.
Operator. The individual or company responsible for the exploration, exploitation and production of an oil or natural gas well or lease.
PV10%. The estimated future net revenue, discounted at a rate of 10% per annum, before income taxes and with no price or cost escalation or de-escalation in accordance with guidelines promulgated by the SEC.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Proved developed producing reserves (PDP). Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production.
Proved developed non-producing reserves (PDNP). Proved oil and natural gas reserves that are developed behind pipe, shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.
Proved developed reserves. Proved reserves that are expected to be recovered from existing wellbores, whether or not currently producing, without drilling additional wells. Production of such reserves may require a recompletion.
Proved reserves. Those 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, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation.
Proved undeveloped reserves (PUD). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Spud. Start (or restart) drilling a new well.
Standardized measure. The estimated future net revenue, discounted at a rate of 10% per annum, after income taxes and with no price or cost escalation, calculated in accordance with Accounting Standards Codification (“ASC”) 932, formerly Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
EMERALD OIL, INC.
TABLE OF CONTENTS
| Page | ||
| Part I | ||
| Item 1. | Business | 1 |
| Item 1A. | Risk Factors | 9 |
| Item 1B. | Unresolved Staff Comments | 15 |
| Item 2. | Properties | 15 |
| Item 3. | Legal Proceedings | 23 |
| Item 4. | Mine Safety Disclosures | 23 |
| Part II | ||
| Item 5. | Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities | 23 |
| Item 6. | Selected Financial Data | 25 |
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 26 |
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 36 |
| Item 8. | Financial Statements and Supplementary Data | 36 |
| Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 36 |
| Item 9A. | Controls and Procedures | 36 |
| Item 9B. | Other Information | 39 |
| Part III | ||
| Item 10. | Directors, Executive Officers and Corporate Governance | 39 |
| Item 11. | Executive Compensation | 39 |
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters | 39 |
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | 39 |
| Item 14. | Principal Accountant Fees and Services | 39 |
| Part IV | ||
| Item 15. | Exhibits and Financial Statement Schedules | 39 |
| Signatures | 44 | |
| Index to Financial Statements | F-1 | |
| i |
EMERALD OIL, INC.
ANNUAL REPORT ON FORM 10-K
FOR FISCAL YEAR ENDED DECEMBER 31, 2012
PART I
Item 1. Business
Overview
Emerald Oil, Inc., a Montana corporation (“Emerald,” the “Company,” “we,” “us,” or “our”), is a Denver-based independent exploration and production company focused on the development of operated wells in the Williston Basin in North Dakota and Montana.
On July 26, 2012, we completed the acquisition of Emerald Oil North America, Inc., formerly Emerald Oil, Inc., from Emerald Oil & Gas NL for approximately 1.66 million of our shares of common stock, which represented approximately 19.9% of our outstanding common stock as of the closing date. As part of the acquisition, we agreed to retain Emerald Oil North America’s liabilities, including approximately $20.3 million in debt. Included in the acquisition were approximately 10,600 net acres located in Dunn County, North Dakota and approximately 45,000 net acres in the Sand Wash Basin Niobrara shale oil play in northwestern Colorado and southwestern Wyoming. In connection with the closing of the acquisition, five existing members of our board of directors resigned, and their vacancies were filled with directors selected by the remaining members of our board of directors. Also in connection with the closing of the acquisition, we entered into employment agreements with six officers, J.R. Reger (Executive Chairman—formerly our Chief Executive Officer), Mike Krzus (Chief Executive Officer), McAndrew Rudisill (President), Paul Wiesner (Chief Financial Officer), Karl Osterbuhr (Vice President of Exploration and Business Development) and Mitchell R. Thompson (Chief Accounting Officer—formerly our Chief Financial Officer).
Following the closing of the acquisition, we took the following actions:
| · | changed our name from Voyager Oil Gas, Inc. to Emerald Oil, Inc.; |
| · | changed the ticker symbol for our common stock traded on the NYSE MKT from “VOG” to “EOX”; |
| · | amended our 2011 Equity Incentive Plan to increase the number of shares of our common stock authorized for issuance under the plan to 3.5 million shares; |
| · | effected a 1-for-7 reverse stock split of our common stock (all amounts herein have been retroactively adjusted to take into account the effect of the reverse stock split); and |
| · | increased the aggregate number of authorized shares of common stock available for issuance to 500,000,000 shares. |
Since the acquisition of Emerald Oil North America, we began establishing an operated drilling program in McKenzie County, North Dakota. We believe the addition of operating capabilities provides increased control over the planning and designing of well development and increases our long-term growth prospects and attractiveness to partner with others. We monitor and plan to continue to monitor offset operator drilling activity in the Williston Basin, and as development activity increases and well designs improve to enhance production and well economics, we plan to replicate the well designs and drilling and completion techniques that we believe represent best practices in the area.
As of December 31, 2012, we had approximately 46,000 net acres in the Williston Basin. Pro forma for closed and pending acquisitions in 2013, we currently hold approximately 51,000 net acres. We have identified approximately 279 net potential drilling locations on this acreage prospective for oil in the Bakken and Three Forks formations. The majority of our capital expenditures in 2013 are expected to be directed toward drilling operated Bakken and Three Forks wells. We plan to leverage our management team’s collective technical, land, financial, and industry operating experience to execute our operated well development program in the Williston Basin that we believe provides significant risk-adjusted returns on capital while enhancing the strategic value of our company.
In addition to our Williston Basin position, we hold positions in the following Rocky Mountain oil and natural gas plays. We have approximately 14,600 net acres in the Sand Wash Basin in northwest Colorado (pending an expected sale of 31,000 net acres in the Sand Wash Basin in southwest Wyoming) prospective for oil in the Niobrara formation. We have approximately 33,500 net acres in central Montana prospective for oil in the Heath formation. We have approximately 72,800 net acres in the Tiger Ridge Field located in Blaine, Hill, and Chouteau Counties, Montana, prospective for natural gas, and another approximate 1,700 net acres in the Denver-Julesburg (or DJ) Basin in Weld County, Colorado, prospective for oil in the Niobrara formation. As of December 31, 2012 our oil and natural gas production was derived from participation in wells as a non-operating partner, primarily on a heads-up, or pro rata, basis proportionate to our working interest, allowing us to participate with established operators.
| 1 |
We have been trading and expect to continue to trade or swap our non-operated acreage to increase our operated acreage and working interests in areas where we have existing acreage. Most trades are for comparable acreage and mutually beneficial for both us and the other party, as we consolidate and increase our working interests. We also intend to acquire more operated acreage through a variety of means, including cash purchases and the issuance of common stock as purchase price consideration.
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Recent Developments
White Deer Energy Securities Purchase Agreement
On February 19, 2013, we completed a private offering with affiliates of White Deer Energy L.P. (“White Deer Energy”), pursuant to which, in exchange for a cash investment of $50 million, we issued the following to White Deer Energy:
| · | 500,000 shares of a new Series A Perpetual Preferred Stock, $0.001 par value per share (the “Series A Preferred Stock”); |
| · | 5,114,633 shares of a new Series B Voting Preferred Stock, $0.001 par value per share (the “Series B Preferred Stock”); and |
| · | warrants to purchase an initial aggregate 5,114,633 shares of our common stock, $0.001 par value per share, at an initial exercise price of $5.77 per share. |
The Series A Preferred Stock has a cumulative dividend rate of 10% per annum, payable quarterly on each March 31, June 30, September 30 and December 31, commencing on March 31, 2013. If we voluntarily or involuntarily liquidate, dissolve or wind up our affairs, the Series A Preferred Stock will be entitled to receive out of our available assets, after satisfaction of liabilities to creditors, if any, and before any distribution of assets is made on our common stock or any other shares of our junior stock, a liquidating distribution in the amount, with respect to each share of Series A Preferred Stock, equal to the sum of (a)(1) on or prior February 19, 2015, $112.50, (2) from February 20, 2015 through February 19, 2016, $110.00, (3) from February 20, 2016 through February 19, 2017, $105.00 and (4) thereafter, $100.00 and (b) the accrued and unpaid dividends thereon (the “Liquidation Preference”). Prior to April 1, 2015, we may pay dividends on the Series A Preferred Stock either (x) in cash or (y) by issuance of (A) additional shares of Series A Preferred Stock valued at the same value as the initial per share purchase price of the Series A Preferred Stock and (B) an additional warrant to purchase shares of common stock; provided that such dividends must be paid in cash unless and until we obtain shareholder approval to authorize the issuance of any additional warrants and any shares of common stock issuable upon exercise of such additional warrants. We have the option to redeem shares of Series A Preferred Stock in whole or in part at any time at the aggregate Liquidation Preference, subject to a minimum redemption amount equal to the lesser of 50,000 shares or the number of shares then outstanding. Upon a change of control, the holders of the Series A Preferred Stock have the right to require us to purchase the Series A Preferred Stock at the Liquidation Preference. The Series A Preferred Stock does not vote generally with our common stock, but has specified approval rights with respect to, among other things, changes to our organizational documents that affect the Series A Preferred Stock, payment of dividends on our common stock or other junior stock, redemptions or repurchases of common stock or other capital stock and incurrence of certain indebtedness. Upon the occurrence of certain events of default under our credit facility with Wells Fargo Bank, N.A., the holders of the Series A Preferred Stock have additional specified approval rights with respect to, among other things, the incurrence or guarantee by us of any indebtedness, any change in compensation or benefits of or employment or severance agreements with our officers and any agreement or arrangement pursuant to which we or our subsidiaries would pay or incur liability in excess of $1,000,000 over the term of such agreement or arrangement.
The Series B Preferred Stock is entitled to vote, until January 1, 2020, in the election of directors and on all other matters submitted to a vote of the holders of common stock as a single class. Each share of Series B Preferred Stock has one vote. The Series B Preferred Stock has no dividend rights and a liquidation preference of $0.001 per share. On and from time to time after January 1, 2020 we may redeem, in whole or in part, the then-outstanding shares of Series B Preferred Stock, at a redemption price per share equal to $0.001.
The warrants entitle the holders thereof to acquire a number of shares of common stock equal to approximately 19.75% of our shares of common stock outstanding as of February 19, 2013, or approximately 16.49% of our outstanding Common Stock on a diluted basis taking into account the exercise of the warrants.
Amendment to Our Credit Facility
In connection with the White Deer Energy investment, we amended our credit facility with Wells Fargo Bank, N.A. to allow for the payment of dividends on the preferred stock we issued to White Deer Energy and include additional definitions related to the issuance of the Series A and Series B Preferred Stock.
Acreage Acquisitions
On January 9, 2013, we entered into a purchase and sale agreement with a third party pursuant to which we acquired leases of oil and natural gas properties in McKenzie County, North Dakota. As consideration for the approximate $4.7 million purchase price of the acquired leases, we issued 851,315 shares of our common stock at a per share value of $5.50 per share, based on the five-day trading volume-weighted average price of our common stock prior to the closing of the acquisition.
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On February 4, 2013, we entered into a purchase and sale agreement with a third party pursuant to which we acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $1.9 million purchase price of the acquired leases, we issued 313,700 shares of our common stock at a per share value of $6.058 per share, based on the five-day trading volume-weighted average price of our common stock prior to closing.
For both acquisitions, we issued the shares of common stock in reliance upon the exemption from the registration requirements under the Securities Act of 1933, as amended, provided by Section 4(2) thereof. Under the terms of each purchase and sale agreement, we granted registration rights to the seller.
Sand Wash Basin Sale
On January 7, 2013, we entered into a definitive agreement with East Management Services, LP (“East”), under which we have agreed to sell our undivided 45% working interest in and to certain oil and natural gas leaseholds in the Sand Wash Basin, comprising approximately 31,000 net acres of our 46,000 net acres located in Routt and Moffatt Counties, Colorado and Carbon County, Wyoming. The effective time for the transfer of the leases will be the date of closing, which is expected to occur during the first quarter of 2013, subject to the satisfaction of customary closing conditions and the condition that East and Entek GRB, LLC timely perform an agreement by which East will acquire Entek’s interest in the same oil and natural gas leaseholds.
The aggregate sale price is approximately $10.0 million, subject to adjustment for certain title defects and title benefits and for leases with a primary term expiring on or before June 30, 2013 that cannot be renewed or extended. The agreement may be terminated (i) by mutual agreement of the parties; (ii) by East if certain representations made by us regarding overriding royalty interests or working interests are not true; (iii) by East if during the 45-day period following execution of the agreement, title defects exceed 5% of the net acres of the certain oil and natural gas leaseholds; (iv) by East if there are any environmental claims that might result in a material adverse effect on the oil and natural gas leaseholds, or (v) by either party if East is unable to acquire Entek’s interest in the oil and natural gas leaseholds.
Production Methods
We began our operated drilling program in McKenzie County, North Dakota in November 2012. We have successfully drilled three operated wells and are in the process of drilling our fourth operated well with our continuous one-rig drilling program. The first three operated wells are scheduled to begin fracture stimulation by the end of first quarter of 2013. Going forward, we expect that revenue from oil and natural gas produced from our operated leasehold positions will increase as a percentage of our overall revenue.
Currently, all of our oil and natural gas production comes from production in which we participate on a heads-up basis alongside third-party interests in wells drilled and completed in spacing units that include our acreage. We typically depend on our drilling partners to propose, permit and initiate the drilling of wells. Prior to commencing drilling, our partners are required to provide all owners of oil, natural gas and mineral interests within the designated spacing unit the opportunity to participate in the drilling costs and revenues of the well to the extent of their pro-rata share of such interest within the spacing unit. In 2011, we participated in the drilling of all proposed wells that included any of our acreage. Beginning in 2012 and on a going forward basis, we assess each drilling opportunity on a case-by-case basis and participate in wells that we expect to meet our return thresholds based upon our estimates of ultimate recoverable oil and natural gas, expertise of the operator and completed well cost from each project, as well as other factors.
We manage our operated commodities marketing and hedging activities internally. We expect to coordinate the transportation of our oil production from our operated wells to the appropriate off-take facilities by means of truck transport at the well head, rail car transport and pipeline off-take. For our non-operated properties, our operating partners generally market and sell the oil and natural gas produced from wells in which we have an interest. Our operating partners coordinate the transportation of our oil production to the appropriate pipelines pursuant to arrangements that such partners negotiate and maintain with various parties purchasing the production. We understand that our partners generally sell our production to a variety of purchasers at prevailing market prices under separately negotiated short-term contracts. The price at which production is sold generally is tied to the spot market for oil. Williston Basin Light Sweet Crude from the Bakken and Three Forks source rock is generally 41-42 degrees API oil and is readily accepted into the pipeline infrastructure. Our average differential during 2012 was approximately $8.42 per Bbl below New York Mercantile Exchange (“NYMEX”) pricing. This differential represents the imbedded transportation costs in moving oil from the wellhead to the refinery.
2013 Capital Budget
For the 12-month period ending December 31, 2013, we plan to spend approximately $86 million on well development in the Williston Basin. Specifically, we plan to spend approximately $78.5 million ($82.5 million less $4.0 million spent during the three months ended December 31, 2012) to drill 7.5 net operated wells at an average estimated cost of $11.0 million per well and approximately $7.4 million to participate in 0.8 net non-operated wells at an average estimated cost of $9.2 million per well. In addition, we plan to spend approximately $10 million on acquiring operating acreage in the core of the Williston Basin. We expect to fund our current 2013 capital expenditure budget using cash-on-hand, cash flow from operations, proceeds from our preferred equity transaction, proceeds from assets sales, and borrowings under our revolving credit facility.
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Competition
The oil and natural gas industry is intensely competitive, particularly with respect to the acquisition of prospective oil and natural gas properties and oil and natural gas reserves. Our ability to effectively compete is dependent on our geological, geophysical and engineering expertise, and our financial resources. We compete against a substantial number of major and independent oil and natural gas companies that have larger technical staffs and greater financial and operational resources than we do. Many of these companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also have refining operations, market refined products and generate electricity. We also compete with other oil and natural gas companies to secure drilling rigs and other equipment necessary for drilling and completion of wells. Generally, as oil and natural gas prices decline, access to additional drilling equipment and completion services becomes more available. Conversely, as commodity prices increase, drilling equipment, may be in short supply from time to time. See Item 1A. Risk Factors — Competition in obtaining rights to explore and develop oil and natural gas reserves and to market our production may impair our business.
Marketing and Customers
The market for oil and natural gas we produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.
Our oil production will generally be sold at prices tied to spot oil markets. Our natural gas production is expected to be sold under long-term contracts and priced based on a set differential to daily spot market prices. We rely on our internal marketing group to sell all of our operated production and we rely on our working interest partners to sell all of our non-operated production. Our non-operated working interest partners include a variety of exploration and production companies, from large publicly traded companies to small, privately owned companies. See Item 1A. Risk Factors — We own a significant amount of operated and non-operated acreage. Our development of successful operations on our operated acreage depends on the technical expertise of our team and is inherently affected by the geology of each prospect. Our non-operated acreage relies extensively on third-parties who, if not successful, could have a material adverse effect on our results of operation.
Principal Agreements Affecting Our Ordinary Business
We do not own any physical real estate, but, instead, our acreage is comprised of leasehold interests subject to the terms and provisions of lease agreements that provide us the right to drill and maintain wells in specific geographic areas. All lease arrangements that comprise our acreage positions are established using standard terms used in the oil and natural gas industry for many years.
In general, our lease agreements stipulate three- to five-year primary terms. Bonuses and royalty rates are negotiated on a case-by-case basis consistent with industry standard pricing. Once a well is drilled and production established, the unit is considered held by production, meaning the lease continues as long as hydrocarbons are being produced. Other locations within the drilling unit created for a well may also be drilled at any time as long as the lease is held by production. Given our plans to develop our operated acreage and the current pace of drilling in the Williston Basin, we do not believe lease expirations will materially affect our acreage positions.
Governmental Regulation and Environmental Matters
Our operations are subject to various rules, regulations and limitations impacting the oil and natural gas exploration and production industry as a whole.
Regulation of Oil and Natural Gas Production
Our oil and natural gas exploration, production and related operations, when developed, are subject to extensive rules and regulations promulgated by federal, state, tribal and local authorities and agencies. For example, North Dakota, Montana and Colorado require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration and production of oil and natural gas. Such states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.
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Environmental Matters
Our operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and relating to safety and health. The recent trend in environmental legislation and regulation generally is toward stricter standards, and this trend will likely continue. These laws and regulations may:
| • | require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; |
| • | limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and |
| • | impose substantial liabilities for pollution resulting from our operations. |
The permits required for our operations may be subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines, injunctions, or both. In management’s opinion, we are in substantial compliance with current applicable environmental laws and regulations, and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on us, as well as the oil and natural gas industry in general.
The following is a summary of some of the existing laws, rules and regulations to which our operations are subject.
The Comprehensive Environmental, Response, Compensation, and Liability Act (CERCLA) and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.
The federal Safe Drinking Water Act (SDWA) and the Underground Injection Control (UIC) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. The Environmental Protection Agency (EPA) directly administers the UIC program in some states and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking salt water to groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury
Our operations are also subject to the federal Clean Water Act and analogous state laws. The Clean Water Act and similar state acts regulate other discharges of wastewater, oil, and other pollutants to surface water bodies, such as lakes, rivers, wetlands, and streams. Failure to obtain permits for such discharges could result in civil and criminal penalties, orders to cease such discharges, and costs to remediate and pay natural resources damages. Under the Clean Water Act, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, or seek coverage under a general permit. Some of our properties may require permits for discharges of storm water runoff and, as part of our overall evaluation of our current operations, we will apply for storm water discharge permit coverage and updating storm water discharge management practices at some of our facilities. We believe that we will be able to obtain, or be included under, these permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on us. These laws also require the preparation and implementation of Spill Prevention, Control, and Countermeasure Plans in connection with on-site storage of significant quantities of oil.
The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Our operations, or the operations of service companies engaged by us, may be, in certain circumstances and locations, subject to permits and restrictions under these statutes for emissions of air pollutants.
The Endangered Species Act (ESA) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish and plant species, nor destroy or modify the critical habitat of such species. Under ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize the species or its habitat. ESA provides for criminal penalties for willful violations of ESA. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expenses to modify our operations or could force us to discontinue certain operations altogether.
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Hydraulic Fracturing Concerns
The practice of hydraulic fracturing has recently become the subject of significant focus among some environmentalists, regulators and the general public. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment have been raised at all levels, including federal, state and local. There have been reports associating hydraulic fracturing with groundwater contamination, improper waste disposal, poor air quality and earthquakes. Hydraulic fracturing requires the use and disposal of significant quantities of water, and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of supply. Hydraulic fracturing techniques have been used by the industry for many years, and, currently, more than 90% of all oil and natural gas wells drilled in the U.S. employ hydraulic fracturing. We and our operating partners strive to adopt best practices and industry standards and comply with all regulatory requirements regarding well construction and operation. We have, and believe our operating partners have, established processes to help ensure that hydraulic fracturing does not pose a meaningful risk to water supplies.
Potential Rulemaking
Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal are conducting studies and considering regulations. For example, in 2011, the U.S. Secretary of Energy formed the Shale Gas Production Subcommittee, a subcommittee of the Secretary of Energy Advisory Board. The Subcommittee was charged with making recommendations to improve the safety and environmental performance of hydraulic fracturing. On August 18, 2011, the Subcommittee issued its Ninety Day Report (the “Report”), which focused exclusively on the production of natural gas (and some liquid hydrocarbons) from shale formations with hydraulic fracturing stimulation in either vertical or horizontal wells. The Subcommittee identified four primary areas of concern including possible water pollution, air pollution, disruption of the community during production, and potential for adverse impact on communities and ecosystems. The Subcommittee also set forth a list of recommendations addressing, among other areas, communications, air quality, protection of water supply and quality, disclosure of fracturing fluid composition, reduction of diesel fuel use, continuous development of best practices, and federal sponsorship of research and development with respect to unconventional gas. The Subcommittee issued its Final Report in November 2011, which recommended implementation of the Subcommittee’s recommendations by federal and state agencies. We will continue to monitor the impact the Subcommittee’s recommendations, and any resulting rule-making activities evolving at federal and state levels, could have on our exploration and development activities.
During 2012, the Bureau of Land Management (BLM) proposed regulations governing hydraulic fracturing on federal lands. The regulations would require: (1) public disclosure of chemicals used in hydraulic fracturing operations; (2) assurances on well-bore integrity to verify that fluids used in wells during fracturing operations are not escaping; and (3) confirmation of a water management plan in place for handling fracturing fluids that flow back to the surface. On January 21, 2013, the BLM announced that it was withdrawing its proposed regulations and would reissue a new set of proposed regulations regarding hydraulic fracturing later in 2013.
During 2012, the EPA proposed new guidelines under the Safe Drinking Water Act regarding the issuance of permits for the use of diesel fuel as a component in hydraulic fracturing activities. The draft guidance outlines for EPA permit writers, where the EPA is the permitting authority, requirements for diesel fuels used for hydraulic fracturing wells, technical recommendations for permitting those wells, and a description of diesel fuels for EPA underground injection control permitting.
The EPA is currently studying the potential impacts of hydraulic fracturing on drinking water resources. Results are expected to be released in a draft for public and peer review in 2014. In addition, the EPA’s recently-issued proposed rules subjecting oil and natural gas operations to regulation under the New Source Performance Standards will be applicable to newly drilled and fractured wells as well as existing wells that are refractured.
We continue to monitor new and proposed legislation and regulations to assess the potential impact on our business. Any additional federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in substantial incremental operating, capital and compliance costs as well as delay our ability to develop oil and natural gas reserves. For additional discussion, see Item 1A. Risk Factors — Federal or state hydraulic fracturing legislation could increase our costs or restrict our access to oil and natural gas reserves.
Climate Change
Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many states and the federal government have enacted legislation directed at controlling greenhouse gas emissions, and future legislation and regulation could impose additional restrictions or requirements in connection with our drilling and production activities and favor use of alternative energy sources, which could increase operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.
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Employees
We currently have 15 full time employees. Our Chief Executive Officer, Michael Krzus, and our Chief Financial Officer, Paul Wiesner, are responsible for all material employee related policy-making decisions. None of our employees are subject to a collective bargaining agreement. If drilling and production activities continue to increase, we may hire additional technical or administrative personnel as appropriate. We are using and will continue to use the services of independent consultants and contractors to perform various professional services, particularly in the area of reservoir engineering, well drilling and well completion operations.
Office Locations
Our executive offices are located at 1600 Broadway Avenue, Suite 1360, Denver, Colorado 80202. Our land operations office is located at 2718 Montana Avenue, Suite 220, Billings, Montana 59101. We believe our current office spaces will be sufficient to meet our needs for the foreseeable future.
Financial Information about Segments and Geographic Areas
Our leaseholds consist of four separate and distinct natural resource plays in the Rocky Mountain Region of the United States. We have segregated each area for the developed and undeveloped acreage and productive and exploratory wells below in Item 2. Properties. All of our oil and natural gas properties and related operations are located onshore in the United States, and management has determined that we have one reportable segment.
Available Information — Reports to Security Holders
Our website address is www.emeraldoil.com. Available on this website under “Investor Relations,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports for officers and directors, and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. These filings are also available to the public at the SEC’s Public Reference Room at 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Electronic filings with the SEC are also available on the SEC website at www.sec.gov .
We have also posted to our website our Audit Committee Charter, Compensation Committee Charter, Governance/Nominating Committee Charter and our Code of Business Conduct and Ethics, in addition to all pertinent contact information.
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Item 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. You should carefully consider the risks, uncertainties and other factors described below and all other information set forth in this Annual Report on Form 10-K. Any of the factors could materially and adversely affect our business, financial condition, operating results and prospects and could negatively impact the market price of our common stock. Also, you should be aware that the risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties, of which we are not yet aware, or that we currently consider to be immaterial may also impair our business operations.
We have a limited operating history, and may not be successful in sustaining profitable business operations.
We have a limited operating history. The business of acquiring, exploring for, developing and producing hydrocarbon reserves is inherently risky. We have a limited operating history for you to consider in evaluating our business and prospects. Our operations are therefore subject to all of the risks inherent in acquiring, exploring for, developing and producing hydrocarbon reserves, particularly in light of our limited experience in undertaking such activities. We may never overcome these obstacles.
Our business is speculative and dependent upon the implementation of our business plan and our ability to enter into agreements with third parties for the rights to exploit potential oil and natural gas reserves on terms that will be commercially viable for us.
Our lack of diversification will increase the risk of an investment in us and our financial condition and results of operations may deteriorate if we fail to diversify.
Our business is focused primarily on a limited number of properties in North Dakota and Montana. We may choose to limit our focus to a single geographic area such as the Williston Basin, which could limit our flexibility. We previously committed to joint ventures with third parties to acquire and develop acreage; we may continue to participate in joint ventures in the future, although we intend to focus on operating our own properties. Our required capital commitments may grow if the opportunity presents itself and depend upon the results of initial testing and development activities. Larger companies have the ability to manage their risk by diversification. However, we lack diversification in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than if our business were more diversified enhancing our risk profile. If we cannot diversify our operations, our financial condition and results of operations could deteriorate.
We have a history of losses which may continue and negatively impact our ability to achieve our business objectives.
We incurred net losses of $62,296,099, $1,345,054 and $4,268,569 for the fiscal years ended December 31, 2012, 2011 and 2010, respectively. We cannot assure you that we can achieve or sustain profitability on a quarterly or annual basis in the future. Our operations are subject to the risks and competition inherent in the oil and natural gas industry. We cannot assure you that future operations will be profitable. Revenues and profits, if any, will depend upon various factors, including whether we will be able to increase our revenues. We may not achieve our business objectives and the failure to achieve such goals would have an adverse impact on our business, financial condition and result of operations.
Strategic relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.
Our ability to successfully acquire additional properties, to discover reserves, to participate in exploration opportunities and to identify and enter into commercial arrangements with customers depend on developing and maintaining close working relationships with industry participants, our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and may impair our ability to grow.
To further develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we will use in our business. Our ability to successfully operate joint ventures depends on a variety of factors, many of which will be entirely outside our control. We may not be able to establish strategic relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to undertake in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.
We own a significant amount of operated and non-operated acreage. Our development of successful operations on our operated acreage depends on the technical expertise of our team and is inherently affected by the geology of each prospect. Our non-operated acreage relies extensively on third-parties who, if not successful, could have a material adverse effect on our results of operation.
To date, we have only produced oil and natural gas from wells operated by third parties. As a result, we do not control the timing or success of the development, exploitation, production and exploration activities relating to our non-operated leasehold interests. If our consultants and drilling partners are not successful in such activities relating to our leasehold interests or are unable or unwilling to perform, our financial condition and results of operation could be materially adversely affected.
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Competition in obtaining rights to explore and develop oil and natural gas reserves and to market our production may impair our business.
The oil and natural gas industry is highly competitive. Other oil and natural gas companies may seek to acquire oil and natural gas leases and other properties and services we intend to target with our investments. This competition is increasingly intense as prices of oil and natural gas on the commodities markets rise. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors or in funding joint ventures with our prospective partners. Competitors include a variety of potential investors and larger companies, which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. In addition, actual or potential competitors may be strengthened through the acquisition of additional assets and interests. If we are unable to compete effectively or adequately respond to competitive pressures, this inability may materially adversely affect our results of operation and financial condition.
We may not be able to effectively manage our growth, which may harm our profitability.
Our strategy envisions expanding our business. If we fail to effectively manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We may not be able to:
| • | meet our capital needs; |
| • | expand our systems effectively or efficiently or in a timely manner; |
| • | allocate our human resources optimally; |
| • | identify and hire qualified employees or retain valued employees; or |
| • | incorporate effectively the components of any business that we may acquire in our effort to achieve growth. |
If we are unable to manage our growth, our operations and our financial results could be adversely affected by inefficiency, which could diminish our profitability.
Our business may suffer if we do not attract and retain talented personnel.
Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting our business. We have a small management team, and the loss of key individuals or the inability to attract suitably qualified staff could materially adversely impact our business.
Our success depends on the ability of our management, employees and exploration partners to interpret market and geological data correctly and to interpret and respond to economic market and other conditions in order to locate and adopt appropriate investment opportunities, monitor such investments, and ultimately, if required, to successfully divest such investments.
Lower oil and natural gas prices, decreases in value of undeveloped acreage, lease expirations and material changes to our plans of development may cause us to record ceiling test write-downs.
We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. We recognized a ceiling test write-down for the year ended December 31, 2012 of approximately $61.9 million and we may recognize write-downs in the future if commodity prices decline or if we experience substantial downward adjustments to our estimated proved reserves.
Our hedging activities could result in financial losses or could reduce our net income or increase our net loss, which may adversely affect our business.
In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we may enter into oil and natural gas price hedging arrangements with respect to a portion of expected production that we fund. Such transactions may limit our potential gains and increase our potential losses if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:
| • | production is less than expected; |
| • | there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; or |
| • | the counterparties to our hedging agreements fail to perform under the contracts. |
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Exploration for oil and natural gas is risky and may not be commercially successful, and the advanced technologies we and our operating partners use cannot eliminate exploration risk, which could impair our ability to generate revenues from our operations.
Our future success will depend on the success of our exploration, development and production program. Oil and natural gas exploration involves a high degree of risk. These risks are more acute in the early stages of exploration. Our ability to generate a return on our investments, revenues and our resulting financial performance are significantly affected by the prices we receive for oil and natural gas produced from wells on our acreage. Especially in recent years, the prices at which oil and natural gas trade in the open market have experienced significant volatility, and will likely continue to fluctuate in the foreseeable future due to a variety of influences including, but not limited to, the following:
| • | domestic and foreign demand for oil and natural gas by both refineries and end users; |
| • | the introduction of alternative forms of fuel to replace or compete with oil and natural gas; |
| • | domestic and foreign reserves and supply of oil and natural gas; |
| • | competitive measures implemented by our competitors and domestic and foreign governmental bodies; |
| • | weather conditions; and |
| • | domestic and foreign economic volatility and stability. |
A significant decrease in oil and natural gas prices could also adversely impact our ability to raise additional capital to pursue future drilling activities.
Our expenditures on exploration may not result in new discoveries of oil or natural gas in commercially viable quantities. It is difficult to project the costs of implementing an exploratory drilling program due to the inherent uncertainties of drilling in unknown formations, the costs associated with encountering various drilling conditions, such as over-pressured zones and tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof.
Even when used and properly interpreted, three-dimensional (3-D) seismic data and visualization techniques only assist geoscientists in identifying subsurface structures and hydrocarbon indicators. They do not allow the interpreter to know conclusively if hydrocarbons are present or economically producible. In addition, the use of 3-D seismic data becomes less reliable when used at increasing depths. We could incur losses as a result of expenditures on unsuccessful wells. If exploration costs exceed estimates, or if exploration efforts do not produce results which meet expectations, the exploration efforts may not be commercially successful, which could adversely impact our ability to generate revenues from our operations.
We may not be able to develop oil and natural gas reserves on an economically viable basis, and our reserves and production may decline as a result.
If we succeed in discovering oil and/or natural gas reserves, these reserves may not be capable of the production levels we project or in sufficient quantities to be commercially viable. On a long-term basis, our viability depends on our ability to find or acquire, develop and commercially produce additional oil and natural gas reserves. Without the addition of reserves through acquisition, exploration or development activities, our reserves and production will decline over time as reserves are produced. Our future reserves will depend not only on our ability to develop then-existing properties, but also on our operating partners’ ability to identify and acquire additional suitable producing properties or prospects, to find markets for the oil and natural gas we may develop and to effectively distribute our production.
Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. In addition, drilling hazards or environmental damage could greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include delays in obtaining governmental approvals or consents, shut-downs of connected wells resulting from extreme weather conditions, problems in storage and distribution and adverse geological and mechanical conditions. We will not be able to eliminate these conditions completely in any case. Therefore, these conditions could diminish our revenue and cash flow levels and result in the impairment of our oil and natural gas interests.
We may not be able to drill wells on a substantial portion of our acreage.
We may not be able to drill on a substantial portion of our acreage for various reasons. We may not generate or be able to raise sufficient capital to do so. Future deterioration in commodities pricing may also make drilling some acreage uneconomic. Our actual drilling activities and future drilling budget will depend on drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, lease expirations, gathering system and pipeline transportation constraints, regulatory approvals and other factors. In addition, any drilling activities we are able to conduct may not be successful or add additional proved reserves to our overall proved reserves, which could have a material adverse effect on our future business, financial condition and results of operations.
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Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage.
A large portion of our acreage is not currently held by production. Unless production in paying quantities is established on units containing these leases during their terms, these leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, many of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. Further, some of our acreage is located in sections where we do not hold the majority of the acreage and therefore it is likely that we will not be named operator of these sections. On our acreage that we do not operate, we have less control over the timing of drilling and there is therefore additional risk of expirations occurring in those sections .
Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our business.
Oil and natural gas are commodities whose prices are determined based on world demand, supply and other factors, all of which are beyond our control. World prices for oil and natural gas have fluctuated widely in recent years, and we expect that prices will fluctuate in the future. Price fluctuations will have a significant impact upon our revenue, the return from our reserves and on our financial condition generally. Price fluctuations for oil and natural gas commodities may also impact the investment market for companies engaged in the oil and natural gas industry. Prices may not remain at current levels. Decreases in the prices of oil and natural gas may have a material adverse effect on our financial condition, the future results of our operations and quantities of reserves recoverable on an economic basis.
Penalties we may incur could impair our business.
Failure to comply with government regulations could subject us to civil and criminal penalties, could require us to forfeit property rights, and may affect the value of our assets. We may also be required to take corrective actions, such as installing additional equipment or taking other actions, each of which could require us to make substantial capital expenditures. We could also be required to indemnify our employees in connection with any expenses or liabilities that they may incur individually in connection with regulatory action against them. As a result, our future business prospects could deteriorate due to regulatory constraints, and our profitability could be impaired by our obligation to provide such indemnification to our employees.
We and our operating partners may have difficulty distributing our production, which could harm our financial condition.
In order to sell the oil and natural gas that we are able to produce, we and the operators of our non-operated wells may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This situation could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our ability to explore and develop properties and to store and transport our oil and natural gas production and may increase our expenses.
Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.
We may be unable to obtain additional capital that we will require to implement our business plan, which could restrict our ability to grow.
We expect that our cash position, revenues from oil and natural gas sales, proceeds from our recent preferred stock offering, and availability on our credit facility will be sufficient to fund our 2013 drilling program.
Our credit facility limits our borrowings to the lesser of the borrowing base and the total commitments. Our borrowing base was $27.5 million as of December 31, 2012. Our borrowing base is determined semi-annually, and may also be redetermined at the election of us or the banks between the scheduled redeterminations. Lower oil and natural gas prices may result in a reduction in our borrowing base at the next redetermination. A reduction in our borrowing base could require us to repay any indebtedness in excess of the borrowing base. Additionally, our credit facility contains covenants limiting our ability to incur additional indebtedness and requiring us to maintain certain financial ratios.
Future acquisitions and future exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of capital and cash flow.
We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned expansion of operations in the future.
Any additional capital raised through the sale of equity will dilute the ownership percentage of our shareholders. Raising any such capital could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of other derivative securities. In addition, we have granted and will continue to grant equity incentive awards under our equity incentive plans, which may have a further dilutive effect.
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Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the oil and natural gas industry in particular), our limited operating history, the location of our oil and natural gas properties and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us) and the departure of key employees. Further, if oil or natural gas prices on the commodities markets decline, our revenues will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), we may be required to cease our operations, divest our assets at unattractive prices or obtain financing on unattractive terms.
We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, which may adversely impact our financial condition.
Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.
This Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will vary from those estimated. Any significant variance could materially affect the estimated quantities and the value of our reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
At December 31, 2012, approximately 63% of our estimated reserves were classified as proved undeveloped. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of these oil and natural gas reserves and the costs associated with development of these reserves in accordance with SEC regulations, actual capital expenditures will likely vary from estimated capital expenditures, development may not occur as scheduled and actual results may not be as estimated.
Our ability to sell our production and/or receive market prices for our production may be adversely affected by transportation capacity constraints and interruptions.
If the amount of oil or natural gas being produced by us and others exceeds the capacity of the various transportation pipelines and gathering systems currently available in our operating areas, it will be necessary for new transportation pipelines and gathering systems to be built. Or, in the case of oil and condensate, it will be necessary for us to rely more heavily on trucks to transport our production, which is more expensive and less efficient than transportation via pipeline. Currently, we anticipate that additional pipeline capacity will be required in the Bakken and Three Forks formations to transport oil and condensate production, which increased substantially during 2012 and is expected to continue to increase. The construction of new pipelines and gathering systems is capital intensive and construction may be postponed, interrupted or cancelled in response to changing economic conditions and the availability and cost of capital. In addition, capital constraints could limit our ability to build gathering systems to transport our production to transportation pipelines. In such event, costs to transport our production may increase materially or we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at much lower prices than market or than we currently project, which would adversely affect our results of operations. A portion of our production may also be interrupted, or shut in, from time to time for numerous other reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions.
Environmental risks may adversely affect our business.
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and municipal laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. Legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner in which we expect may result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. The discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities to governments and third parties and may require us to incur costs to remedy such discharge. The application of environmental laws to our business may cause us to curtail our production or increase the costs of our production, development or exploration activities.
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Federal or state hydraulic fracturing legislation could increase our costs or restrict our access to oil and natural gas reserves.
Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act, but opponents of hydraulic fracturing have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if implemented, would subject all hydraulic fracturing to regulation under the Safe Drinking Water Act. Further, the EPA’s Office of Research and Development (ORD) is conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. The results of that study could advance the development of additional regulations. Apart from federal regulatory initiatives, states have been considering or implementing new requirements for hydraulic fracturing, including restricting its use in environmentally sensitive areas. Similarly, some localities have significantly limited or prohibited drilling activities, or are considering doing so.
Although it is not possible at this time to predict the final outcome of the ORD’s study or the requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing, any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas where we conduct business, such as the Bakken and Three Forks areas, could significantly increase our operating, capital and compliance costs as well as delay or halt our ability to develop oil and natural gas reserves. See Item 1. Business —Governmental Regulation and Environmental Matters — Hydraulic Fracturing.
Possible regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.
Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many states and the federal government have imposed requirements directed at controlling greenhouse gas emissions, and future legislation and regulation could impose additional restrictions or obligations in connection with our drilling and production activities and favor use of alternative energy sources, which could increase our operating costs or reduce the demand for petroleum products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.
Title to the properties in which we have an interest may be impaired by title defects.
Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. Title defects may exist in many of our oil and natural gas interests. In addition, we may be unable to obtain adequate insurance for title defects on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired.
Federal legislation could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.
Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production and, periodically, interest expense. The Dodd-Frank Act, which was passed by Congress and signed into law in July 2010, provides for statutory and regulatory requirements for certain derivative transactions, which are broadly referred to as “swaps” and which include oil and gas hedging transactions and interest rate swaps. Swaps designated by the Commodities Futures Trading Commission (CFTC) and swaps within certain classes of swaps designated by the CFTC will be required to be submitted for clearing on a derivative clearing organization and, if accepted for clearing, cleared on the derivative clearing organization. Transactions in swaps accepted for clearing must be executed on a board of trade designated as a contract market or a swap execution facility if such swaps are made available for trading on such a board of trade or swap execution facility. The Dodd-Frank Act provides an exception from application of the Act's clearing requirement that commercial end-users may elect for swaps they use to hedge or mitigate commercial risks. Although we believe we will be able to elect such exception with respect to most, if not all, of our swaps, if we cannot do so with respect to many of the swaps we enter into, our ability to execute our hedging program efficiently will be adversely affected. In addition, any of our existing swaps, as well as swaps that we enter before such swaps become subject to the clearing requirement, that fall within a class of swaps becoming subject to the clearing requirement will have to be submitted for clearing unless we meet certain reporting requirements.
We anticipate that, under regulations adopted under the Dodd-Frank Act and relevant derivative clearing organization and other rules, if we do not qualify as a commercial end-user we will be required to post cash collateral for those of our derivative transactions constituting swaps (including our interest rate swaps and commodities-related swaps) that we need to clear on a derivative clearing organization. Moreover, the CFTC and the federal regulators of banks and other financial institutions have proposed regulations imposing margin requirements for non-cleared swaps that, if adopted, could require us to post cash or other types of collateral for our non-cleared swaps, if any, from time to time in certain circumstances. Posting cash collateral or margin with respect to our swaps could cause liquidity issues for us by reducing our ability to use our cash for capital expenditures or other partnership purposes. A requirement to post cash collateral or margin could therefore reduce our ability to execute strategic hedges to reduce commodity price uncertainty and, thus, to protect cash flows. In addition, even if we are not required to post cash collateral or margin for our swaps, the banks and other derivatives dealers who are the contractual counterparties to our swaps will be required to comply with the Dodd-Frank Act’s requirements, and the costs of their compliance will likely be passed on to customers, including us, thus increasing our costs of engaging in hedging transactions, decreasing the benefits of those transactions to us and reducing our cash flows. If we reduce our use of derivatives as a result of the new legislation 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. Increased volatility may make us less attractive to certain types of investors. 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. If the legislation and regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.
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If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.
Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results could be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet certain reporting obligations.
We will rely on technology to conduct our business and our technology could become ineffective or obsolete.
We rely on technology, including geographic and seismic analysis techniques and economic models, to develop our reserve estimates and to guide our exploration, development and production activities. We will be required to continually enhance and update our technology to maintain our efficacy and to avoid obsolescence. The costs of doing so may be substantial, and may be higher than the costs that we anticipated for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Leasehold Properties
As of December 31, 2012, we controlled approximately 200,000 net acres in the following five primary prospect areas:
| · | 46,000 net acres (approximately 51,000 net acres pro forma for acquisitions closed and pending in 2013) in the Williston Basin targeting the Bakken and Three Forks shale oil formations in North Dakota and Montana; |
| · | 45,000 net acres in the Sand Wash Basin targeting the Niobrara shale oil formations in northwest Colorado (prior to the pending sale of 31,000 net acres in southwest Wyoming, which is expected to close in the first quarter of 2013); |
| · | 33,500 net acres in a joint venture targeting the Heath shale oil formation in Musselshell, Petroleum, Garfield and Fergus Counties of Montana; |
| · | 1,700 net acres in the Denver-Julesburg Basin targeting the Niobrara shale oil formation in Colorado and Wyoming; and |
| · | 72,800 net acres in a joint venture in and around the Tiger Ridge natural gas field in Blaine, Hill and Chouteau Counties of Montana. |
Williston Basin — Bakken and Three Forks
The Williston Basin is one of the largest oil resource plays in North America and has been the focus of extensive industry activity over the last several years. As of December 31, 2012 there were approximately 200 rigs drilling in the Williston Basin in North Dakota and Montana. Since the application of modern horizontal drilling and completion techniques began in 2007, thousands of Bakken and Three Forks wells have been drilled throughout the basin. We believe that this industry activity, including drilling activity in close proximity to our leasehold, has substantially mitigated the geologic risks of our anticipated drilling locations. The Williston Basin is geologically and aerially well-defined, and almost all of our net acres are positioned within McKenzie, Dunn, Williams and Mountrail Counties, North Dakota, and Richland County, Montana, which are all generally recognized as being prospective for both the Bakken and Three Forks formations.
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On a pro forma basis for closed and pending acquisitions in 2013, our Williston Basin acreage position consists of approximately 19,500 net operated acres in McKenzie, Dunn, and Williams Counties, North Dakota and Richland County, Montana where we have either secured operatorship through approved drilling permits or we believe we have sufficient working interests to claim operatorship in individual drilling spacing units pending approval of drilling permit applications. Our remaining acreage position on a pro forma basis consists of approximately 31,500 net acres in Williams, McKenzie, Dunn and Mountrail Counties in North Dakota, and Richland County, Montana, where we hold relatively low working interests. We expect to continue to maintain our non-operated working interests in leaseholds that contain producing wells in which we are a participant. In non-operated leaseholds that are not yet producing, we intend to utilize such leasehold to consolidate our operated working interests in current or future selected core focus areas, sell our interests to help fund our operated program, or maintain our interests to participate in future well development.
We are currently in the process of optimizing our participation in our non-operated acreage. While we cannot control the timing of capital expenditures for our non-operated properties, we may choose to selectively participate in proposed wells, based on our internal capital return criteria and our internal geologic knowledge. We consider the experience gained from our non-operated interests to be valuable due to the high quality of the operators. These interests have allowed and we expect that they will continue to allow us to leverage valuable technical data across the basin in order to participate in what we believe to be the most economic wells. The amount of detailed, well-specific data we have acquired as a result of our participation in approximately 200 gross non-operated wells to date, together with publicly available information, has allowed us to compile a valuable database of well information that we use to select our operated development areas and formulate optimal well designs.
Using industry-accepted well down-spacing assumptions, we believe there could be approximately 279 net potential drilling locations on our acreage prospective for oil in the Bakken and Three Forks formations. Consistent with such assumptions, we believe that each 1,280-acre unit can support approximately four Bakken and three Three Forks well locations. We plan to embark on an aggressive drilling program to convert our substantial undeveloped operated leasehold position to production, cash flow and reserves. For the 12-month period ending December 31, 2013, we plan to spend approximately $86 million on well development in the Williston Basin. Specifically, we plan to spend approximately $78.5 million ($82.5 million less $4.0 million spent during the three months ended December 31, 2012) to drill 7.5 net operated wells at an average estimated cost of $11.0 million per well and approximately $7.4 million to participate in 0.8 net non-operated wells at an average estimated cost of $9.2 million per well. We expect to fund our current 2013 capital expenditure budget using cash-on-hand, cash flow from operations, proceeds from our preferred equity transaction, proceeds from assets sales, and borrowings under our revolving credit facility.
The following table presents summary data for our Williston Basin project area and capital expenditure budget for the year ending December 31, 2013:
| Planned Capital Expenditures | ||||||||||||||||
| Net Acres | Net Identified Drilling Locations | Net Wells | Drilling Capex (in millions) | |||||||||||||
| Operated | 19,500 | 107 | 7.5 | $ | 78.5 | |||||||||||
| Non-Operated | 31,500 | 172 | 0.8 | $ | 7.4 | |||||||||||
| Total Williston Basin | 51,000 | 279 | 8.3 | $ | 85.9 | |||||||||||
Sand Wash Basin – Niobrara
As of December 31, 2012, we owned an interest in approximately 45,000 net acres in the Sand Wash Basin prospective for oil in the Niobrara formation in northwestern Colorado and southern Wyoming, of which we are in the process of selling 31,000 net acres in the Sand Wash Basin in southwest Wyoming, which we expect to close in March 2013. Following the completion of the pending sale, we will hold approximately 14,000 net acres in the Focus Ranch Federal Unit. In addition to this acreage, we hold a 45% interest in the Slater Dome Gas Gathering pipeline, which extends 18.5 miles from the edge of the Focus Ranch Federal Unit to a gas sales point in Baggs, Wyoming. We intend to focus our appraisal activities in 2013 on the Focus Ranch Federal Unit area, which has historically demonstrated significant oil and natural gas flows from well tests and commercial oil production.
Big Snowy Joint Venture — Heath Shale Oil
As of December 31, 2012, we owned an interest in approximately 33,500 net acres located in central Montana as part of a joint venture targeting the Heath shale oil. During 2012, the number of drilling permits issued and amount of drilling in the area have increased compared with 2011. We believe the Heath shale has similar characteristics to the Bakken and Three Forks formations. Our five-year primary term leases have three-year extension options that will allow us to hold our leases with minimal incremental capital into 2017.
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DJ Basin — Niobrara
As of December 31, 2012, we owned an interest in approximately 1,700 net acres in Weld County, Colorado and Laramie County, Wyoming, prospective for the Niobrara formation with 1,400 net acres currently held by production as we continue to monitor the performance and characteristics of the producing wells. We currently have no plans for drilling any additional development wells in the DJ Basin.
Major Joint Venture — Tiger Ridge Natural Gas
As of December 31, 2012, we owned an interest in approximately 72,800 net acres in and around the Tiger Ridge natural gas field in Montana. We participated in drilling two wells with Devon Energy Corporation, both of which were shut-in in 2010. We conducted a 3-D seismic program during 2010 and drilled and completed six exploratory wells in the fourth quarter of 2011 with our joint venture partners, Hancock Enterprises and MCR, LLC, as operators. We have an average working interest of 70% in these initial wells. We and our joint venture partners are assessing whether further development is economic at current natural gas prices.
Developed and Undeveloped Acreage
As of December 31, 2012, our principal assets included approximately 200,000 net acres located in the northern Rocky Mountain region of the United States. Net acreage represents our percentage ownership of gross acreage. The following table summarizes our estimated gross and net developed and undeveloped acreage by resource play at December 31, 2012.
| Developed Acreage | Undeveloped Acreage | Total Acreage | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| Bakken and Three Forks (1) | 53,227 | 11,208 | 125,512 | 34,486 | 178,739 | 45,694 | ||||||||||||||||||
| Red River | — | — | 800 | 800 | 800 | 800 | ||||||||||||||||||
| Heath JV | — | — | 85,811 | 33,562 | 85,811 | 33,562 | ||||||||||||||||||
| Tiger Ridge JV | — | — | 90,295 | 72,798 | 90,295 | 72,798 | ||||||||||||||||||
| Sand Wash Basin (2) | — | — | 88,398 | 45,545 | 88,398 | 45,545 | ||||||||||||||||||
| DJ Niobrara | 2,240 | 1,120 | 2,638 | 574 | 4,878 | 1,694 | ||||||||||||||||||
| Total: | 55,467 | 12,328 | 393,454 | 187,765 | 448,921 | 200,093 | ||||||||||||||||||
| (1) | The table includes approximately 5,840 gross (1,935 net) undeveloped acres in North Dakota and Montana targeting the Bakken and Three Forks formations currently in the process of being drilled or and completed as of December 31, 2012. |
| (2) | The table includes approximately 69,000 gross (31,000 net) acres in the Sand Wash Basin in southwest Wyoming and northern Colorado that we expect to sell in March 2013. The remaining acreage consists of approximately 37,000 gross (14,000 net) total undeveloped acres located in the Focus Ranch Federal Unit. |
The following table summarizes our estimated gross and net developed and undeveloped acreage by state at December 31, 2012.
| Developed Acreage | Undeveloped Acreage | Total Acreage | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| North Dakota(1) | 46,967 | 8,468 | 71,785 | 19,729 | 118,752 | 28,197 | ||||||||||||||||||
| Montana(2) | 6,260 | 2,740 | 230,633 | 121,917 | 236,893 | 124,657 | ||||||||||||||||||
| Colorado (3) | 2,240 | 1,120 | 44,006 | 18,090 | 46,246 | 19,210 | ||||||||||||||||||
| Wyoming(3) | — | — | 47,030 | 28,029 | 47,030 | 28,029 | ||||||||||||||||||
| Total: | 55,467 | 12,328 | 393,454 | 187,765 | 448,921 | 200,093 | ||||||||||||||||||
| (1) | Includes approximately 5,100 gross (1,815 net) undeveloped acres targeting the Bakken and Three Forks formations that are currently in the process of being drilled or and completed as of December 31, 2012. |
| (2) | Includes approximately 740 gross (120 net) undeveloped acres targeting the Bakken and Three Forks formations that are currently in the process of being drilled or and completed as of December 31, 2012. |
| (3) | The table includes approximately 69,000 gross (31,000 net) acres in the Sand Wash Basin in southwest Wyoming and northern Colorado that we expect to sell in March 2013. The remaining acreage consists of approximately 37,000 gross (14,000 net) total undeveloped acres located in the Focus Ranch Federal Unit. |
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The following table summarizes our estimated gross and net developed and undeveloped acreage by county across the Bakken and Three Forks prospect at December 31, 2012.
| Developed Acreage | Undeveloped Acreage | Total Acreage | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| Burke County, ND | 400 | 185 | 600 | 21 | 1,000 | 206 | ||||||||||||||||||
| Divide County, ND | 1,200 | 330 | — | — | 1,200 | 330 | ||||||||||||||||||
| Dunn County, ND (1) | 2,175 | 293 | 16,543 | 7,520 | 18,718 | 7,813 | ||||||||||||||||||
| McKenzie County, ND (2) | 12,606 | 2,321 | 30,567 | 7,271 | 43,173 | 9,592 | ||||||||||||||||||
| McLean County, ND | 840 | 140 | 24 | 24 | 864 | 164 | ||||||||||||||||||
| Mountrail County, ND | 6,137 | 739 | 4,668 | 427 | 10,805 | 1,166 | ||||||||||||||||||
| Stark County, ND | 960 | 135 | — | — | 960 | 135 | ||||||||||||||||||
| Williams County, ND | 22,650 | 4,325 | 19,380 | 4,466 | 42,030 | 8,791 | ||||||||||||||||||
| Richland County, MT | 4,483 | 1,896 | 52,730 | 14,032 | 57,213 | 15,928 | ||||||||||||||||||
| Roosevelt County, MT | 1,480 | 548 | 640 | 365 | 2,120 | 913 | ||||||||||||||||||
| Sheridan County, MT | 296 | 296 | 360 | 360 | 656 | 656 | ||||||||||||||||||
| Total: | 53,227 | 11,208 | 125,512 | 34,486 | 178,739 | 45,694 | ||||||||||||||||||
| (1) | During 2012, leases expired in Dunn County, North Dakota covering approximately 12,817 gross (3,150 net) acres. The cost associated with the abandoned acreage totaling approximately $3.5 million is included in the full cost pool and subject to the depletion base. |
| (2) | During 2012, leases expired in McKenzie County, North Dakota covering approximately 75 net acres. The cost associated with the abandoned acreage totaling $52,927 is included in the full cost pool and subject to the depletion base. |
| (3) | The table includes approximately 5,840 gross (1,935 net)undeveloped acres in North Dakota and Montana targeting the Bakken and Three Forks formations currently in the process of being drilled or and completed as of December 31, 2012. |
Undeveloped Acreage
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2012 that will expire over the next three years and thereafter by project area unless production is established within the spacing units covering the acreage prior to the expiration dates:
| Expiring 2013 | Expiring 2014 | Expiring 2015 | Expiring 2016 and thereafter | |||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||
| North Dakota Bakken and Three Forks (1) | 22,416 | 5,736 | 30,781 | 10,875 | 4,256 | 1,752 | 4,689 | 1,366 | ||||||||||||||||||||||||
| Montana Bakken and Three Forks (1) | 17,600 | 2,677 | 36,580 | 8,131 | 5,507 | 2,974 | 3,684 | 975 | ||||||||||||||||||||||||
| Montana Red River | — | — | 640 | 640 | 160 | 160 | — | — | ||||||||||||||||||||||||
| Montana Heath JV (2) | 34,260 | 17,203 | 51,551 | 16,359 | — | — | — | — | ||||||||||||||||||||||||
| Montana Tiger Ridge JV (3) | 11,653 | 4,741 | 37,345 | 28,165 | 15,000 | 13,864 | 26,296 | 26,028 | ||||||||||||||||||||||||
| DJ - Niobrara | 876 | 263 | 1,602 | 288 | 160 | 23 | — | — | ||||||||||||||||||||||||
| Sand Wash Basin | 9,912 | 5,107 | 5,291 | 2,726 | 7,740 | 3,988 | 65,455 | 33,724 | ||||||||||||||||||||||||
| Total | 96,717 | 35,727 | 163,790 | 67,184 | 32,823 | 22,761 | 100,124 | 62,093 | ||||||||||||||||||||||||
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| (1) | The table includes approximately 5,840 gross (1,935 net) acres in North Dakota and Montana targeting the Bakken and Three Forks formations that are currently in the process of being drilled or and completed as of December 31, 2012. We anticipate these wells will be sufficiently productive to allow us to hold such acres by production. Additionally, many of our leases include options to extend the lease from one to five additional years beyond the initial lease term. Of the 125,512 gross (34,486 net) undeveloped acres in North Dakota and Montana targeting the Bakken and Three Forks formations, approximately 18,435 gross (4,396 net) acres carry an option to extend the lease. |
| (2) | The expiration table does not reflect the three-year optional extensions included on all of our acreage in the Montana Heath Joint Venture. |
| (3) | During 2012, leases expired in Fergus and Choteau Counties, Montana, covering approximately 4,325 gross (1,908 net) acres. The $52,699 cost associated with the abandoned acreage is included in the full cost pool and subject to the depletion base. |
| (4) | The table includes approximately 69,000 gross (31,000 net) acres in the Sand Wash Basin in southwest Wyoming that we expect to sell in March 2013. The remaining acreage consists of approximately 37,000 gross (14,000 net) total undeveloped acres located in the Focus Ranch Federal Unit. |
Unproved Properties
We historically have acquired our properties by purchasing individual or small groups of leases directly from mineral owners or from landmen or lease brokers, which leases historically have not been subject to specified drilling projects, and by purchasing lease packages in identified project areas controlled by specific operators. We generally participate in drilling activities on a heads-up, or pro rata, basis based on our ownership percentage by electing whether to participate in each well on a well-by-well basis at the time wells are proposed for drilling.
We believe that the majority of our unproved properties will become subject to depletion within the next five years by proving up reserves relating to its acreage through exploration and development activities, by impairing the acreage that will expire before we can explore or develop it further, or by determining that further exploration and development activity will not occur. The timing by which all other properties will become subject to depletion will depend upon the timing of future drilling activities and delineation of our reserves.
Production History
The following table presents information about our produced oil and natural gas volumes for the years ended December 31, 2012, 2011 and 2010. As of December 31, 2012, we sold oil and natural gas from a total of 209 gross wells, 205 of which are located within the Williston Basin and four are located with the DJ Basin. Approximately 99%, 94% and 88% of net production volumes of Boe were produced from properties located in the Williston Basin (North Dakota and Montana) for the years ended December 31, 2012, 2011 and 2010, respectively. All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Net Production: | ||||||||||||
| Oil (Bbl) | 320,147 | 95,517 | 13,198 | |||||||||
| Natural Gas (Mcf) | 129,648 | 14,962 | 3,489 | |||||||||
| Barrel of Oil Equivalent (Boe) | 341,755 | 98,011 | 13,780 | |||||||||
| Average Sales Prices: | ||||||||||||
| Oil (per Bbl) | $ | 85.16 | $ | 86.86 | $ | 70.26 | ||||||
| Natural Gas (per Mcf) | $ | 6.68 | $ | 8.66 | $ | 4.44 | ||||||
| Average Production Costs: | ||||||||||||
| Oil (per Bbl) | $ | 8.26 | $ | 7.51 | $ | 2.05 | ||||||
| Natural Gas (per Mcf) | $ | 0.65 | $ | 0.65 | $ | 0.04 | ||||||
| Barrel of Oil Equivalent (Boe) | $ | 7.98 | $ | 7.42 | $ | 1.94 | ||||||
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Productive Wells
The following table summarizes gross and net productive oil wells by state at December 31, 2012, 2011 and 2010. A net well represents our fractional working ownership interest of a gross well. The following table does not include wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation.
| December 31, | ||||||||||||||||||||||||
| 2012 | 2011 | 2010 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| North Dakota Bakken and Three Forks – non-operated | 178 | 7.12 | 75 | 2.32 | 6 | 0.24 | ||||||||||||||||||
| Montana Bakken and Three Forks – non-operated | 27 | 2.55 | 7 | 0.67 | — | — | ||||||||||||||||||
| Colorado Niobrara – non-operated | 4 | 2.0 | 5 | 2.50 | 1 | 0.50 | ||||||||||||||||||
| Total: | 209 | 11.67 | 87 | 5.49 | 7 | 0.74 | ||||||||||||||||||
Wells Being Drilled or Awaiting Completion
The following table summarizes wells that were in the process of being drilled, awaiting completion, in the process of completion or awaiting flow back subsequent to fracture stimulation by state at December 31, 2012, 2011 and 2010. A net well represents our fractional working ownership interest of a gross well.
| December 31, | ||||||||||||||||||||||||
| 2012 | 2011 | 2010 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| North Dakota Bakken and Three Forks - operated | 2 | 1.02 | — | — | — | — | ||||||||||||||||||
| North Dakota Bakken and Three Forks – non-operated | 25 | 0.86 | 58 | 2.77 | 12 | 0.70 | ||||||||||||||||||
| Montana Bakken and Three Forks – non-operated | 1 | 0.09 | 5 | 0.19 | 3 | 0.09 | ||||||||||||||||||
| Montana Tiger Ridge Gas – non-operated | 4 | 2.80 | 6 | 4.20 | — | — | ||||||||||||||||||
| Colorado Niobrara – non-operated | — | — | — | — | 2 | 1.00 | ||||||||||||||||||
| Total: | 32 | 4.77 | 69 | 7.16 | 17 | 1.79 | ||||||||||||||||||
Operated Wells
We began our operated drilling program in McKenzie County, North Dakota in November 2012. We have successfully drilled three operated wells and are in the process of drilling our fourth operated well with our continuous one-rig drilling program. The first three operated wells are scheduled to begin fracture stimulation by the end of first quarter of 2013.
Exploratory Wells
As of December 31, 2012, we were participating in 32 gross (4.77 net) wells in the process of being drilled or completed. Of these wells, seven gross (0.19 net) wells are classified as PDNP properties. The wells in process that are not classified as PDNP properties are deemed exploratory wells and included in the table below.
| December 31, | ||||||||||||||||||||||||
| 2012 | 2011 | 2010 | ||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
| North Dakota Bakken and Three Forks - operated | 2 | 1.02 | — | — | — | — | ||||||||||||||||||
| North Dakota Bakken and Three Forks – non-operated | 19 | 0.76 | 30 | 1.78 | — | — | ||||||||||||||||||
| Montana Tiger Ridge – natural gas – non-operated | 4 | 2.80 | 6 | 4.20 | — | — | ||||||||||||||||||
| Colorado Niobrara – non-operated | — | — | — | — | 2 | 1.00 | ||||||||||||||||||
| Total: | 25 | 4.58 | 36 | 5.98 | 2 | 1.00 | ||||||||||||||||||
Of the 209 gross (11.67 net) productive wells that we have participated in as a non-operator, we have only participated in 2 gross (0.53 net) dry holes, which were located in Weld County, Colorado and Mountrail County, North Dakota.
Research and Development
We do not anticipate performing any significant product research and development under our current plan of operations.
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Reserves
We recently completed our most current reservoir engineering calculations as of December 31, 2012. As of December 31, 2012, we had total proved reserves of approximately 5.35 million Boe, all of which were located in the Williston Basin. Based on the results of our December 31, 2012 reserve analysis, our proved reserves increased approximately 52% during 2012 primarily as a result of increased drilling activity involving our acreage and our acquisition of acreage subject to specific drilling projects or included in permitted or drilling spacing units. We incurred approximately $73 million of capital expenditures for drilling activities and $17 million for acreage acquisitions during the year ended December 31, 2012, which directly contributed to the increase in our proved developed reserves. No other expenditures materially contributed to the development of proved developed reserves in 2012. Our proved undeveloped reserves increased by approximately 43% during 2012 primarily as a result of drilling activity and our acquisitions of acreage. Based on our independent reservoir engineering firm’s calculations of proved undeveloped reserves as of December 31, 2011, approximately 345,000 Boe, or 14.5%, of proved undeveloped reserves were converted to proved developed reserves during 2012. The capital costs to develop these reserves were approximately $6.9 million. Also during 2012, we drilled wells at 86 locations that did not include proved reserves as of December 31, 2011. During 2012, we added 65 new proved undeveloped locations, which resulted in the addition of approximately 1.0 million Boe of proved undeveloped reserves. We expect that our proved undeveloped reserves will continue to be converted to proved developed producing reserves as additional wells are drilled. At December 31, 2012, our projected costs to develop our remaining proved undeveloped reserves were $49.1 million in 2013 and $44.19 million in 2014. We do not have any material amounts of proved undeveloped reserves that have remained undeveloped for five years or more from the time such reserves were initially categorized as proved undevloped. All locations comprising our remaining proved undeveloped reserves are forecast to be drilled within five years from initially being recorded in accordance with our adopted development plan.
SEC Pricing Proved Reserves (1)
| Gross Wells | Net Wells | Oil (Bbl) | Natural Gas (cubic feet) | Total (Boe) (2) | Pretax PV10% | |||||||||||||||||||
| PDP Properties | 202 | 9.84 | 1,755,358 | 1,007,264 | 1,923,236 | $ | 62,549,717 | |||||||||||||||||
| PDNP Properties | 6 | 0.10 | 32,872 | 6,894 | 34,021 | 650,003 | ||||||||||||||||||
| Total Proved Developed Properties | 208 | 9.94 | 1,788,230 | 1,014,158 | 1,957,257 | 63,199,720 | ||||||||||||||||||
| PUD Properties | 139 | 9.52 | 3,081,116 | 1,894,335 | 3,396,838 | 24,619,642 | ||||||||||||||||||
| Total Proved Properties: | 347 | 19.46 | 4,869,346 | 2,908,493 | 5,354,095 | $ | 87,819,362 | |||||||||||||||||
| (1) | The SEC Pricing Proved Reserves table above values oil and natural gas reserve quantities and related discounted future net cash flows as of December 31, 2012 assuming average constant realized prices of $85.75 per Bbl of oil and $5.13 per Mcf of natural gas. The average natural gas price reflects the value of processed natural gas sales and natural gas liquids. Under SEC guidelines, these prices represent the average prices per Bbl of oil and per Mcf of natural gas at the beginning of each month in the 12-month period prior to the end of the reporting period, which averages are then adjusted to reflect applicable transportation and quality differentials. The values presented in the table above were calculated by Pressler Petroleum Consultants, Inc. and audited by Netherland, Sewell & Associates, Inc. |
| (2) | Barrels of oil equivalent (Boe) are computed based on a conversion ratio of one Boe for each barrel of oil and one Boe for every 6,000 cubic feet (i.e., 6 Mcf) of natural gas. |
| (3) | Pre-tax PV10% may be considered a non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP measure. Pre-tax PV10% is computed on the same basis as the standardized measure of discounted future net cash flows but without deducting future income taxes. We believe Pre-tax PV10% is a useful measure for investors for evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our Pre-tax PV10% as a basis for comparison of the relative size and value of our reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and natural gas properties and acquisitions. However, Pre-tax PV10% is not a substitute for the standardized measure of discounted future net cash flows. Our Pre-tax PV10% and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves. |
The table above assumes prices and costs discounted using an annual discount rate of 10% without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, or federal income taxes.
The “Pre-tax PV10%” values of our proved reserves presented in the foregoing table may be considered a non-GAAP financial measure as defined by the SEC. The following table reconciles the pre-tax PV10% value of our SEC Pricing Proved Reserves to the standardized measure of discounted future net cash flows.
SEC Pricing Proved Reserves
| Standardized Measure Reconciliation | ||||
| Pre-tax Present Value of estimated future net revenues (Pre-tax PV10%) | $ | 87,819,362 | ||
| Future income taxes, discounted at 10% | 2,534,578 | |||
| Standardized measure of discounted future net cash flows | $ | 85,284,784 |
Uncertainties are inherent in estimating quantities of proved reserves, including many risk factors beyond our control. Reserve engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner. As a result, estimates of proved reserves may vary depending upon the engineer valuing the reserves. Further, our actual realized price for our oil and natural gas is not likely to average the pricing parameters used to calculate our proved reserves. As such, the oil and natural gas quantities and the value of those commodities ultimately recovered from our properties will vary from reserve estimates.
Controls Over Reserve Report Preparation, Technical Qualifications and Technologies Used
Preparation of our reserve report is outlined in our Sarbanes-Oxley Act Section 404 internal control procedures. Our procedures require that our reserve report be prepared by an independent reservoir engineering firm and then audited by a third-party registered independent engineering firm at the end of every year. The preparation and audit of our reservoir engineering report is based on information we provide to such engineer. We accumulate historical production data for our wells, calculate historical lease operating expenses and differentials, update working interests and net revenue interests, obtain updated authorizations for expenditure (“AFEs”) from our operations department and obtain geological and geophysical information from operators. This data is forwarded to our third-party engineering firm for review and calculation. Our Chief Executive Officer and Vice President of Exploration and Business Development provide a final review of our reserve report and the assumptions relied upon in such report. Our Chief Executive Officer has over 30 years experience managing technical and business areas in upstream oil and natural gas, liquefied natural gas and geothermal. He is a member of the Society of Petroleum Engineers (SPE) and holds a degree in Oil and Gas Technology from the British Columbia Institute of Technology and a BSc in Petroleum Engineering from Tulsa University.
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We have utilized Pressler Petroleum Consultants, Inc. (“Pressler”), an independent reservoir engineering firm, for the preparation of our December 31, 2012 reserve report. Pressler is a professional reservoir-evaluation consulting firm and has substantial experience calculating the reserves of various other companies with operations targeting the Bakken and Three Forks formations and several other resource plays of the Northern Rockies. As such, we believe Pressler has sufficient experience to appropriately determine our reserves. Pressler utilizes proprietary technology, systems and data to calculate our reserves commensurate with this experience.
The reserves estimates shown herein have been independently audited by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. The lead technical person at NSAI primarily responsible for overseeing the audit of our reserves has 32 years of industry experience, and has been practicing consulting petroleum engineering at NSAI since 1989. He is a Registered Professional Engineer in the State of Texas, and has in excess of 20 years of practical experience in petroleum engineering studies and evaluation of reserves. NSAI meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI is proficient in applying industry standard practices to engineering and geosciences evaluations as well as applying SEC and other industry reserves definitions and guidelines.
The proved reserves tables above summarize our estimated proved reserves as of December 31, 2012, based upon reports prepared by Pressler and audited by NSAI. Our audit procedures require NSAI to prepare their own estimates of proved reserves for fields comprising at least 80% of the aggregate net present value of our year-end proved reserves, discounted at 10% per annum.
In accordance with applicable requirements of the SEC, estimates of our net proved reserves and future net revenues are made using average prices at the beginning of each month in the 12-month period prior to the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation).
The reserves set forth in the NSAI audit letter for the properties are estimated by performance methods or analogy. In general, reserves attributable to producing wells and/or reservoirs are estimated by performance methods such as decline curve analysis which utilizes extrapolations of historical production data. Reserves attributable to non-producing and undeveloped reserves included in our report are estimated by analogy.
To estimate economically recoverable oil and natural gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future of production rates. Under Rules 210.4-10(a)(22)(v) and (26) of Regulation S-X, proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which those reserves can be economically produced from a reservoir, determined as of the effective date of the report. With respect to the property interests we own, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, production taxes, recompletion and development costs and product prices are based on the SEC regulations, geological maps, well logs, core analyses, and pressure measurements.
The reserve data set forth in the NSAI audit letter represent only estimates, and should not be construed as being exact quantities. The estimates of reserves may or may not be actually recovered, and if recovered, the actual revenues and costs could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their estimated values, including many factors beyond our control. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geologic interpretation and judgment. As a result, estimates of different engineers, including those used by us, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and natural gas prices, operating costs and other factors. The revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. Our estimated net proved reserves, included in our SEC filings, have not been filed with or included in reports to any other federal agency. See Item 1A. Risk Factors — Estimates of proved oil and natural gas reserves are uncertain and any material inaccuracies in these reserve estimates will materially affect the quantities and the value of our reserves.
Additional discussion of our proved reserves is set forth under the heading Supplemental Oil and Gas Reserve Information (Unaudited) following our audited financial statements for the years ended December 31, 2012, 2011 and 2010.
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Delivery Commitments
We currently have oil delivery agreements in place through April 2013 for delivery of all oil produced from our operated wells. We have an off-take agreement through January 2016 and monthly thereafter with ONEOK, Inc. for delivery of all of our operated natural gas produced in our area of operation in McKenzie County, North Dakota.
Item 3. Legal Proceedings
We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. We believe that all such litigation matters are not likely to have a material adverse effect on the Company’s financial position, cash flows or results of operations.
Item 4. Mine Safety Disclosures
Not applicable.
PART II
Item 5. Market For Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Market Information
Emerald’s common stock is currently listed for trading on the NYSE MKT under the symbol “EOX.” From March 2, 2011 until September 4, 2012, Emerald’s common stock was listed for trading on the NYSE MKT under the symbol “VOG.” From December 29, 2009 until March 1, 2011, Voyager’s common stock was listed for trading on the over-the-counter bulletin board under the symbol “VYOG.OB.”
The high and low sales prices per share of Emerald’s common stock for each quarterly period within the three most recent fiscal years are indicated below, as reported on the NYSE MKT and over-the-counter bulletin board, as appropriate, and have been adjusted to reflect our 1-for-7 reverse stock split effected on October 23, 2012:
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||
| Year Ended December 31, 2012 | ||||||||||||||||
| High | $ | 25.20 | $ | 18.34 | $ | 13.86 | $ | 5.95 | ||||||||
| Low | $ | 17.01 | $ | 11.20 | $ | 5.46 | $ | 3.90 | ||||||||
| Year Ended December 31, 2011 | ||||||||||||||||
| High | $ | 52.78 | $ | 32.55 | $ | 27.65 | $ | 21.21 | ||||||||
| Low | $ | 27.23 | $ | 15.89 | $ | 14.14 | $ | 10.99 | ||||||||
| Year Ended December 31, 2010 | ||||||||||||||||
| High | $ | 8.54 | $ | 29.96 | $ | 30.80 | $ | 37.80 | ||||||||
| Low | $ | 6.30 | $ | 8.12 | $ | 23.45 | $ | 21.49 | ||||||||
Holders
As of March 18, 2013, we had 25,899,658 shares of our common stock outstanding, held by approximately 7,900 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.
Emerald Dividend Policy
We have never paid a cash dividend on our common stock, and the current policy of our board of directors is to retain any earnings to provide for our growth. The payment of cash dividends on our common stock in the future, if any, will be at the discretion of our board of directors and will depend on such factors as earnings levels, capital requirements, our overall financial condition and any other factors deemed relevant by our board of directors.
Equity Compensation Plan Information
The following table summarizes information regarding the number of shares of our common stock that are available for issuance under our existing equity compensation plan as of December 31, 2012.
| Plan Category | Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights | Weighted Average Exercise Price of Outstanding Options, Warrants and Rights | Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) | |||||||||
| (a) | (b) | (c) | ||||||||||
| Equity Compensation Plans Approved by Security Holders (1) | 735,705 | $ | 11.29 | 20,578 | ||||||||
| Equity Compensation Plans Not Approved by Security Holders (2) | 323,290 | $ | 9.22 | — | ||||||||
| Total | 1,058,995 | $ | 10.66 | 20,578 | ||||||||
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| (1) | Includes stock options to purchase 32,137 shares of common stock issued pursuant to equity plans of the pre-merger entity, ante4, Inc. prior to the merger date, April 16, 2010. |
| (2) | On December 1, 2009, we issued our Chief Accounting Officer warrants to purchase a total of 37,216 shares of common stock exercisable at $6.86 per share pursuant to the terms of his employment agreement. On December 31, 2009, we issued our Executive Chairman warrants to purchase a total of 186,077 shares of common stock exercisable at $6.86 per share pursuant to the terms of his employment agreement. On April 21, 2010, we granted our outside directors stock options to purchase a total of 100,000 shares of common stock exercisable at $19.32 per share for serving as outside directors, 42,857 of which have been forfeited or have expired. On November 12, 2010, we granted a newly appointed outside director stock options to purchase a total of 21,425 shares of common stock exercisable at $25.90 per share for serving as an outside director. In May 2011, we granted stock options to two employees to purchase a total of 14,286 and 7,143 shares of common stock exercisable at $21.14 and $24.85 per share, respectively, pursuant to the terms of their employment agreements. None of the officers, directors or employees had exercised any of the warrants or options as of December 31, 2012. |
Stock Performance Graph
This graph shows our cumulative total shareholder return over the period from April 16, 2010, the date of our merger with ante4, Inc., to December 31, 2012, relative to the cumulative total returns of the Amex Index and the Standard & Poor’s Composite 500 Index. The comparison assumes an investment of $100 (with reinvestment of all dividends) was made in our common stock on April 16, 2010, and in each of the indexes and its relative performance is tracked semi-annually through December 31, 2012.
Emerald Oil, Inc.
Total Return Performance
The following table sets forth the total returns utilized to generate the foregoing graph.
| 4/16/2010 | 6/30/2010 | 12/31/2010 | 6/30/2011 | 12/31/2011 | 6/30/2012 | 12/31/2012 | ||||||||||||||||||||||
| Emerald Oil, Inc. | $ | 100.00 | $ | 271.43 | $ | 385.71 | $ | 212.14 | $ | 183.57 | $ | 125.71 | $ | 53.47 | ||||||||||||||
| Standard & Poor’s Composite 500 Index | $ | 100.00 | $ | 86.46 | $ | 105.50 | $ | 110.78 | $ | 105.49 | $ | 114.26 | $ | 119.63 | ||||||||||||||
| Amex Oil Index | $ | 100.00 | $ | 79.48 | $ | 109.11 | $ | 117.31 | $ | 110.55 | $ | 104.83 | $ | 111.69 | ||||||||||||||
Recent Sales of Unregistered Securities
On February 19, 2013, we completed a private offering with affiliates of White Deer Energy, pursuant to which, in exchange for a cash investment of $50 million, we issued 500,000 shares of Series A Preferred Stock, 5,114,633 shares of Series B Preferred Stock and warrants to purchase an initial aggregate amount of 5,114,633 shares of our common stock.
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On February 4, 2013, we entered into a purchase and sale agreement with a third party pursuant to which we acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $1.9 million purchase price of the acquired leases, we issued 313,700 shares of our common stock at a per share value of $6.058 per share, based on the five-day trading volume-weighted average price of our common stock prior to closing.
On January 9, 2013, we entered into a purchase and sale agreement with a third party pursuant to which we acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $4.7 million purchase price of the acquired leases, we issued 851,315 shares of our common stock at a per share value of $5.50 per share, based on the five-day trading volume-weighted average price of our common stock prior to the closing of the acquisition.
On July 26, 2012, we completed the acquisition of Emerald Oil North America, Inc., formerly Emerald Oil, Inc., from Emerald Oil & Gas NL for approximately 1.66 million shares of our common stock.
On February 4, 2011, we sold 1.8 million units at a price of $28.00 per unit, with each unit consisting of one share of our common stock and one-half of a warrant to purchase one additional share of our common stock. Net proceeds to us from the sale of the units, after deducting selling commissions and offering expenses, were approximately $46.5 million. The warrants, which represent the right to acquire up to an aggregate of 0.9 million shares of our common stock, are exercisable within the five-year anniversary of the closing date of the offering at an exercise price of $49.70 per share.
On April 16, 2010, our predecessor company, ante4, Inc. acquired Plains Energy Investments, Inc., in exchange for approximately 3.2 million shares of our common stock and 669,879 warrants to purchase one share of our common stock.
On March 10, 2010, ante4, Inc. purchased leasehold interests from South Fork Exploration, LLC for $1.4 million and 0.3 million shares of restricted common stock with a fair value of approximately $2.4 million.
In January 2010, ante4, Inc. completed a private placement offering of 0.1 million shares of common stock to accredited investors at a subscription price of $7.42 per share for total gross proceeds of $0.8 million. As part of this private placement, we entered into an introduction letter agreement with Great North Capital Consultants, Inc. (“Great North”). As compensation for the work performed, Great North received 25,217 shares of restricted common stock and $67,760 in cash. The fair value of the restricted stock was $0.2 million or $7.42 per share, based upon the market value of one share of common stock on the date the transaction closed.
The foregoing securities were issued in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, provided by Section 4(2) thereof.
Item 6. Selected Financial Data
The financial statement information set forth below is derived from our balance sheets as of December 31, 2012, 2011 and 2010, and the related statements of operations, stockholders’ equity, and cash flows for the years ended December 31, 2012, 2011, and 2010 beginning on page F-1 of this report. See “Item 1 Business—Overview.” On April 16, 2010, our predecessor company, ante4, Inc. acquired Plains Energy Investments, Inc., at which time we began our present business operations.
| Year Ended December 31, | ||||||||||||
| 2012(1) | 2011 | 2010 (2) | ||||||||||
| Statements of Income Information: | ||||||||||||
| Revenues | ||||||||||||
| Oil and Natural Gas Sales | $ | 28,129,985 | $ | 8,426,129 | $ | 942,840 | ||||||
| Loss on Commodity Derivatives | (215,439 | ) | — | — | ||||||||
| Total Revenues | 27,914,546 | 8,426,129 | 942,840 | |||||||||
| Operating Expenses | ||||||||||||
| Production Expenses | 2,727,133 | 726,946 | 26,686 | |||||||||
| Production Taxes | 2,955,015 | 717,440 | 102,743 | |||||||||
| General and Administrative Expenses | 12,903,845 | 2,686,176 | 1,778,161 | |||||||||
| Depletion of Oil and Natural Gas Properties | 12,770,718 | 3,546,466 | 547,844 | |||||||||
| Impairment of Oil and Natural Gas Properties | 61,900,692 | — | 1,377,188 | |||||||||
| Depreciation and Amortization | 53,818 | 30,831 | 2,929 | |||||||||
| Accretion of Discount on Asset Retirement Obligations | 14,988 | 4,882 | 358 | |||||||||
| Gain on Acquisition of Business, Net | (5,758,048 | ) | — | — | ||||||||
| Total Expenses | 87,568,161 | 7,712,741 | 3,835,909 | |||||||||
| Income (Loss) from Operations | (59,653,615 | ) | 713,388 | (2,893,069 | ) | |||||||
| Other Income (Expense), Net | (2,642,484 | ) | (2,058,442 | ) | (1,310,260 | ) | ||||||
| Loss Before Income Taxes | (62,296,099 | ) | (1,345,054 | ) | (4,203,329 | ) | ||||||
| Income Tax Provision | — | — | 65,240 | |||||||||
| Net Loss | $ | (62,296,099 | ) | $ | (1,345,054 | ) | $ | (4,268,569 | ) | |||
| Net Loss Per Common Share – Basic and Diluted | $ | (4.91 | ) | $ | (0.17 | ) | $ | (0.79 | ) | |||
| Weighted Average Shares Outstanding – Basic and Diluted | 12,699,544 | 8,012,158 | 5,434,084 | |||||||||
| Balance Sheet Information: | ||||||||||||
| Total Assets | $ | 173,886,362 | $ | 104,839,421 | $ | 48,495,426 | ||||||
| Long-term Liabilities | $ | 23,796,074 | $ | 15,116,119 | $ | 10,522 | ||||||
| Total Liabilities | $ | 63,592,277 | $ | 25,697,480 | $ | 15,774,602 | ||||||
| Stockholders’ Equity | $ | 110,294,085 | $ | 79,141,941 | $ | 32,720,824 | ||||||
| Statement of Cash Flow Information: | ||||||||||||
| Net cash provided by (used for) operating activities | $ | 4,289,767 | $ | (153,156 | ) | $ | (1,165,634 | ) | ||||
| Net cash used for investing activities | $ | (66,452,633 | ) | $ | (43,508,278 | ) | $ | (3,745,202 | ) | |||
| Net cash provided by financing activities | $ | 58,427,978 | $ | 46,230,181 | $ | 15,578,094 | ||||||
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| (1) | We acquired Emerald Oil North America, Inc. from Emerald Oil & Gas NL on July 26, 2012. Our consolidated financial and operating results reflect the operations of the acquisition from the closing date (July 26, 2012) through December 31, 2012. See “Item 1 Business—Overview.” |
| (2) | We did not have oil and natural gas operations prior to April 16, 2010. |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This Item 7 contains “forward-looking” statements. See “Cautionary Statement Concerning Forward-Looking Statements” at the beginning of this report. The following discussion should be read in conjunction with Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data appearing elsewhere in this report. On July 26, 2012, we completed the acquisition of Emerald Oil North America, Inc., formerly Emerald Oil, Inc. (“Emerald Oil North America”), from Emerald Oil & Gas NL. Accordingly, this document includes Emerald Oil North America, its consolidated subsidiaries and the operations of the combined businesses from the closing date (July 26, 2012) through December 31, 2012. On April 16, 2010, our predecessor company, ante4, Inc. acquired Plains Energy Investments, Inc., at which time we began our present business operations. A discussion of our financial results before April 16, 2010 is not pertinent to our business plan on a going forward basis, due to the change in our business which occurred upon consummation of the merger on April 16, 2010.
Overview and Outlook
We are an oil and natural gas exploration and production company. Our properties are located in North Dakota, Montana, Colorado and Wyoming. Our corporate strategy is to build shareholder value through the development and acquisition of oil and natural gas assets that exhibit economically producible hydrocarbons.
As of December 31, 2012, we controlled the rights to mineral leases covering approximately 200,000 net acres. Our business currently focuses on the development of our properties in North Dakota and Montana. Our goals are to continue to explore for and develop hydrocarbons within the mineral leases we control as well as continue to expand our acreage position should opportunities present themselves. In order to accomplish our objectives we will need to achieve the following:
| • | continue to develop our substantial inventory of high quality core Bakken and Three Forks acreage with results consistent with or superior to the results we have achieved to date; |
| • | retain and attract talented personnel; |
| • | continue to be a low-cost producer of hydrocarbons; and |
| • | continue to manage our financial obligations to access the appropriate capital needed to develop our position of primarily undrilled acreage. |
The following table sets forth selected operating data for the periods indicated. Production volumes and average sales prices are derived from accrued accounting data for the relevant period indicated.
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Results of Operations for the periods ended December 31, 2012, 2011 and 2010
Revenues
Revenues from sales of oil and natural gas were $28.1 million in 2012 compared to $8.4 million and $0.9 million in 2011 and 2010, respectively. For 2012, our total production volumes on a Boe basis increased 249% as compared to 2011. For 2011, our total production volumes on a Boe basis increased 611% as compared to 2010. Production primarily increased due to the addition of 6.68 and 2.75 net productive wells in the Williston Basin in 2012 and 2011, respectively. During 2012, we realized an $85.05 average price per barrel of oil (including realized derivatives) compared to an $86.86 and $70.26 average price per barrel of oil during 2011 and 2010, respectively.
All data presented below is derived from accrued revenue and production volumes for the relevant period indicated.
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Net Oil and Natural Gas Revenues: | ||||||||||||
| Oil | $ | 27,264,526 | $ | 8,296,607 | $ | 927,339 | ||||||
| Natural Gas and Other Liquids | 865,459 | 129,522 | 15,501 | |||||||||
| Total Oil and Natural Gas Sales Before Derivatives | 28,129,985 | 8,426,129 | 942,840 | |||||||||
| Realized Loss on Commodity Derivatives | (34,191 | ) | — | — | ||||||||
| Unrealized Loss on Commodity Derivatives | (181,248 | ) | — | — | ||||||||
| Total Oil and Natural Gas Sales Net of Derivatives | $ | 27,914,546 | $ | 8,426,129 | $ | 942,840 | ||||||
| Net Production: | ||||||||||||
| Oil (Bbl) | 320,147 | 95,517 | 13,198 | |||||||||
| Natural Gas and Other Liquids (Mcf) | 129,648 | 14,962 | 3,489 | |||||||||
| Barrel of Oil Equivalent (Boe) | 341,755 | 98,011 | 13,780 | |||||||||
| Average Sales Prices: | ||||||||||||
| Oil (per Bbl) | $ | 85.16 | $ | 86.86 | $ | 70.26 | ||||||
| Effect of Settled Oil Derivatives on Average Price (per Bbl) | (0.11 | ) | $ | — | — | |||||||
| Oil Net of Settled Derivatives (per Bbl) | $ | 85.05 | $ | 86.86 | $ | 70.26 | ||||||
| Natural Gas and Other Liquids (per Mcf) | $ | 6.68 | $ | 8.66 | $ | 4.44 | ||||||
| Barrel of Oil Equivalent with Realized Derivatives (per Boe) | $ | 82.21 | $ | 85.97 | $ | 68.42 | ||||||
Loss on Commodity Derivatives
Realized commodity derivative loss was $34,191 for the year ended December 31, 2012. Unrealized commodity derivative loss was $181,248 for the year ended December 31, 2012. We did not have any commodity derivative contracts prior to January 1, 2012. Our derivatives are not designated for hedge accounting and are accounted for using the mark-to-market accounting method whereby gains and losses from changes in the fair value of derivative instruments are recognized immediately into earnings. Mark-to-market accounting treatment creates volatility in our revenues as unrealized gains and losses from derivatives are included in total revenues and are not included in accumulated other comprehensive income in the accompanying balance sheets. As commodity prices increase or decrease, such changes will have an opposite effect on the mark-to-market value of our derivatives. Future derivatives gains will be offset by lower future wellhead revenues. Conversely, future derivatives losses will be offset by higher future wellhead revenues based on the value at the settlement date. At December 31, 2012, all of our derivative contracts are recorded at their fair value, which was a net liability of $181,248.
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Expenses
All data presented below is derived from costs and production volumes for the relevant period indicated.
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Costs and Expenses Per Boe of Production : | ||||||||||||
| Production Expenses | $ | 7.98 | $ | 7.42 | $ | 1.94 | ||||||
| Production Taxes | 8.65 | 7.32 | 7.46 | |||||||||
| G&A Expenses (Excluding Share-Based Compensation) | 16.34 | 19.97 | 64.98 | |||||||||
| Shared-Based Compensation | 21.42 | 7.43 | 64.06 | |||||||||
| Depletion of Oil and Natural Gas Properties | 37.37 | 36.18 | 39.76 | |||||||||
| Impairment of Oil and Natural Gas Properties | 181.13 | — | 99.94 | |||||||||
| Depreciation and Amortization | 0.16 | 0.31 | 0.21 | |||||||||
| Accretion of Discount on Asset Retirement Obligation | 0.04 | 0.05 | 0.03 | |||||||||
Production Expenses
Production expenses were $2,727,133 in 2012 compared to $726,946 in 2011 and $26,686 in 2010. We experience increases in operating expenses as we add new wells and maintain production from existing properties. On a per unit basis, production expenses per Boe increased from $1.94 per barrel sold in 2010 to $7.42 in 2011 and $7.98 in 2012. These increases are related to higher operating costs primarily in our Williston Basin wells. The largest cost driver in our Williston Basin wells is the disposal of water.
Production Taxes
Production taxes were $2,955,015 in 2012 compared to $717,440 in 2011 and $102,743 in 2010. We pay production taxes based on realized oil and natural gas sales. Our production taxes were 10.5% in 2012 compared to 8.5% in 2011 and 10.9% in 2010. Certain portions of our production occurs in North Dakota and Montana jurisdictions that have lower initial tax rates for an established period of time or until an established threshold of production is exceeded, after which the tax rates are increased to the standard tax rate of 11.5%. The 2012 average production tax rate was higher than 2011 due to expirations of production tax holidays during the year. The 2011 average production tax rate was lower than the 2010 average due to well additions that qualified for reduced rates/or tax exemptions during 2011.
General and Administrative Expense
General and administrative expenses were $12,903,845 in 2012 compared to $2,686,176 in 2011and $1,778,161 in 2010. The 2012 increase of $10,217,669 when compared to 2011 is due to our change in corporate strategy to add operating capabilities to develop its own operated wells in the Williston Basin. This strategic change allows us the opportunity to significantly grow production by using industry best practices and to control well design and capital expenditures to maximize our return on capital. Specifically, 2012 expense increased on a year-over-year basis compared to 2011 due to an increase of $8,812,951 related to increase in employee compensation and related expense and an increase of $993,925 related to professional and legal expense. Share-based compensation expenses are included in the employee compensation and related expenses, totaling $7,318,690 in 2012 compared to $728,546 in 2011 and $882,804 in 2010. All increases relate to our strategic change to add operating capabilities and increases in personnel and infrastructure.
General and administrative expenses during 2011 increased on a year-over-year basis compared to 2010 due to increased professional and legal expenses ($480,254), the addition of employees and related employment expenses ($225,890), as well as exchange listing expenses ($110,366). Increases in professional, legal, employment-related and exchange listing expenses in 2011 compared to 2010 were the result of growth in infrastructure.
Depletion Expense
Our depletion expense is driven by many factors, including certain exploration costs involved in the development of producing reserves, production levels and estimates of proved reserve quantities and future developmental costs. Depletion expense was $12,770,718 compared to $3,546,466 in 2011 and $547,844 in 2010. On a per-unit basis, depletion expense was $37.37 per Boe in 2012 compared to $36.18 per Boe in 2011 and $39.76 per Boe in 2010. Our depletion expense is based on the capitalized costs related to properties having proved reserves, plus the estimated future development costs and asset retirement costs which are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves determined by independent petroleum engineers. This increase in depletion expense in 2012 and 2011 was due primarily to the addition of 6.68 and 2.75 net productive wells in the Williston Basin in 2012 and 2011, respectively.
Impairment of Oil and Natural Gas Properties
We follow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Capitalized costs (net of related deferred income taxes) are limited to a ceiling based on the present value of future net revenues using the 12-month unweighted average of first-day-of-the-month price (the “12-month average price”), discounted at 10%, plus the lower of cost or fair market value of unproved properties. If the ceiling is not greater than or equal to the total capitalized costs, then we are required to write down capitalized costs to the ceiling. We perform this ceiling test calculation each quarter. Any required write downs are included in the consolidated statements of operations as an impairment charge.
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We recognized an impairment expense at June 30, 2012 of $10,191,234 and at December 31, 2012 of $51,709,458 for a year ended December 31, 2012 total of $61,900,692. Included in the full cost pool at December 31, 2012 are $23.8 million of costs related to our Niobrara development program in the DJ Basin of Colorado which we have deemed uneconomic, $11.5 million of costs associated with the write-down of the Sand Wash Basin to fair market value reflective of the pending sale (see Item 1. Business – Recent Events) and $3.6 million of expiring leases in North Dakota we have deemed uneconomic to pursue. Combined, these items have added $38.9 million of costs to the full cost pool without contributing reserves and discounted future net revenues to increase the ceiling. The remaining $23.0 million impairment charge is a result of reclassifying proven undeveloped reserves into probable reserves to better reflect our current development program. We have moved away from our previous business model that focused on participating in non-operated wells developed by others to our current operated program over which we have control of the timing of well development and design of our wells. Going forward, we plan to participate in significantly fewer non-operated wells and grow reserves through our operated well development program.
Gain on Acquisition of Business, net
The gain on the acquisition of business, net recognized during the year ended December 31, 2012 is a result of a $7,213,835 gain recognized, offset by $1,455,787 of acquisition costs incurred in the acquisition of Emerald Oil North America on July 26, 2012 in accordance with GAAP. The gain is a result of the decrease in share price between the announcement date and closing date of the acquisition. We did not acquire any business during the years ended December 31, 2011 and 2010.
Other Income (Expense), Net
Other income (expense), net was $(2,642,484) in 2012 compared to $(2,058,442) in 2011 and $(1,310,260) in 2010. Interest expense, the largest component of other income (expense) was $(2,614,240) in 2012 compared to $(2,036,032) in 2011 and $(629,026) in 2010. We capitalized $362,688 of interest costs during the year ended December 31, 2012. No interest was capitalized during the years ended December 31, 2011 and 2010. The increase in interest expense in 2011 compared to 2010 resulted from the outstanding senior secured notes incurring interest for the full year of 2011, while the notes were outstanding for four months of 2010.
Net Loss
We had net loss of $62,296,099 in 2012 compared to $1,345,054 in 2011 and $4,268,569 in 2010 (representing $4.91, $0.17 and $0.79 per share, respectively). The increase in net loss in our period-over-period results was driven by the $61,900,692 impairment of oil and natural gas properties in 2012 and increased expenses related to our strategic change and increase in infrastructure, offset by increased revenue and production from oil and natural gas properties.
Non-GAAP Financial Measures
Adjusted EBITDA
In addition to reporting net income (loss) as defined under GAAP, we also present net earnings before interest, income taxes, depletion, depreciation, and amortization, accretion of discount on asset retirement obligations, impairment of oil and natural gas properties, net gain on acquisition of business, unrealized gain (loss) from mark-to-market on commodity derivatives and non-cash expenses relating to share based payments recognized under ASC Topic 718 (“Adjusted EBITDA”), which is a non-GAAP performance measure. Adjusted EBITDA consists of net earnings after adjustment for those items described in the table below. Adjusted EBITDA does not represent, and should not be considered an alternative to GAAP measurements, such as net income (loss) (its most directly comparable GAAP measure), and our calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, we believe the measure is useful in evaluating its fundamental core operating performance. We also believe that Adjusted EBITDA is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. Our management uses Adjusted EBITDA to manage our business, including in preparing our annual operating budget and financial projections. Our management does not view Adjusted EBITDA in isolation and also uses other measurements, such as net income (loss) and revenues to measure operating performance. The following table provides a reconciliation of net loss to Adjusted EBITDA for the periods presented:
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Net loss | $ | (62,296,099 | ) | $ | (1,345,054 | ) | $ | (4,268,569 | ) | |||
| Add: Interest expense | 2,614,240 | 2,036,032 | 629,026 | |||||||||
| Accretion of asset retirement obligations | 14,988 | 4,882 | 358 | |||||||||
| Depletion, depreciation and amortization | 12,824,536 | 3,577,297 | 550,773 | |||||||||
| Impairment of oil and natural gas properties | 61,900,692 | — | 1,377,188 | |||||||||
| Share-based compensation | 7,318,690 | 728,546 | 882,804 | |||||||||
| Unrealized loss on commodity derivatives | 181,248 | — | — | |||||||||
| Less: Gain on acquisition of business, net | (5,758,048 | ) | ||||||||||
| Adjusted EBITDA | $ | 16,800,247 | $ | 5,001,703 | $ | (828,420 | ) | |||||
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Adjusted Income (Loss)
In addition to reporting net income (loss) as defined under GAAP, we also present net earnings before the impairment of oil and natural gas properties, net gain on acquisition of business, non-recurring portion of share based compensation and the effect of unrealized gain (loss) from mark-to-market on commodity derivatives (“adjusted income (loss)”), which is a non-GAAP performance measure. Adjusted income (loss) consists of net earnings after adjustment for those items described in the table below. Adjusted income (loss) does not represent, and should not be considered an alternative to GAAP measurements, such as net income (loss), and our calculations thereof may not be comparable to similarly titled measures reported by other companies. By eliminating the items described below, we believe the measure is useful in evaluating our fundamental core operating performance. We also believe that adjusted income (loss) is useful to investors because similar measures are frequently used by securities analysts, investors, and other interested parties in their evaluation of companies in similar industries. Our management uses adjusted income to manage our business, including in preparing our annual operating budget and financial projections. Our management does not view adjusted income (loss) in isolation and also uses other measurements, such as net income (loss) and revenues to measure operating performance. The following table provides a reconciliation of net income (loss), to adjusted income (loss) for the periods presented:
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Net loss | $ | (62,296,099 | ) | $ | (1,345,054 | ) | $ | (4,268,569 | ) | |||
| Add: Impairment of oil and natural gas properties | 61,900,692 | — | 1,377,188 | |||||||||
| Unrealized loss on commodity derivatives | 181,248 | — | — | |||||||||
| Non-recurring portion of share based compensation (1) | 3,504,125 | |||||||||||
| Less: Gain on acquisition of business, net | (5,758,048 | ) | — | — | ||||||||
| Adjusted loss | $ | (2,468,082 | ) | $ | (1,345,054 | ) | $ | (2,891,381 | ) | |||
| Adjusted loss per share – basic and diluted | $ | (0.19 | ) | $ | (0.17 | ) | $ | (0.53 | ) | |||
| Weighted average shares outstanding – basic and diluted | 12,699,544 | 8,012,158 | 5,434,084 | |||||||||
(1) Non-recurring portion of share based compensation relates to non-cash costs of share grants that immediately vested on the grant date. There are no further costs to amortize on these grants.
Operation Plan
On July 26, 2012, we acquired Emerald Oil North America, Inc. and made a strategic decision to add operating capabilities and focus on growing operating acreage in the Williston Basin. The operated drilling program creates higher rate of return opportunities to drill and produce our own wells. We expect to encounter situations in which we will exchange portions of our non-operated acreage for operated acreage and forgo the opportunity to participate in non-operated wells developed on the acreage. Additionally, we may decide to sell a portion of our interests in non-operated leaseholds to help fund our operating development program. As we evaluate the potential return on capital of wells developed by other operators, we may decide to not participate in the development of the first well developed on that particular non-operated acreage, and go non-consent, but will retain the opportunity to participate in future well development on future in-fill wells in the leased area that are held by production with an existing producing well. We believe adding operating capabilities will provide us more control over our capital budget and ultimately will result in a higher return on capital. We expect to fund our current 2013 capital expenditure budget using cash-on-hand, cash flow from operations, proceeds from our preferred equity transaction, proceeds from assets sales, and borrowings under our revolving credit facility. We may consider funding growth opportunities beyond our current 2013 capital expenditure budget with future equity if we believe it would be accretive to shareholders and/or debt financings.
Our future financial results will depend primarily on: (i) the ability to continue to source and evaluate potential projects; (ii) the ability to discover commercial quantities of oil and natural gas; (iii) the market price for oil and natural gas; and (iv) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources. There can be no assurance that we will be successful in any of these respects, that the prices of oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding, if necessary.
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Liquidity and Capital Resources
Liquidity is a measure of a company’s ability to meet potential cash requirements. We have historically met our capital requirements through cash on hand, cash from operations, proceeds from asset sales, the issuance of common stock and by long-term and short-term borrowings. We anticipate we will be able to provide the necessary liquidity for 2013 from the revenues generated from the sales of our oil and natural gas reserves in our existing properties, availability under our credit facility and the recently completed private offering with affiliates of White Deer Energy, pursuant to which we issued 500,000 shares of Series A Preferred Stock, 5,114,633 shares of Series B Preferred Stock and warrants to purchase an initial aggregate amount of 5,114,633 shares of our common stock in exchange for a cash investment of $50 million (see Item 1. Business - Recent Developments). We are in the process of selling certain assets that are outside of the Williston Basin. We plan to deploy proceeds from these assets sales into our operating program in the Williston Basin. We are also in the process of selling non-operated acreage that has authorization for expenditures (AFEs) attached that allow the leaseholds to participate as a non-operator in the well development and production from the wells. The proceeds received from the sale of the acreage and attached AFEs will be applied to our operating program in the Williston Basin and will reduce our payables for the cost to participate in the development of the related non-operated wells. If we do not generate sufficient cash flow from operations, proceeds from asset sales or do not have availability under our credit facility, we may attempt to continue to finance our operations through equity and/or debt financings.
Our primary use of capital has been for the acquisition, development and exploration of oil and natural gas properties. We continually monitor potential capital sources, including equity and debt financings, in order to meet our planned capital expenditures and liquidity requirements. Our future success in growing provide reserves and production will be highly dependent on our ability to access outside sources of capital.
The following table summarizes total current assets, total current liabilities and working capital at December 31, 2012.
| Current Assets | $ | 24,002,557 | ||
| Current Liabilities | 39,796,203 | |||
| Working Capital Shortfall | $ | (15,793,646 | ) |
Equity Offerings
On February 19, 2013, we completed a private offering with affiliates of White Deer Energy L.P. (“White Deer Energy”), pursuant to which, in exchange for a cash investment of $50 million, we issued the following to White Deer Energy:
| · | 500,000 shares of a new Series A Perpetual Preferred Stock, $0.001 par value per share (the “Series A Preferred Stock”); |
| · | 5,114,633 shares of a new Series B Voting Preferred Stock, $0.001 par value per share (the “Series B Preferred Stock”); and |
| · | warrants to purchase an initial aggregate amount of 5,114,633 shares of our common stock, $0.001 par value per share, at an initial exercise price of $5.77 per share. |
The Series A Preferred Stock has a cumulative dividend rate of 10% per annum, payable quarterly on each March 31, June 30, September 30 and December 31, commencing on March 31, 2013. If we voluntarily or involuntarily liquidate, dissolve or wind up our affairs, the Series A Preferred Stock will be entitled to receive out of our available assets, after satisfaction of liabilities to creditors, if any, and before any distribution of assets is made on our common stock or any other shares of our junior stock, a liquidating distribution in the amount, with respect to each share of Series A Preferred Stock, equal to the sum of (a)(1) on or prior February 19, 2015, $112.50, (2) from February 20, 2015 through February 19, 2016, $110.00, (3) from February 20, 2016 through February 19, 2017, $105.00 and (4) thereafter, $100.00 and (b) the accrued and unpaid dividends thereon (the “Liquidation Preference”). Prior to April 1, 2015, we may pay dividends on the Series A Preferred Stock either (x) in cash or (y) by issuance of (A) additional shares of Series A Preferred Stock valued at the same value as the initial per share purchase price of the Series A Preferred Stock and (B) an additional warrant to purchase shares of common stock; provided that such dividends must be paid in cash unless and until we obtain shareholder approval to authorize the issuance of any additional warrants and any shares of common stock issuable upon exercise of such additional warrants. We have the option to redeem shares of Series A Preferred Stock in whole or in part at any time at the aggregate Liquidation Preference, subject to a minimum redemption amount equal to the lesser of 50,000 shares or the number of shares then outstanding. Upon a change of control, the holders of the Series A Preferred Stock have the right to require us to purchase the Series A Preferred Stock at the Liquidation Preference. The Series A Preferred Stock does not vote generally with our common stock, but has specified approval rights with respect to, among other things, changes to our organizational documents that affect the Series A Preferred Stock, payment of dividends on our common stock or other junior stock, redemptions or repurchases of common stock or other capital stock and incurrence of certain indebtedness. Upon the occurrence of certain events of default under our credit facility with Wells Fargo Bank, N.A., the holders of the Series A Preferred Stock have additional specified approval rights with respect to, among other things, the incurrence or guarantee by us of any indebtedness, any change in compensation or benefits of or employment or severance agreements with our officers and any agreement or arrangement pursuant to which we or our subsidiaries would pay or incur liability in excess of $1,000,000 over the term of such agreement or arrangement.
The Series B Preferred Stock is entitled to vote, until January 1, 2020, in the election of directors and on all other matters submitted to a vote of the holders of common stock as a single class. Each share of Series B Preferred Stock has one vote. The Series B Preferred Stock has no dividend rights and a liquidation preference of $0.001 per share. On and from time to time after January 1, 2020 we may redeem, in whole or in part, the then-outstanding shares of Series B Preferred Stock, at a redemption price per share equal to $0.001.
The warrants entitle the holders thereof to acquire a number of shares of common stock equal to approximately 19.75% of our shares of common stock outstanding as of February 19, 2013, or approximately 16.49% of our outstanding Common Stock on a diluted basis taking into account the exercise of the warrants.
We intend to use the proceeds from this private offering to purchase additional working interests in operated drilling spacing units in McKenzie County, North Dakota and to increase our capital expenditure budget to drill additional operated wells in the Williston Basin.
On February 4, 2013, we entered into a purchase and sale agreement with a third party pursuant to which we acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $1.9 million purchase price of the acquired leases, we issued 313,700 shares of our common stock at a per share value of $6.058 per share, based on the five-day trading volume-weighted average price of our common stock prior to closing.
On January 9, 2013, we entered into a purchase and sale agreement with a third party pursuant to which we acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $4.7 million purchase price of the acquired leases, we issued 851,315 shares of our common stock at a per share value of $5.50 per share, based on the five-day trading volume-weighted average price of our common stock prior to the closing of the acquisition.
On September 28, 2012, we completed a public offering of 13,392,857 shares of common stock at $5.60 per share. The gross proceeds from the offering were $75 million, and the net proceeds were approximately $69.7 million, after deducting underwriting discounts and commissions and other offering expenses. The sale of the shares of common stock closed on September 25, 2012. The underwriters elected to exercise the over-allotment option to sell an additional 484,698 shares of common stock at $5.60 per share. The gross proceeds from the over-allotment exercise were $2.7 million, and the net proceeds are approximately $2.5 million after deducting underwriting discounts and commissions. The over-allotment exercise closed on October 26, 2012. We used a portion of the net proceeds from this offering, along with cash on hand, to repay a portion of outstanding indebtedness and for additional operable leasehold acquisitions. We intend to use the remaining proceeds to fund drilling and development expenditures in the Williston Basin and for general corporate purposes, including working capital.
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On July 26, 2012, we completed the acquisition of Emerald Oil North America, Inc., formerly Emerald Oil, Inc., from Emerald Oil & Gas NL for approximately 1.66 million shares of our common stock.
Credit Facility
On November 20, 2012, we entered into a credit facility with Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, and the lenders party thereto. Our credit facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million and an initial borrowing base of $27.5 million. We used the proceeds from our credit facility to repay our previous credit facility with Macquarie Bank Limited in full.
Amounts borrowed under our credit facility will mature on November 20, 2017, and upon such date, any amounts outstanding under our credit facility are due and payable. Redeterminations of the borrowing base will be on a semi-annual basis, with an option to elect an additional redetermination every six months between the semi-annual redeterminations.
The annual interest cost, which is dependent upon the percentage of the borrowing base utilized, is, at our option, based on either the Alternate Base Rate (as defined in our credit facility) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest exceed the maximum interest rate allowed by any current or future law. As of December 31, 2012, the annual interest rate on our credit facility was 2.81%, which is based on LIBOR plus 2.25%. Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at our option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. We will also pay a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized.
A portion of our credit facility not in excess of $5 million will be available for the issuance of letters of credit by Wells Fargo. We will pay a rate per annum ranging from 1.75% to 2.75% on the face amount of each letter of credit issued and will pay a fronting fee equal to the greater of $500 and 0.125% of the face amount of each letter of credit issued. We did not obtain any letters of credit under our credit facility in 2012.
Each of our subsidiaries is a guarantor under our credit facility. Our credit facility is secured by first priority, perfected liens and security interests on substantially all of our assets and of the guarantors, including a pledge of their ownership in their respective subsidiaries.
Our credit facility contains customary covenants that include among other things, limitations on our ability to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. Our credit facility also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of debt to EBITDA for the preceding four fiscal quarters of no more than 3.50 to 1.00, and (c) a fixed charge coverage ratio for any four fiscal quarters of at least 3.00 to 1.00. We were not in compliance with the current ratio covenant as of December 31, 2012, and a waiver was obtained from Wells Fargo.
On February 18, 2013, our credit facility was amended to allow us to issue shares of our preferred stock and warrants to White Deer Energy. The amendment allows for the payment of dividends on the preferred stock and incorporates similar language with respects to change of control provisions.
On November 20, 2012, we drew approximately $15.2 million on our credit facility to pay in full the approximate $15.0 million outstanding balance on the Macquarie Facility and fees and expenses associated with our credit facility. On December 26, 2012, approximately $8.3 million was drawn for working capital purposes. During 2013, we intend to utilize the remaining availability of approximate $4.0 million under our credit facility for our ongoing business operations, including the development and acquisition of properties and financing working capital requirements. As of December 31, 2012, the principal balance amount on our credit facility was $23.5 million.
We entered into the Macquarie Facility on February 10, 2012. The Macquarie Facility provided up to a maximum of $150 million in principal amount of borrowings to be used as working capital for exploration and production operations. Initially, $15 million of financing was available under the Macquarie Facility based on reserves (Tranche A), with an additional $50 million available under a development tranche (Tranche B). On July 26, 2012, we entered into an amended and restated credit agreement with Macquarie Bank Limited to expand the existing availability and outstanding balance under the Macquarie Bank Facility. We obtained additional availability from the Macquarie Facility and drew $15 million of additional debt on a new third tranche at an initial rate of 9% above LIBOR and had the potential to draw a maximum of $20 million. The $15 million drawn was used for existing development activities and was paid in full with proceeds from the equity offering completed on September 28, 2012. The Macquarie Facility was paid in full on November 20, 2012. The remaining unamortized debt issuance costs of $389,333 were written off to interest expense in the year ended December 31, 2012.
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Satisfaction of Our Cash Obligations for the Next Twelve Months
We project we will have sufficient capital to accomplish our development plan and forecasted general and administrative expenses for the next twelve months. Our projections are based on cash on hand, increasing cash flow from operations, proceeds from the recent issuance of preferred stock to White Deer Energy, and increased borrowing capacity based on reserve growth. However, we may scale back our development plan should our projections of cash flow and borrowing capacity fall short of expectations or commodity prices fall substantially. We may also choose to access the equity capital markets to fund acreage acquisitions and/or accelerated drilling at the discretion of management, depending on prevailing market conditions. We will evaluate any potential opportunities for acquisitions as they arise. Given our asset base and anticipated increasing cash flows, we believe we are in a position to take advantage of any appropriately priced acquisition opportunities that may arise. However, there can be no assurance that any additional capital will be available to us on favorable terms or at all.
Our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by companies in their early stage of operations, particularly companies in the oil and natural gas exploration industry. Such risks include, but are not limited to, an evolving and unpredictable business model and the management of growth. To address these risks we must, among other things, implement and successfully execute our business and marketing strategy, respond to competitive developments, and attract, retain and motivate qualified personnel. There can be no assurance that we will be successful in addressing such risks, and the failure to do so can have a material adverse effect on our business prospects, financial condition and results of operations.
Effects of Inflation and Pricing
The oil and natural gas industry is cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry put extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion. Material changes in prices also impact our current revenue stream, estimates of future reserves, borrowing base calculations of bank loans, impairment assessments of oil and natural gas properties, and values of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel. While we do not currently expect business costs to materially increase, higher prices for oil and natural gas could result in increases in the costs of materials, services and personnel.
Cash and Cash Equivalents
Our total cash resources as of December 31, 2012 were $10,192,379, compared to $13,927,267 as of December 31, 2011. The decrease in our cash balance was primarily attributable to the development of oil and natural gas properties and repayment of debt, offset by proceeds from the equity offering on September 28, 2012 and borrowings under our credit facility.
Net Cash Provided By (Used For) Operating Activities
Net cash provided by (used for) operating activities was $4,289,767 for the year ended December 31, 2012 compared to $(153,156) for the year ended December 31, 2011 and $(1,165,634) for the year ended December 31, 2010. The change in the net cash provided by operating activities is primarily attributable to higher production revenue in 2012 compared to 2011 and 2010, offset by a higher net loss.
Net Cash Used In Investment Activities
Net cash used in investment activities was $66,452,633 for the year ended December 31, 2012 compared to $43,508,278 for the year ended December 31, 2011 and $3,745,203 for the year ended December 31, 2010. The cash used in investment activities is primarily attributable to the purchase and development of oil and natural gas properties in the Williston Basin during these periods.
Net Cash Provided By Financing Activities
Net cash provided by financing activities was $58,427,978 for the year ended December 31, 2012 compared to $46,230,181 for the year ended December 31, 2011 and $15,578,094 for the year ended December 31, 2010. The net cash provided by financing activities for the year ended December 31, 2012 is primarily attributable to proceeds from the equity offering completed on September 28, 2012 and our credit facility amended in July 2012 and November 2012, offset by repayment of borrowings under the amended credit facility, the assumption of liabilities resulting from the acquisition of Emerald Oil North America, Inc., and the repayment of the senior secured promissory notes. The change in net cash provided by financing activities for the year ended December 31, 2011 compared to December 31, 2010 is primarily attributable to proceeds from a private placement of common stock and warrants in February 2011.
Contractual Obligations and Commitments
As of December 31, 2012, our $23.5 million credit facility was our only material debt obligation. See — Liquidity and Capital Resources — Credit Facility. We have no other material capital lease obligations, operating lease obligations or purchase obligations requiring future payments other than our Denver, Colorado and Billings, Montana office leases that expire on February 15, 2014 and April 1, 2014, respectively. The following table illustrates our contractual obligations as of December 31, 2012.
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| Payment due by period | ||||||||||||||||||||
| Contractual Obligations | Total | Less than 1 year | 2 – 3 years | 4 – 5 years | More than 5 years | |||||||||||||||
| Credit Facility (1) | $ | 23,500,000 | $ | — | $ | — | $ | 23,500,000 | $ | — | ||||||||||
| Interest on Credit Facility(2) | 3,227,575 | 660,350 | 1,320,700 | 1,246,525 | — | |||||||||||||||
| Office Leases (3) | 322,667 | 169,532 | 153,135 | — | — | |||||||||||||||
| Automobile Leases (4) | 16,728 | 16,728 | — | — | — | |||||||||||||||
| Office Equipment (5) | 34,380 | 8,496 | 16,992 | 8,892 | — | |||||||||||||||
| $ | 27,101,350 | $ | 855,106 | $ | 1,490,827 | $ | 24,755,417 | $ | — | |||||||||||
| (1) | On November 20, 2012, we entered into our credit facility with Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto. Our credit facility is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million and an initial borrowing base of $27.5 million. Amounts borrowed under our credit facility will mature on November 20, 2017, and upon such date, any amounts outstanding under our credit facility are due and payable. Redeterminations of the borrowing base will be made on a semi-annual basis, with an option to elect additional redeterminations every six months, which allows for redeterminations as frequent as every quarter. |
| (2) | Based upon our interest rate of 2.81% under our credit facility as of December 31, 2012. |
| (3) | Our Denver, Colorado office lease commenced on December 15, 2012 and has a term of 26 months. Our Billings, Montana office commenced on April 1, 2011 and has a term of 36 months. |
| (4) | In November 2010, we entered into automobile leases for vehicles utilized by two of our employees, which expire in November 2013. |
| (5) | In December 2012 and January 2013, we entered into various leases for office equipment utilized by the Denver, Colorado and Billings, Montana offices, which expire in December 2015 and January 2016, respectively. |
Off-Balance Sheet Arrangements
We currently do not have any off-balance sheet arrangements.
2013 Drilling Projects
For the 12-month period ending December 31, 2013, we plan to spend approximately $86 million on well development in the Williston Basin. Specifically, we plan to spend approximately $78.5 million ($82.5 million less $4.0 million spent during the three months ended December 31, 2012) to drill 7.5 net operated wells at an average estimated cost of $11.0 million per gross well and approximately $7.4 million to participate in 0.8 net non-operated wells at an average estimated cost of $9.2 million per well. We expect to fund our current 2013 capital expenditure budget using cash-on-hand, cash flow from operations, proceeds from issuance of preferred stock to White Deer Energy, proceeds from assets sales, and borrowings under our revolving credit facility.
Our future financial results will depend primarily on: (i) the ability to continue to source and evaluate potential projects; (ii) the ability to discover commercial quantities of oil and natural gas; (iii) the market price for oil and natural gas; and (iv) the ability to fully implement our exploration and development program, which is dependent on the availability of capital resources. There can be no assurance that we will be successful in any of these respects, that the prices of oil and natural gas prevailing at the time of production will be at a level allowing for profitable production, or that we will be able to obtain additional funding, if necessary.
Product Research and Development
We do not anticipate performing any significant product research and development given our current plan of operation.
Expected Purchase or Sale of Any Significant Equipment
We do not anticipate the purchase or sale of any plant or significant equipment as such items are not required by us at this time or anticipated to be needed in the next twelve months.
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Critical Accounting Policies
Revenue Recognition and Natural Gas Balancing
We recognize oil and natural gas revenues from our interests in producing wells when production is delivered and title has transferred to the purchaser, to the extent the selling price is reasonably determinable. We use the sales method of accounting for balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2012 and 2011, our natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which we have an interest equaled to our entitled interest in natural gas production from those wells.
Full Cost Method
We follow the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, a portion of employee salaries related to property development, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. For the years ended December 31, 2012, 2011 and 2010, we capitalized $842,418, $526,630 and $0, respectively, of internal salaries, which included $582,040, $418,414 and $0, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. We capitalized interest of $362,688 for the year ended December 31, 2012. We did not capitalize interest for the years ended December 31, 2011 and 2010.
Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. As of December 31, 2012, we have had no property sales since inception, but have a sale pending in the Sand Wash Basin (see Item 1. Business – Recent Developments) and engage in acreage trades in the Williston Basin.
We assess all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to amortization. For the years ended December 31, 2012 and 2011, we included $3,625,209 and $6,983,125, respectively, related to expiring leases within costs subject to the depletion calculation.
Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under ASC 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed, impaired, or abandoned.
Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion, net of deferred income taxes, may not exceed a ceiling amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, which is tested on a quarterly basis, an impairment is recognized. The present value of estimated future net revenues was computed by applying prices based on a 12-month arithmetic average of the oil and natural gas prices in effect on the first day of each month, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. Based on calculated reserves at December 31, 2012, 2011 and 2010, the unamortized costs of our oil and natural gas properties exceeded the ceiling test limit by $51,709,458, $0 and $1,377,188, respectively. The unamortized costs of our oil and natural gas properties exceeded the ceiling test limit as of June 30, 2012 by $10,191,234. As a result, we are required to record impairment of the net capitalized costs of our oil and natural gas properties in the amount of $61,900,692, $0 and $1,377,188, for the years ended December 31, 2012, 2011 and 2010 respectively.
Joint Ventures
The consolidated financial statements as of December 31, 2012, 2011 and 2010 include the accounts of our proportionate share of the assets, liabilities, and results of operations of the joint ventures we are involved in.
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Stock-Based Compensation
We have accounted for stock-based compensation under the provisions of ASC 718-10-55. We recognize stock-based compensation expense in the financial statements over the vesting period of equity-classified employee stock-based compensation awards based on the grant date fair value of the awards, net of estimated forfeitures. For options and warrants we use the Black-Scholes option valuation model to calculate the fair value of stock-based compensation awards at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. For the stock options and warrants granted we have used a variety of comparable and peer companies to determine the expected volatility input based on the expected term of the options. We believe the use of peer company data fairly represents the expected volatility we would experience if we were in the oil and natural gas industry over the expected term of the options. We used the simplified method to determine the expected term of the options due to the lack of historical data. Changes in these assumptions can materially affect the fair value estimate.
On May 27, 2011, our shareholders approved the 2011 Equity Incentive Plan (the “2011 Plan”), under which 714,286 shares of common stock were reserved. On October 22, 2012, our shareholders approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares. The purpose of the 2011 Plan is to promote our success and our affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees upon whose efforts our success will depend to a large degree. It is our intention to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of December 31, 2012, 735,705 stock options and 2,743,717 shares of common stock and restricted stock units had been issued to officers, directors and employees under the 2011 Plan, including 1,847,701 unvested restricted stock units. As of December 31, 2012, there were 20,578 shares available for issuance under the 2011 Plan.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile, and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous factors beyond our control. Our revenues during the years ended December 31, 2012, 2011 and 2010 generally have increased or decreased along with any increases or decreases in oil or natural gas prices, but the exact impact on our income is indeterminable given the variety of expenses associated with producing and selling oil and natural gas that also increase and decrease along with oil and natural gas prices. If oil prices decline by $1.00 per Bbl, then the standardized measure of our proved reserves as of December 31, 2012 would decline from $87.8 million to $85.7 million, or 2.4%. If natural gas prices decline by $0.10 per Mcf, then the standardized measure of our proved reserves as of December 31, 2012 would decline from $87.8 million to $87.6 million, or 0.2%. However, larger decreases in oil and natural gas prices may have a proportionately greater impact on our standardized measure.
We entered into our credit facility on November 20, 2012, which allows us to enter into commodity derivative instruments, the notional volumes for which when aggregated with other commodity swap agreements and additional fixed-price physical off-take contracts then in effect, as of the date such instrument is executed, is not greater than 80% of the reasonably anticipated projected production from our proved developed producing reserves. We intend to use of these commodity derivative instruments as a means of managing our exposure to price changes in the future. For additional discussion, see Item 2. Management’s Discuss and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Credit Facility above.
Interest Rate Risk
As of December 31, 2012, we had borrowed $23.5 million under our credit facility. Our credit facility with Wells Fargo subjects us to interest rate risk on borrowings. The credit facility allows us to fix the interest rate of borrowings under it for all or a portion of the principal balance for a period up to six months. To the extent the interest rate is fixed, interest rate changes affect the instrument’s fair market value but do not impact results of operations or cash flows. Conversely, for the portion of our borrowings that has a floating interest rate, interest rate changes will not affect the fair market value but will impact future results of operations and cash flows. The average annual interest rate incurred under our credit facilities for the year ended December 31, 2012 was 4.9%. A 1% increase in LIBOR on our outstanding debt as of December 31, 2012 would result in an estimated $235,000 increase in annual interest.
Item 8. Financial Statements and Supplementary Data
Our Financial Statements required by this item are included on the pages immediately following the Index to Financial Statements beginning on page F- 1.
Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed by us in the reports we file or furnish to the SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
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As of December 31, 2012, our management, consisting of our Chief Executive Officer and Chief Financial Officer, have evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) pursuant to Rule 13a-15(b) under the Exchange Act. Based upon and as of the date of the evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are designed and effective to ensure that information required to be disclosed is recorded, processed, summarized and reported within the specified periods and is accumulated and communicated to management, consisting of our Chief Executive Officer and Chief Financial Officer, to allow for timely decisions regarding required disclosure of material information required to be included in our periodic SEC reports. Based on the foregoing, our management determined that our disclosure controls and procedures were effective as of December 31, 2012.
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.
There were no changes in internal control over financial reporting during the fourth quarter of 2012 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). The design of any system of controls is 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, regardless of how remote. All internal control systems, no matter how well designed, have inherent limitations. Our internal control over financial reporting consists of the following policies and procedures that:
| · | Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; |
| · | Provide reasonable assurance that transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and |
| · | Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
We carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal controls over financial reporting as of December 31, 2012. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in “Internal Control — Integrated Framework.” Based on this assessment, management believes that, as of December 31, 2012, our internal control over financial reporting was effective based on those criteria.
The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by BDO USA, LLP, an independent registered public accounting firm, as stated in their report which is included in this annual report on Form 10-K.
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Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Emerald Oil, Inc.
Denver, Colorado
We have audited Emerald Oil, Inc.’s, formerly Voyager Oil & Gas, Inc., internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Emerald Oil, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on Emerald Oil, Inc.’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Emerald Oil, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheet of Emerald Oil, Inc. as of December 31, 2012 and 2011, and the related statements of operations, stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2012 and our report dated March 18, 2013 expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Houston, Texas
March 18, 2013
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Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.
Item 11. Executive Compensation
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.
Item 14. Principal Accountant Fees and Services
The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(a) Documents filed as Part of this Report:
1. Financial Statements
See Index to Financial Statements on page F- 1 .
2. Financial Statement Schedules
All schedules are omitted because they are either not applicable or required information is shown in the financial statements or notes thereto.
3. Exhibits
The exhibits set forth in the accompanying Exhibit Index are filed or incorporated by reference as part of this Form 10-K.
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Exhibit Index
| Exhibit No. | Description | Reference | ||
| 2.1 | Securities Purchase Agreement dated July 9, 2012, among Voyager Oil & Gas, Inc., Emerald Oil & Gas NL and Emerald Oil, Inc. | Exhibit 2.1 to the current report on Form 8-K of the registrant filed on July 10, 2012. | ||
| 2.1 | Purchase and Sale Agreement, dated as of September 6, 2012, by and between Emerald WB LLC and Slawson Exploration Company, Inc. | Exhibit 2.1 to the current report on Form 8-K of the registrant filed on September 10, 2012. | ||
| 2.3 | Letter Agreement dated as of January 7, 2013, by and between Emerald Oil, Inc. and East Management Services, LP. | Exhibit 2.1 to the current report on Form 8-K of the registrant filed on January 8, 2013. | ||
| 3.1 | Articles of Incorporation of Voyager Oil & Gas, Inc. | Exhibit 3.1 to our current report on Form 8-K filed on June 2, 2011. | ||
| 3.2 | Articles of Merger, dated as of May 31, 2011, by and between Voyager Oil & Gas, Inc., a Delaware corporation, and Voyager Oil & Gas 1, Inc., a Montana corporation. | Exhibit 2.1 to the current report on Form 8-K of the registrant filed on June 2, 2011. | ||
| 3.3 | Articles of Amendment to the Articles of Incorporation | Exhibit 3.1 to the current report on Form 8-K of the registrant filed on October 24, 2012. | ||
| 3.4 | Articles of Amendment to the Articles of Incorporation | Exhibit 3.1 to the current report on Form 8-K of the registrant filed on February 19, 2013. | ||
| 3.5 | Amended Bylaws of Emerald Oil, Inc. | Exhibit 3.2 to the quarterly report on Form 10-Q of the registrant filed on November 8, 2012. | ||
| 4.1 | Specimen Certificate of Common Stock, par value $0.001 per share of Emerald Oil, Inc. | Exhibit 4.1 to our current report on Form 8-K filed on October 24, 2012. | ||
| 4.2 | Form of Vesting Warrant. | Exhibit 4.2 to the Form S-3 registration statement of the registrant filed on April 30, 2010 (File No. 333-166402). | ||
| 4.3 | Form of Warrant. | Exhibit 4.3 to the Form S-3 registration statement of the registrant filed on April 30, 2010 (File No. 333-166402). | ||
| 4.4 | Form of Restricted Stock Award Agreement. | Exhibit 4.4 to the Form S-3 registration statement of the registrant filed on April 30, 2010 (File No. 333-166402). | ||
| 4.5 | Form of Lock-Up Agreement. | Exhibit 4.5 to the Form S-3 registration statement of the registrant filed on April 30, 2010 (File No. 333-166402). |
| 4.7 | Form of Warrant issued to investors in the February 2011 private placement. | Exhibit 5.1 to the Form S-3 registration statement of the registrant filed on February 11, 2011 (File No. 333-172210). | ||
| 4.8 | Form of Warrant issued to investors in the February 2013 private placement. | Exhibit 4.1 to the current report on Form 8-K of the registrant filed on February 19, 2013. | ||
| 10.1 | Securities Purchase Agreement dated February 1, 2011. | Exhibit 10.1 to the current report on Form 8-K of the registrant filed on February 7, 2011. | ||
| 10.2 | Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan. | Exhibit 10.1 to the quarterly report on Form 10-Q of the registrant filed on August 9, 2011. | ||
| 10.3 | Form of Incentive Stock Option Agreement under the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan. | Exhibit 10.1 to the quarterly report on Form 10-Q of the registrant filed on November 8, 2011. | ||
| 10.4 | Form of Nonqualified Stock Option Agreement under the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan. | Exhibit 10.2 to the quarterly report on Form 10-Q of the registrant filed on November 8, 2011. | ||
| 10.5 | Form of Restricted Stock Agreement under the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan. | Exhibit 10.3 to the quarterly report on Form 10-Q of the registrant filed on November 8, 2011. |
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| Exhibit No. | Description | Reference | ||
| 10.6 | Form of Restricted Stock Unit Agreement under the Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan. | Exhibit 10.4 to the quarterly report on Form 10-Q of the registrant filed on November 8, 2011. | ||
| 10.7 | Amendment to Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan. | Exhibit 4.1 to the current report on Form 8-K of the registrant filed on February 22, 2012. | ||
| 10.8 | Employment Agreement with James Russell Reger dated July 26, 2012 | Exhibit 10.2 to the current report on Form 8-K of the registrant filed on July 31, 2012. | ||
| 10.9 | Employment Agreement with McAndrew Rudisill dated July 26, 2012. | Exhibit 10.3 to the current report on Form 8-K of the registrant filed on July 31, 2012. | ||
| 10.10 | Employment Agreement with Mike Krzus dated July 26, 2012 | Exhibit 10.4 to the current report on Form 8-K of the registrant filed on July 31, 2012. | ||
| 10.11 | Employment Agreement with Mitchell R. Thompson dated July 26, 2012 | Exhibit 10.5 to the current report on Form 8-K of the registrant filed on July 31, 2012. | ||
| 10.12 | Employment Agreement with Paul Wiesner dated July 26, 2012. | Exhibit 10.6 to the current report on Form 8-K of the registrant filed on July 31, 2012. | ||
| 10.13 | Employment Agreement with Karl Osterbuhr dated July 26, 2012 | Exhibit 10.7 to the current report on Form 8-K of the registrant filed on July 31, 2012. | ||
| 10.14 | Employment Agreement with Martin J. Beskow dated March 30, 2012. | Exhibit 10.1 to the current report on Form 8-K of the registrant filed on April 5, 2012. | ||
| 10.15 | Amendment to 2011 Voyager Oil & Gas, Inc. 2011 Equity Incentive Plan. | Exhibit 10.1 to the current report on Form 8-K of the registrant filed on October 24, 2012. | ||
| 10.16 | Amendment No. 1 to Employment Agreement with James Russell Reger dated November 15, 2012. | Exhibit 10.2 to the current report on Form 8-K of the registrant filed on November 21, 2012. | ||
| 10.17 | Amendment No. 1 to Employment Agreement with McAndrew Rudisill dated November 15, 2012. | Exhibit 10.3 to the current report on Form 8-K of the registrant filed on November 21, 2012. | ||
| 10.18 | Amendment No. 1 to Employment Agreement with Mike Krzus dated November 15, 2012. | Exhibit 10.4 to the current report on Form 8-K of the registrant filed on November 21, 2012. | ||
| 10.19 | Amendment No. 1 to Employment Agreement with Mitchell R. Thompson dated November 15, 2012. | Exhibit 10.5 to the current report on Form 8-K of the registrant filed on November 21, 2012. | ||
| 10.20 | Amendment No. 1 to Employment Agreement with Paul Wiesner dated November 15, 2012. | Exhibit 10.6 to the current report on Form 8-K of the registrant filed on November 21, 2012. |
| 10.21 | Amendment No. 1 to Employment Agreement with Karl Osterbuhr dated November 15, 2012. | Exhibit 10.7 to the current report on Form 8-K of the registrant filed on November 21, 2012. |
| 10.22 | Second Amendment to Employment Agreement with Mike Krzus effective as of March 16, 2013. | Exhibit 10.1 to the current report on Form 8-K of the registrant filed on March 14, 2013. | ||
| 10.23 | Second Amendment to Employment Agreement with McAndrew Rudisill effective as of March 16, 2013. | Exhibit 10.2 to the current report on Form 8-K of the registrant filed on March 14, 2013. | ||
| 10.24 | Second Amendment to Employment Agreement with J.R. Reger effective as of March 16, 2013. | Exhibit 10.3 to the current report on Form 8-K of the registrant filed on March 14, 2013. | ||
| 10.25 | Second Amendment to Employment Agreement with Paul Wiesner effective as of March 16, 2013. | Exhibit 10.4 to the current report on Form 8-K of the registrant filed on March 14, 2013. | ||
| 10.26 | Second Amendment to Employment Agreement with Karl Osterbuhr effective as of March 16, 2013. | Exhibit 10.5 to the current report on Form 8-K of the registrant filed on March 14, 2013. |
| 10.27 | Credit Agreement dated November 20, 2012, among Emerald Oil, Inc., as Borrower, Wells Fargo Bank, N.A., as Administrative Agent, and the Lenders party thereto | Exhibit 10.1 to the current report on Form 8-K of the registrant filed on November 21, 2012. | ||
| 10.28 | First Amendment to Credit Agreement dated as of February 18, 2013, among Emerald Oil, Inc., the Guarantors, the Lenders and Wells Fargo Bank, N.A., as administrative agent for the Lenders. | Exhibit 10.3 to the current report on Form 8-K of the registrant filed on February 19, 2013. | ||
| 10.29 | Securities Purchase Agreement dated February 1, 2013, among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P. | Exhibit 10.1 to the current report on Form 8-K of the registrant filed on February 6, 2013. |
| 41 |
| 10.30 | Registration Rights Agreement dated February 19, 2013, among Emerald Oil, Inc., WDE Emerald Holdings LLC and White Deer Energy FI L.P. | Exhibit 10.1 to the current report on Form 8-K of the registrant filed on February 19, 2013. | ||
| 10.31 | Form of Indemnification Agreement. | Exhibit 10.2 to the current report on Form 8-K of the registrant filed on February 19, 2013. | ||
| 14.1 | Code of Ethics. | Filed herewith. | ||
| 16.1 | Letter from Mantyla McReyonlds, LLC dated October 6, 2011. | Exhibit 16.1 to the current report on Form 8-K of the registrant filed on October 7, 2011. | ||
| 21.1 | List of Subsidiaries. | Filed herewith. | ||
| 23.1 | Consent of Independent Registered Public Accounting Firm BDO USA, LLP. | Filed herewith. | ||
| 23.2 | Consent of Independent Registered Public Accounting Firm Mantyla McReyonlds LLC. | Filed herewith. | ||
| 23.3 | Consent of Netherland, Sewell & Associates, Inc. | Filed herewith. | ||
| 24.1 | Power of Attorney (included on signature page). | Filed herewith. | ||
| 31.1 | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | Filed herewith. | ||
| 31.2 | Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | Filed herewith. | ||
| 32.1 | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | Filed herewith. | ||
| 32.2 | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | Filed herewith. | ||
| 99.1 | Report of Netherland, Sewell & Associates, Inc. | Filed herewith. | ||
| 101.INS | XBRL Instance Document. | Filed herewith. | ||
| 101.SCH | XBRL Schema Document. | Filed herewith. | ||
| 101.CAL | XBRL Calculation Linkbase Document. | Filed herewith. | ||
| 101.DEF | XBRL Definition Linkbase Document. | Filed herewith. | ||
| 101.LAB | XBRL Label Linkbase Document. | Filed herewith. | ||
| 101.PRE | XBRL Presentation Linkbase Document. | Filed herewith. |
| 42 |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| EMERALD OIL, INC. | ||
| Date: March 18, 2013 |
By: /s/ MICHAEL KRZUS |
POWER OF ATTORNEY
Each person whose signature appears below constitutes and appoints, Michael Krzus and Paul Wiesner, or either of them, his true and lawful attorney-in-fact and agent, acting alone, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Annual Report on Form 10-K and to file the same, with all exhibits thereto, and other documents in connection wherewith, with the Commission, granting unto said attorney-in-fact and agent, each acting alone, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all said attorney-in-fact and agent, acting alone, or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated:
| Signature | Title | Date | ||
| /s/ MICHAEL KRZUS Michael Krzus |
Director; Chief Executive Officer | March 18, 2013 | ||
| /s/ PAUL WIESNER Paul Wiesner |
Chief Financial Officer | March 18, 2013 | ||
| /s/ JAMES RUSSELL (J.R.) REGER James Russell (J.R.) Reger |
Director; Executive Chairman | March 18, 2013 | ||
| /s/ MCANDREW RUDISILL McAndrew Rudisill |
Director; President | March 18, 2013 | ||
| /s/ LYLE BERMAN | Director | March 18, 2013 | ||
| Lyle Berman | ||||
| /s/ THOMAS J. EDELMAN | Director | March 18, 2013 | ||
| Thomas J. Edelman | ||||
| /s/ DUKE R. LIGON Duke R. Ligon |
Director | March 18, 2013 | ||
| /s/ DANIEL L. SPEARS Daniel L. Spears |
Director | March 18, 2013 | ||
| /s/ SETH SETRAKIAN Seth Setrakian |
Director | March 18, 2013 |
| 43 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Page | ||||
| Reports of Independent Registered Public Accounting Firms | F- | 2 | ||
| Consolidated Balance Sheets as of December 31, 2012 and 2011 | F- | 4 | ||
| Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010 | F- | 5 | ||
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010 | F- | 6 | ||
| Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010 | F- | 7 | ||
| Notes to the Consolidated Financial Statements | F- | 8 | ||
| F-1 |
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Emerald Oil, Inc.
Denver, Colorado
We have audited the accompanying consolidated balance sheets of Emerald Oil, Inc., formerly Voyager Oil & Gas, Inc., as of December 31, 2012 and 2011 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Emerald Oil, Inc. at December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Emerald Oil, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria) and our report dated March 18, 2013 expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Houston, Texas
March 18, 2013
| F-2 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Emerald Oil, Inc.
Denver, CO
We have audited the accompanying Emerald Oil, Inc. formerly Voyager Oil & Gas, Inc. (the Company) statements of operations, stockholders’ equity, and cash flows for the year ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of the Company for the year ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America.
/s/ Mantyla McReynolds LLC
Mantyla McReynolds LLC
Salt Lake City, Utah
March 14, 2011
| F-3 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31,
| 2012 | 2011 | |||||||
| ASSETS | ||||||||
| CURRENT ASSETS | ||||||||
| Cash and Cash Equivalents | $ | 10,192,379 | $ | 13,927,267 | ||||
| Trade Receivables | 12,573,156 | 3,247,412 | ||||||
| Other Receivables | 1,133,849 | — | ||||||
| Prepaid Expenses and Other Current Assets | 103,173 | 48,330 | ||||||
| Total Current Assets | 24,002,557 | 17,223,009 | ||||||
| PROPERTY AND EQUIPMENT | ||||||||
| Oil and Natural Gas Properties, Full Cost Method | ||||||||
| Proved Oil and Natural Gas Properties | 167,618,422 | 60,425,243 | ||||||
| Unproved Oil and Natural Gas Properties | 61,454,831 | 32,180,217 | ||||||
| Other Property and Equipment | 385,023 | 176,238 | ||||||
| Total Property and Equipment | 229,458,276 | 92,781,698 | ||||||
| Less – Accumulated Depreciation, Depletion and Amortization | (80,230,517 | ) | (5,505,288 | ) | ||||
| Total Property and Equipment, Net | 149,227,759 | 87,276,410 | ||||||
| Prepaid Drilling Costs | 100,193 | 33,163 | ||||||
| Fair Value of Commodity Derivatives | 25,397 | — | ||||||
| Debt Issuance Costs, Net of Amortization | 269,681 | 306,839 | ||||||
| Other Non-Current Assets | 260,775 | — | ||||||
| Total Assets | $ | 173,886,362 | $ | 104,839,421 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
| CURRENT LIABILITIES | ||||||||
| Accounts Payable | $ | 39,169,037 | $ | 10,375,239 | ||||
| Fair Value of Commodity Derivatives | 206,645 | — | ||||||
| Accrued Expenses | 420,521 | 206,122 | ||||||
| Total Current Liabilities | 39,796,203 | 10,581,361 | ||||||
| LONG-TERM LIABILITIES | ||||||||
| Revolving Credit Facility | 23,500,000 | — | ||||||
| Senior Secured Promissory Notes | — | 15,000,000 | ||||||
| Asset Retirement Obligations | 296,074 | 116,119 | ||||||
| Total Liabilities | 63,592,277 | 25,697,480 | ||||||
| COMMITMENTS AND CONTINGENCIES | ||||||||
| STOCKHOLDERS’ EQUITY | ||||||||
| Preferred Stock – Par Value $.001; 20,000,000 Shares Authorized; None Issued or Outstanding | — | — | ||||||
| Common Stock, Par Value $.001; 500,000,000 Shares Authorized, 24,734,643 and 8,264,062 Shares Issued and Outstanding, respectively | 24,735 | 8,264 | ||||||
| Additional Paid-In Capital | 180,439,530 | 87,007,758 | ||||||
| Accumulated Deficit | (70,170,180 | ) | (7,874,081 | ) | ||||
| Total Stockholders’ Equity | 110,294,085 | 79,141,941 | ||||||
| Total Liabilities and Stockholders’ Equity | $ | 173,886,362 | $ | 104,839,421 | ||||
The accompanying notes are an integral part of these financial statements.
| F-4 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| REVENUES | ||||||||||||
| Oil and Natural Gas Sales | $ | 28,129,985 | $ | 8,426,129 | $ | 942,840 | ||||||
| Loss on Commodity Derivatives | (215,439 | ) | — | — | ||||||||
| Total Revenues | 27,914,546 | 8,426,129 | 942,840 | |||||||||
| OPERATING EXPENSES | ||||||||||||
| Production Expenses | 2,727,133 | 726,946 | 26,686 | |||||||||
| Production Taxes | 2,955,015 | 717,440 | 102,743 | |||||||||
| General and Administrative Expenses | 12,903,845 | 2,686,176 | 1,778,161 | |||||||||
| Depletion of Oil and Natural Gas Properties | 12,770,718 | 3,546,466 | 547,844 | |||||||||
| Impairment of Oil and Natural Gas Properties | 61,900,692 | — | 1,377,188 | |||||||||
| Depreciation and Amortization | 53,818 | 30,831 | 2,929 | |||||||||
| Accretion of Discount on Asset Retirement Obligations | 14,988 | 4,882 | 358 | |||||||||
| Gain on Acquisition of Business, Net | (5,758,048 | ) | — | — | ||||||||
| Total Expenses | 87,568,161 | 7,712,741 | 3,835,909 | |||||||||
| INCOME (LOSS) FROM OPERATIONS | (59,653,615 | ) | 713,388 | (2,893,069 | ) | |||||||
| OTHER INCOME (EXPENSE) | ||||||||||||
| Merger Costs | — | — | (735,942 | ) | ||||||||
| Interest Expense | (2,614,240 | ) | (2,036,032 | ) | (629,026 | ) | ||||||
| Other Income (Expense) | (28,244 | ) | (22,410 | ) | 54,708 | |||||||
| Total Other Income (Expense), Net | (2,642,484 | ) | (2,058,442 | ) | (1,310,260 | ) | ||||||
| LOSS BEFORE INCOME TAXES | (62,296,099 | ) | (1,345,054 | ) | (4,203,329 | ) | ||||||
| INCOME TAX PROVISION | — | — | 65,240 | |||||||||
| NET LOSS | $ | (62,296,099 | ) | $ | (1,345,054 | ) | $ | (4,268,569 | ) | |||
| Net Loss Per Common Share – Basic and Diluted | $ | (4.91 | ) | $ | (0.17 | ) | $ | (0.79 | ) | |||
| Weighted Average Shares Outstanding – Basic and Diluted | 12,699,544 | 8,012,158 | 5,434,084 | |||||||||
The accompanying notes are an integral part of these financial statements.
| F-5 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| CASH FLOWS FROM OPERATING ACTIVITIES | ||||||||||||
| Net Loss | $ | (62,296,099 | ) | $ | (1,345,054 | ) | $ | (4,268,569 | ) | |||
| Adjustments to Reconcile Net Loss to Net Cash Provided By (Used For) Operating Activities: | ||||||||||||
| Depletion of Oil and Natural Gas Properties | 12,770,718 | 3,546,466 | 547,844 | |||||||||
| Impairment of Oil and Natural Gas Properties | 61,900,692 | — | 1,377,188 | |||||||||
| Depreciation and Amortization | 53,818 | 30,831 | 2,929 | |||||||||
| Amortization of Premium on Bonds | — | — | 46,448 | |||||||||
| Amortization of Debt Discount | — | 163,356 | 61,664 | |||||||||
| Amortization of Debt Issuance Costs | 1,929,561 | 82,191 | — | |||||||||
| Loss on Disposal of Property and Equipment | — | — | 34,305 | |||||||||
| Accretion of Discount on Asset Retirement Obligations | 14,988 | 4,882 | 358 | |||||||||
| Gain on Sale of Available for Sale Securities | — | — | (1,520 | ) | ||||||||
| Unrealized Loss on Derivative Instruments | 181,248 | — | — | |||||||||
| Gain on Acquisition of Business | (7,213,835 | ) | — | — | ||||||||
| Share-Based Compensation Expense | 7,318,690 | 728,546 | 882,804 | |||||||||
| Changes in Assets and Liabilities: | ||||||||||||
| Increase in Trade Receivables | (9,325,744 | ) | (2,951,591 | ) | (295,821 | ) | ||||||
| Increase in Other Receivables | (1,133,849 | ) | — | — | ||||||||
| (Increase) Decrease in Prepaid Expenses and Other Current Assets | (54,843 | ) | 90,123 | 198,350 | ||||||||
| Increase in Other Non-Current Assets | (100,100 | ) | — | — | ||||||||
| Increase (Decrease) in Accounts Payable | 30,123 | (319,349 | ) | 411,469 | ||||||||
| Increase (Decrease) in Accrued Expenses | 214,399 | (183,557 | ) | (163,083 | ) | |||||||
| Net Cash Provided By (Used For) Operating Activities | 4,289,767 | (153,156 | ) | (1,165,634 | ) | |||||||
| CASH FLOWS FROM INVESTING ACTIVITIES | ||||||||||||
| Cash Received from Merger Agreement | — | — | 17,413,845 | |||||||||
| Cash Received on Note Receivable | — | — | 500,000 | |||||||||
| Purchases of Other Property and Equipment | (172,785 | ) | (157,892 | ) | (598 | ) | ||||||
| Prepaid Drilling Costs | (67,030 | ) | 460,497 | (493,660 | ) | |||||||
| Proceeds from Sales of Available for Sale Securities | — | 242,070 | 9,769,881 | |||||||||
| Investment in Oil and Natural Gas Properties | (66,212,818 | ) | (44,052,953 | ) | (30,934,671 | ) | ||||||
| Net Cash Used For Investing Activities | (66,452,633 | ) | (43,508,278 | ) | (3,745,203 | ) | ||||||
| CASH FLOWS FROM FINANCING ACTIVITIES | ||||||||||||
| Proceeds from Issuance of Common Stock – Net of Issuance Costs | 72,167,012 | 46,602,251 | 779,240 | |||||||||
| Proceeds from Issuance of Senior Secured Promissory Notes | — | — | 14,775,000 | |||||||||
| Advances on Revolving Credit Facility and Term Loan | 56,530,730 | — | — | |||||||||
| Payments on Revolving Credit Facility and Term Loan | (33,030,730 | ) | — | — | ||||||||
| Payments of Senior Secured Promissory Notes | (15,000,000 | ) | — | — | ||||||||
| Payment of Assumed Liabilities | (20,303,903 | ) | — | — | ||||||||
| Cash Paid for Debt Issuance Costs | (1,935,131 | ) | (389,030 | ) | — | |||||||
| Proceeds from Exercise of Stock Options and Warrants | — | 16,960 | 23,854 | |||||||||
| Net Cash Provided by Financing Activities | 58,427,978 | 46,230,181 | 15,578,094 | |||||||||
| NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (3,734,888 | ) | 2,568,747 | (10,667,257 | ) | |||||||
| CASH AND CASH EQUIVALENTS – BEGINNING OF PERIOD | 13,927,267 | 11,358,520 | 691,263 | |||||||||
| CASH AND CASH EQUIVALENTS – END OF PERIOD | $ | 10,192,379 | $ | 13,927,267 | $ | 11,358,520 | ||||||
| Supplemental Disclosure of Cash Flow Information | ||||||||||||
| Cash Paid During the Period for Interest | $ | 1,154,943 | $ | 1,800,000 | $ | 380,933 | ||||||
| Cash Paid During the Period for Income Taxes | $ | — | $ | — | $ | 65,240 | ||||||
| Non-Cash Financing and Investing Activities: | ||||||||||||
| Oil and Natural Gas Properties Included in Account Payable | $ | 38,973,137 | $ | 10,252,407 | $ | 95,576 | ||||||
| Stock-Based Compensation Capitalized to Oil and Natural Gas Properties | $ | 582,040 | $ | 418,414 | $ | — | ||||||
| Capitalized Asset Retirement Obligations | $ | 164,967 | $ | 100,715 | $ | 10,164 | ||||||
| Purchases through Issuance of Common Stock or Assumption of Liabilities: | ||||||||||||
| Oil and Natural Gas Properties | $ | 40,787,238 | $ | — | $ | 2,358,900 | ||||||
| Other Property and Equipment | $ | 36,000 | $ | — | $ | — | ||||||
| Other Non-Current Assets | $ | 75,000 | $ | — | $ | — | ||||||
| Non-Cash Acquisition of Business Amounts: | ||||||||||||
| Fair Market of Common Stock Issued | $ | 13,380,501 | $ | — | $ | — | ||||||
| Debt Assumed | $ | 20,303,903 | $ | — | $ | — | ||||||
The accompanying notes are an integral part of these financial statements.
| F-6 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
CONSOLIDATED STATEMENTS OF
STOCKHOLDERS’ EQUITY (DEFICIT)
FOR THE YEARS ENDED DECEMBER 31, 2012, 2011 AND 2010
| Common Stock | Additional Paid-In Capital | Accumulated Other Comprehensive Income (Loss) | Accumulated Deficit | Total Stockholders’ Equity | ||||||||||||||||||||
| Shares | Amount | |||||||||||||||||||||||
| Balance – December 31, 2009 | 2,619,915 | $ | 2,620 | $ | 7,683,956 | $ | 6,486 | $ | (2,260,458 | ) | $ | 5,432,604 | ||||||||||||
| Sale of 114,624 Common Shares at $7.42 Per Share | 114,624 | 115 | 846,885 | — | — | 847,000 | ||||||||||||||||||
| Issued 25,217 Common Shares related to Capital Raise | 25,217 | 25 | (25 | ) | — | — | — | |||||||||||||||||
| Private Placement Cost Net of Common Shares Issued | — | — | (67,760 | ) | — | — | (67,760 | ) | ||||||||||||||||
| Issued Pursuant to Exercise of Warrants | 29,772 | 30 | 770 | — | — | 800 | ||||||||||||||||||
| Restricted Stock Grant Compensation | — | — | 57,376 | — | — | 57,376 | ||||||||||||||||||
| Compensation Related to Stock Warrant Grants | — | — | 120,770 | — | — | 120,770 | ||||||||||||||||||
| Issued 319,229 Common Shares for Leaseholds Interests | 319,229 | 319 | 2,358,581 | — | — | 2,358,900 | ||||||||||||||||||
| Balance Immediately Before Reverse Acquisition with Ante4, Inc. | 3,108,757 | 3,109 | 11,000,553 | 6,486 | (2,260,458 | ) | 8,749,690 | |||||||||||||||||
| Acquisition of Ante4, Inc. | 3,041,762 | 3,041 | 27,515,436 | — | — | 27,518,477 | ||||||||||||||||||
| Balance Immediately After Reverse Acquisition with Ante4, Inc. | 6,150,519 | 6,150 | 38,515,989 | 6,486 | (2,260,458 | ) | 36,268,167 | |||||||||||||||||
| Issuance Pursuant to Exercise of Options | 5,715 | 6 | 23,048 | — | — | 23,054 | ||||||||||||||||||
| Issued Pursuant to Exercise of Warrants | 321,542 | 321 | (321 | ) | — | |||||||||||||||||||
| Restricted Stock Grant Compensation | — | — | 172,128 | — | — | 172,128 | ||||||||||||||||||
| Compensation Related to Stock Warrant Grants | — | — | 362,311 | — | — | 362,311 | ||||||||||||||||||
| Director Fees Related to Stock Option Grants | — | — | 170,219 | — | — | 170,219 | ||||||||||||||||||
| Net Change in Unrealized Gains on Available for Sale Investments | — | — | — | (6,486 | ) | — | (6,486 | ) | ||||||||||||||||
| Net Loss | — | — | — | — | (4,268,569 | ) | (4,268,569 | ) | ||||||||||||||||
| Balance – December 31, 2010 | 6,477,776 | 6,477 | 39,243,374 | — | (6,529,027 | ) | 32,720,824 | |||||||||||||||||
| Issuance Pursuant to Exercise of Options | 572 | 1 | 16,959 | — | — | 16,960 | ||||||||||||||||||
| Net Proceeds from Equity Offering | 1,785,714 | 1,786 | 46,600,465 | — | — | 46,602,251 | ||||||||||||||||||
| Restricted Stock Grant Compensation | — | — | 226,318 | — | — | 226,318 | ||||||||||||||||||
| Compensation Related to Stock Warrant and Option Grants | — | — | 649,694 | — | — | 649,694 | ||||||||||||||||||
| Director Fees Related to Stock Option Grants | — | — | 270,948 | — | — | 270,948 | ||||||||||||||||||
| Net Loss | — | — | — | — | (1,345,054 | ) | (1,345,054 | ) | ||||||||||||||||
| Balance – December 31, 2011 | 8,264,062 | 8,264 | 87,007,758 | — | (7,874,081 | ) | 79,141,941 | |||||||||||||||||
| Common Shares Issued as Compensation | 910,296 | 910 | 3,837,212 | — | — | 3,838,122 | ||||||||||||||||||
| Restricted Stock Grants | 74,285 | 74 | (74 | ) | — | — | — | |||||||||||||||||
| Restricted Stock Forfeited | (53,572 | ) | (53 | ) | 53 | — | — | — | ||||||||||||||||
| Restricted Stock Grant Compensation | — | — | 1,178,559 | — | — | 1,178,559 | ||||||||||||||||||
| Compensation Related to Stock Option Grants | — | — | 1,779,901 | — | — | 1,779,901 | ||||||||||||||||||
| Director Fees Related to Stock Option Grants | — | — | 1,104,147 | — | — | 1,104,147 | ||||||||||||||||||
| Issuance of Common Shares for the Acquisition of Emerald Oil North America, Inc. | 1,662,174 | 1,662 | 13,378,839 | — | — | 13,380,501 | ||||||||||||||||||
| Net Proceeds from Equity Offering | 13,877,555 | 13,878 | 72,153,134 | — | — | 72,167,012 | ||||||||||||||||||
| Reverse Split Reconciliation Due to Fractional Shares | (157 | ) | — | — | — | — | — | |||||||||||||||||
| Net Loss | — | — | — | — | (62,296,099 | ) | (62,296,099 | ) | ||||||||||||||||
| Balance – December 31, 2012 | 24,734,643 | $ | 24,735 | $ | 180,439,530 | $ | — | $ | (70,170,180 | ) | $ | 110,294,085 | ||||||||||||
The accompanying notes are an integral part of these financial statements.
| F-7 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
NOTE 1 ORGANIZATION AND NATURE OF BUSINESS
Description of Operations — Emerald Oil, Inc. (formerly Voyager Oil & Gas, Inc.), a Montana corporation (the “Company”), is an independent oil and natural gas exploration and production company engaged in the business of acquiring acreage in prospective natural resource plays within the continental United States (“U.S.”), primarily focused on the Williston Basin located in North Dakota and Montana. The Company also holds acreage in other emerging oil plays in Colorado, Wyoming and Montana. The Company seeks to accumulate acreage that builds net asset value by growing reserves and converting undeveloped assets into producing wells in repeatable and scalable shale oil plays.
The Company has historically participated in well development as a non-operator and is in the process of building operations to plan and design well development as an operator on acreage where a controlling interest is held. The Company had 14 employees as of December 31, 2012 and retains independent contractors to assist in operating and managing its prospects as well as to carry out the principal and necessary functions incidental to the oil and natural gas business. With the acquisition of Emerald Oil North America, Inc., formerly known as Emerald Oil, Inc. (“Emerald Oil North America”) on July 26, 2012 (see Note 3 – Acquisition of Business), the Company has added executive management that is experienced in well development and intends to build on these capabilities internally and through partnering with others to leverage best practices. Production from oil wells has increased significantly, and the Company intends to add to this production by operating its own wells, while continuing to participate as a non-operator in wells managed by other operators.
NOTE 2 SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
Reverse Stock Split
The Company’s board of directors approved a 1-for-7 reverse stock split pursuant to which all shareholders of record received one share of common stock for each seven shares of common stock owned (subject to minor adjustments as a result of fractional shares). On October 22, 2012, a majority of the Company’s shareholders approved the reverse stock split. This reverse stock split decreased the issued and outstanding shares by approximately 140,339,000, the outstanding warrants by approximately 6,700,000 and the outstanding stock options by approximately 4,100,000. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all stock, warrant and option transactions described herein have been adjusted to reflect the 1-for-7 reverse stock split.
Cash and Cash Equivalents
The Company considers highly liquid investments with insignificant interest rate risk and original maturities of three months or less to be cash equivalents. Cash equivalents consist primarily of interest-bearing bank accounts and money market funds. The Company’s cash positions represent assets held in checking and money market accounts. These assets are generally available to the Company on a daily or weekly basis and are highly liquid in nature. All of the Company’s non-interest bearing cash accounts were fully insured at December 31, 2012 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning 2013, insurance coverage will revert to $250,000 per depositor at each financial institution, and the Company’s non-interest bearing cash balances may then exceed federally insured limits. In addition, the Company is subject to Security Investor Protection Corporation protection on a vast majority of its financial assets in the event one of the brokerage firms that the Company utilizes for its investments fails.
Full Cost Method
The Company follows the full cost method of accounting for oil and natural gas operations whereby all costs related to the exploration and development of oil and natural gas properties are initially capitalized into a single cost center (“full cost pool”). Such costs include land acquisition costs, a portion of employee salaries related to property development, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition, and exploration activities. For the years ended December 31, 2012, 2011 and 2010, the Company capitalized $842,418, $526,630 and $0, respectively, of internal salaries, which included $582,040, $418,414 and $0, respectively, of stock-based compensation. Internal salaries are capitalized based on employee time allocated to the acquisition of leaseholds and development of oil and natural gas properties. The Company capitalized interest of $362,688 for the year ended December 31, 2012. The Company did not capitalize interest for the years ended December 31, 2011 and 2010.
Proceeds from property sales will generally be credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. The Company has had no property sales since inception, but has a sale pending in the Sand Wash Basin (see Note 16 – Subsequent Events) and engages in acreage trades in the Williston Basin.
The Company assesses all items classified as unevaluated property on a quarterly basis for possible impairment or reduction in value. The assessment includes consideration of the following factors, among others: intent to drill, remaining lease term, geological and geophysical evaluations, drilling results and activity, the assignment of proved reserves, and the economic viability of development if proved reserves are assigned. During any period in which these factors indicate an impairment, the cumulative drilling costs incurred to date for such property and all or a portion of the associated leasehold costs are transferred to the full cost pool and are then subject to depletion and amortization. For the years ended December 31, 2012 and 2011, the Company included $3,625,209 and $6,983,125, respectively, related to expiring leases within costs subject to the depletion calculation.
Capitalized costs associated with impaired properties and properties having proved reserves, estimated future development costs, and asset retirement costs under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 410-20-25 are depleted and amortized on the unit-of-production method based on the estimated gross proved reserves. The costs of unproved properties are withheld from the depletion base until such time as they are either developed, impaired, or abandoned.
Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion, net of deferred income taxes, may not exceed a ceiling amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, which is tested on a quarterly basis, an impairment is recognized. The present value of estimated future net revenues was computed by applying prices based on a 12-month arithmetic average of the oil and natural gas prices in effect on the first day of each month, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes. Based on calculated reserves at December 31, 2012, 2011 and 2010, the unamortized costs of the Company’s oil and natural gas properties exceeded the ceiling test limit by $51,709,458, $0 and $1,377,188, respectively. The Company also recognized that oil and natural gas properties exceeded the ceiling test limit as of June 30, 2012 by $10,191,234. As a result, the Company was required to record impairment of the net capitalized costs of its oil and natural gas properties in the amount of $61,900,692, $0 and $1,377,188, for the years ended December 31, 2012, 2011 and 2010 respectively.
Oil and Natural Gas Reserve Quantities
Emerald’s estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Pressler Petroleum Consultants, Inc. prepares a reserve and economic evaluation of all Emerald’s properties on a case-by-case basis utilizing information provided to it by Emerald and information available from state agencies that collect information reported to it by the operators of Emerald’s properties. The reserve estimates are then independently audited by Netherland, Sewell & Associates, Inc. The estimate of Emerald’s proved reserves as of December 31, 2012, 2011 and 2010 have been prepared and presented in accordance with SEC rules and accounting standards.
Reserves and their relation to estimated future net cash flows impact Emerald’s depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. Emerald prepares its reserve estimates, and the projected cash flows derived from these reserve estimates, in accordance with SEC guidelines. The independent engineering firms described above adhere to the same guidelines when preparing and auditing the reserve report, respectively. The accuracy of Emerald’s reserve estimates is a function of many factors including the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgments of the individuals preparing the estimates.
Emerald’s proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.
| F-8 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
Other Property and Equipment
Property and equipment that are not oil and natural gas properties are recorded at cost and depreciated using the straight-line method over their estimated useful lives of three to seven years. Expenditures for replacements, renewals, and betterments are capitalized. Maintenance and repairs are charged to operations as incurred. Depreciation expense was $53,818, $30,831 and $2,929 for the years ended December 31, 2012, 2011 and 2010, respectively.
ASC 360-10-35-21 requires that long-lived assets, other than oil and natural gas properties, be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The determination of impairment is based upon expectations of undiscounted future cash flows, before interest, of the related asset. If the carrying value of the asset exceeds the undiscounted future cash flows, the impairment would be computed as the difference between the carrying value of the asset and the fair value. The Company has not recognized any impairment losses on non-oil and natural gas long lived assets.
Asset Retirement Obligations
The Company records the fair value of a liability for an asset retirement obligation in the period in which the well is spud or the asset is acquired and a corresponding increase in the carrying amount of the related long-lived asset. The liability is accreted to its present value each period, and the capitalized cost is depleted using the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.
Revenue Recognition and Natural Gas Balancing
The Company recognizes oil and natural gas revenues from its interests in producing wells when production is delivered and title has transferred to the purchaser, to the extent the selling price is reasonably determinable. The Company uses the sales method of accounting for balancing of natural gas production and would recognize a liability if the existing proven reserves were not adequate to cover the current imbalance situation. As of December 31, 2012 and 2011, the Company’s natural gas production was in balance, i.e., its cumulative portion of natural gas production taken and sold from wells in which it has an interest equaled the Company’s entitled interest in natural gas production from those wells.
Stock-Based Compensation
The Company has accounted for stock-based compensation under the provisions of ASC 718-10-55. The Company recognizes stock-based compensation expense in the financial statements over the vesting period of equity-classified employee stock-based compensation awards based on the grant date fair value of the awards, net of estimated forfeitures. For options and warrants the Company uses the Black-Scholes option valuation model to calculate the fair value of stock based compensation awards at the date of grant. Option pricing models require the input of highly subjective assumptions, including the expected price volatility. For the stock options and warrants granted the Company has used a variety of comparable and peer companies to determine the expected volatility input based on the expected term of the options. The Company believes the use or peer company data fairly represents the expected volatility it would experience if it were in the oil and natural gas industry over the expected term of the options. The Company used the simplified method to determine the expected term of the options due to the lack of historical data. Changes in these assumptions can materially affect the fair value estimate.
On May 27, 2011, the shareholders of the Company approved the 2011 Equity Incentive Plan (the “2011 Plan”), under which 714,286 shares of common stock were reserved. On October 22, 2012, the shareholders of the Company approved an amendment to the 2011 Plan to increase the number of shares available for issuance under the 2011 Plan to 3,500,000 shares. The purpose of the 2011 Plan is to promote the success of the Company and its affiliates by facilitating the employment and retention of competent personnel and by furnishing incentives to those officers, directors and employees upon whose efforts the success of the Company and its affiliates will depend to a large degree. It is the intention of the Company to carry out the 2011 Plan through the granting of incentive stock options, nonqualified stock options, restricted stock awards, restricted stock unit awards, performance awards and stock appreciation rights. As of December 31, 2012, 735,705 stock options and 2,743,717 shares of common stock and restricted stock units had been issued to officers, directors and employees under the 2011 Plan, including 1,847,701 unvested restricted stock units. As of December 31, 2012, there are 20,578 shares available for issuance under the 2011 Plan.
| F-9 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
Income Taxes
The Company accounts for income taxes under ASC 740-10-30. Deferred income tax assets and liabilities are determined based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Accounting standards require the consideration of a valuation allowance for deferred tax assets if it is “more likely than not” that some component or all of the benefits of deferred tax assets will not be realized.
The tax effects from an uncertain tax position can be recognized in the financial statements only if the position is more likely than not of being sustained if the position were to be challenged by a taxing authority. The Company has examined the tax positions taken in its tax returns and determined that there are no uncertain tax positions. As a result, the Company has recorded no uncertain tax liabilities in its consolidated balance sheet.
Net Income (Loss) Per Common Share
Basic net income (loss) per common share is based on the net income (loss) divided by the weighted average number of common shares outstanding during the period. Diluted earnings per share are computed using the weighted average number of common shares plus dilutive common share equivalents outstanding during the period using the treasury stock method. In the computation of diluted earnings per share, excess tax benefits that would be created upon the assumed vesting of unvested restricted shares or the assumed exercise of stock options (i.e., hypothetical excess tax benefits) are included in the assumed proceeds component of the treasury stock method to the extent that such excess tax benefits are more likely than not to be realized. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. As the Company had losses for the years ended December 31, 2012, 2011 and 2010, the potentially dilutive shares were anti-dilutive and were thus not included in the net loss per share calculation.
As of December 31, 2012, (i) 1,847,701 unvested restricted stock units were issued and outstanding and represent potentially dilutive shares; (ii) 424,986 stock options that were issued and presently exercisable and represent potentially dilutive shares; (iii) 410,716 stock options that were granted but are not presently exercisable and represent potentially dilutive shares; (iv) 223,293 warrants that were issued and presently exercisable, which have an exercise price of $6.86; and (v) 892,858 warrants that were issued and presently exercisable, which have an exercise price of $49.70.
| F-10 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
Commodity Derivative Instruments
The Company has entered into commodity derivative instruments utilizing “no premium” collars and price swaps to reduce the effect of price changes on a portion of future oil production. The Company’s commodity derivative instruments are measured at fair value and are included in the consolidated balance sheet as derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the loss on commodity derivatives line on the consolidated statements of operations.
| F-11 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
The Company’s valuation estimate takes into consideration the counterparties’ credit worthiness, the Company’s credit worthiness, and the time value of money. The consideration of the factors results in an estimated exit price for each derivative asset or liability under a market place participant’s view. Management believes that this approach provides a reasonable, non-biased, verifiable, and consistent methodology for valuing commodity derivative instruments (see Note 14– Derivative Instruments and Price Risk Management).
New Accounting Pronouncements
From time to time, new accounting pronouncements are issued by FASB that are adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on the Company’s consolidated financial statements upon adoption.
Joint Ventures
The consolidated financial statements as of December 31, 2012, 2011 and 2010 include the accounts of the Company and its proportionate share of the assets, liabilities, and results of operations of the joint ventures it is involved in.
Use of Estimates
The preparation of consolidated financial statements under GAAP in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates relate to proved oil and natural gas reserve volumes, future development costs, estimates relating to certain oil and natural gas revenues and expenses, fair value of derivative instruments, valuation of share-based compensation and the valuation of deferred income taxes. Actual results may differ from those estimates.
Industry Segment and Geographic Information
The Company operates in one industry segment, which is the exploration, development and production of oil and natural gas with all of the Company’s operational activities having been conducted in the U.S. The Company’s current operational activities and the Company’s consolidated revenues are generated from markets exclusively in the U.S., and the Company has no long lived assets located outside the U.S.
Reclassifications
Certain reclassifications have been made to prior periods’ reported amounts in order to conform with the current period presentation. These reclassifications did not impact the Company’s net loss, stockholders’ equity or cash flows.
Change in Reporting Period End
On July 29, 2010, the Company’s Board of Directors approved a change in the Company’s fiscal year end to a traditional calendar year from that of a last Sunday of quarter end period. The change in reporting period has been reflected in this Annual Report on Form 10-K. The Company’s fiscal year end is December 31, and the quarters end on March 31, June 30 and September 30.
Principles of Consolidation
The accompanying consolidated financial statements include the accounts of Emerald Oil, Inc. and its direct and indirect wholly owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
NOTE 3 ACQUISITION OF BUSINESS
On July 9, 2012, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with Emerald Oil & Gas NL (the “Parent”) and Emerald Oil North America, Inc. (“Emerald Oil North America”), a wholly owned subsidiary of the Parent pursuant to which the Company purchased all of the outstanding capital stock of Emerald Oil North America for approximately 19.9% of the total shares of the Company’s common stock outstanding as of the closing date. The Company completed the acquisition of Emerald Oil North America on July 26, 2012 and issued approximately 1.66 million shares to the Parent. The Company assumed Emerald Oil North America’s liabilities, including approximately $20.3 million in debt owed by Emerald Oil North America. The acquisition included approximately 10,600 net acres located in Dunn County, North Dakota and approximately 45,000 net acres in the Sandwash Basin Niobrara shale oil play in northwestern Colorado and southwestern Wyoming.
In connection with the closing of the Emerald Oil North America acquisition, five existing members of the Company’s board of directors resigned, and their vacancies were filled with directors selected by the remaining members of the Company’s board of directors. Also in connection with the closing of the Emerald acquisition, the Company entered into employment agreements with six officers, J.R. Reger (Executive Chairman—formerly Chief Executive Officer), Mike Krzus (Chief Executive Officer), McAndrew Rudisill (President), Paul Wiesner (Chief Financial Officer), Karl Osterbuhr (Vice President of Exploration and Business Development) and Mitchell R. Thompson (Chief Accounting Officer—formerly Chief Financial Officer).
| F-12 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
Emerald Oil North America’s $20.3 million in debt obligations assumed by the Company was comprised of $17.7 million to Hartz Energy Capital, LLC (“Hartz”) and $2.5 million plus accrued interest to Parent. Both were paid in full on September 28, 2012.
Interest on the Hartz credit agreement was in the form of an overriding royalty interest in and to all of the oil, gas and other liquid hydrocarbons produced and saved from certain of the Company’s oil and natural gas properties, free of any and all expenses of development, production, transportation, marketing and any other related or similar expenses. The initial credit agreement included a 2.15% overriding royalty interest on Emerald Oil North America’s properties in the Williston Basin of North Dakota. In accordance with the amended credit agreement, interest on the credit agreement was expanded to include a 0.9% overriding royalty interest in and to all of the oil, gas and other liquid hydrocarbons produced and saved from the Company’s properties in the Green River Basin of Colorado and Wyoming.
The acquisition has been accounted for using the acquisition method. Assets acquired and liabilities assumed were recorded at their estimated fair values as of the acquisition date. The allocation of the purchase price is based upon a valuation of certain assets acquired and liabilities assumed. The Company recorded a gain on the bargain purchase of Emerald Oil North America as a result of the decrease in the Company’s share price between the announcement date (July 10, 2012) and closing date (July 26, 2012) of the acquisition in accordance with GAAP. A summary of the acquisition is below:
| (in thousands) | ||||
| Proved Oil and Natural Gas Properties | $ | 6,839 | ||
| Unproved Oil and Natural Gas Properties | 33,948 | |||
| Other Assets | 111 | |||
| Debt Assumed | (20,303 | ) | ||
| Net Assets Acquired | 20,595 | |||
| Equity Issued to Emerald Oil NL | (13,381 | ) | ||
| Gain on Acquisition | 7,214 | |||
| Less: Acquisition Costs | (1,456 | ) | ||
| Gain on Acquisition, net | $ | 5,758 | ||
Pro Forma Operating Results
From July 26, 2012 to December 31, 2012, the Company recognized $194,417 in revenues and $136,196 of expenses relating to Emerald Oil North America, resulting in net income during the year ended December 31, 2012 of $58,221.
| F-13 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
The following table reflects the unaudited pro forma results of operations as though the acquisition had occurred on January 1, 2011. The pro forma amounts are not necessarily indicative of the results that may be reported in the future:
| Year Ended December 31, | ||||||||
| 2012 | 2011 | |||||||
| Revenues | $ | 27,968,701 | $ | 8,569,107 | ||||
| Net loss | $ | (64,707,199 | ) | $ | (1,977,350 | ) | ||
| Net loss per share – basic and diluted | $ | (4.74 | ) | $ | (0.20 | ) | ||
| Weighted Average Shares Outstanding – Basic and Diluted | 13,639,626 | 9,674,332 | ||||||
NOTE 4 OIL AND NATURAL GAS PROPERTIES
The value of the Company’s oil and natural gas properties consists of all acreage acquisition costs (including cash expenditures and the value of stock consideration), drilling costs and other associated capitalized costs. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in the accompanying consolidated statements of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets based on their estimated fair value at the time of the acquisition. In the past, acquisitions have been funded with internal cash flow and the issuance of equity securities.
Acquisitions
For the year ended December 31, 2012, the Company acquired approximately 12,416 net mineral acres in the Williston Basin targeting the Bakken and Three Forks formations for an average cost of approximately $1,340 per net acre including the acreage acquired as a result of the acquisition of Emerald Oil North America.
The Company also acquired approximately 45,000 net mineral acres in the Sandwash Basin of northwestern Colorado and southwestern Wyoming targeting the Niobrara as a result of the acquisition of Emerald Oil North America (See Note 3 – Acquisition of Business).
On October 5, 2012 the Company acquired 4,453 net acres in McKenzie County, North Dakota for $3,200 per acre from Slawson, under which the Company agreed to acquire certain oil and natural gas leaseholds, and various other related rights, interests, equipment and other assets. The effective time for the transfer of the leases was September 1, 2012. The purchase included operating permits for additional wells and a recently constructed well pad and tank battery at an additional cost of $1.18 million, for a total cash purchase price of $15.4 million.
Sandwash Basin – Niobrara
The Company owns approximately 45,000 net mineral acres in the Sand Wash Basin of the Greater Green River Basin prospective for the Niobrara oil shale and other secondary target formations known to contain oil and natural gas. The assets include certain existing oil and gas wells and a 6-inch diameter natural gas gathering pipeline extending approximately 18.5 miles in length from the Company’s natural gas production facilities located in Moffat County, Colorado, to a Questar pipeline connection located near the town of Baggs in Carbon County, Wyoming. These assets were acquired in conjunction with the acquisition of Emerald Oil North America on July 26, 2012 (see Note 3 – Acquisition of Business).
The assets are governed by a participation agreement (the “Participation Agreement”) with Entek GRB LLC, a subsidiary of Entek Energy Ltd, a publicly traded Australian exploration and production company. Under the Participation Agreement, the Company and Entek have agreed to jointly develop each party’s respective leasehold interests within a designated area of mutual interest, referred to as the Green River Basin AMI. The collective leasehold position consists of 45,000 gross acres in Routt County, Colorado and 67,000 gross acres in Moffat County, Colorado and Carbon County, Wyoming. The collective leasehold interest of the Company and Entek in the Green River Basin AMI is owned 45% by the Company and 55% by Entek, and Entek is the operator of the properties.
| F-14 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
On January 7, 2013, the Company entered into a definitive agreement with East Management Services, LP, under which the Company has agreed to sell its undivided 45% working interest in its leasehold position in Moffat County, Colorado and Carbon County, Wyoming (see Note 16 – Subsequent Events).
Big Snowy Joint Venture
In October 2008, the Company entered into the Big Snowy Joint Venture Agreement with an administrator third-party to acquire certain oil and natural gas leases in the Heath shale oil play in Musselshell, Petroleum, Garfield, Rosebud and Fergus Counties in Montana, and another third party to perform as the operator. Under the terms of the agreement, the Company is responsible for 72.5% of lease acquisition costs, and the other parties are individually responsible for 2.5% and 25% of the lease acquisition costs. Each party controls the same respective working interest on all future production and reserves. The administrator third-party joint venture partner is responsible for coordinating the geology, acquiring the leases in its name, preparing and disseminating assignments, accounting for the project costs and administration of the well operator. The joint venture had accumulated oil and natural gas leases totaling 33,562 net mineral acres as of December 31, 2012. The Company is committed to a minimum of $1,000,000 and a maximum of $1,993,750 toward this joint venture, with all partners, including the Company, committing a minimum of $2,750,000. The administrator third-party joint venture partner issues cash calls during the year to replenish the joint venture cash account. The Company’s contributions to the joint venture totaled $724,744 as of December 31, 2012. The unutilized cash balance was $11,790 as of December 31, 2012.
Niobrara Development with Slawson Exploration Company, Inc.
As of December 31, 2012, the Company held approximately 1,700 net acres in Weld County, Colorado and Laramie County, Wyoming, with 1,440 net acres currently held by production with Slawson Exploration Company, Inc. (“Slawson”). The Company currently has no plans for drilling any additional development wells under this development program during 2012.
Major Joint Venture
In May 2008, the Company entered into the Major Joint Venture Agreement with a third-party partner to acquire certain oil and natural gas leases in the Tiger Ridge Gas Field in Blaine, Hill, and Choteau Counties of Montana. Under the terms of the joint venture agreement, the Company is responsible for all lease acquisition costs. The third-party joint venture partner is responsible for coordinating the geology, acquiring the leases in its name, preparing and disseminating assignments, accounting for the project costs and administration of the well operator.
Tiger Ridge Joint Venture
In November 2009, the Company entered into the Tiger Ridge Joint Venture Agreement with a third-party, Hancock Enterprises, and a well operator, MCR, LLC, to develop and exploit a drilling program in two certain blocks of acreage in the Major Joint Venture, which is an area of mutual interest. The Company controls a 70% working interest, while a third-party investor and the well operator control a 10% working interest and 20% working interest, respectively. The joint venture agreement requires that all parties contribute in cash their proportional share to cover all costs incurred in developing these blocks of acreage for drilling. The Company participated in the drilling of two wells with Devon Energy Corporation, both of which were drilled and shut-in in 2010. The Company conducted 3-D seismic testing throughout 2010 and drilled and completed six exploratory wells in the fourth quarter of 2011 with our joint venture partners. These wells are currently under evaluation for economical production at current natural gas prices.
NOTE 5 RELATED PARTY TRANSACTIONS
On September 22, 2010, Steven Lipscomb and Michael Reger subscribed for $500,000 and $1,000,000 of senior secured promissory notes, respectively. The issuance of the senior secured promissory notes is described in Note 8 to the consolidated financial statements. Mr. Lipscomb is a former director of the Company. Mr. Reger is a brother of J.R. Reger, who is Executive Chairman of the Company and formerly the Chief Executive Officer. The Company’s Audit Committee, which consisted solely of independent directors, reviewed and approved this transaction. The senior secured promissory notes were paid in full on February 10, 2012.
On November 2, 2011, the Company purchased certain leases consisting of approximately 256 net acres in Dunn County, North Dakota for a total purchase price of $768,000. The leases were purchased from Ante5, Inc. (“Seller”), a related party. The Seller and its assets were spun off from the Company and became a separate public reporting U.S. company on June 24, 2010. The Chairman of the Board of the Seller is Bradley Berman, who is the son of a director of the Company and also the beneficial owner of less than five percent of the Company’s outstanding common stock as of December 31, 2012. The Company’s Audit Committee reviewed and approved this transaction prior to its completion. In approving this transaction, the Audit Committee, which consisted solely of independent directors, took into account, among other factors, that due diligence performed by the Company evidenced that the leases were purchased by the Company at the Seller’s original cost per acre and on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances.
| F-15 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
NOTE 6 PREFERRED AND COMMON STOCK
The Company has authorized 20,000,000 shares of preferred stock. No shares of preferred stock were issued as of December 31, 2012 and 2011.
In January 2010, the Company completed a private placement offering of 114,624 shares of common stock to accredited investors at a subscription price of $7.42 per share for total gross proceeds of $847,000. As part of this private placement, the Company entered into an introduction letter agreement with Great North Capital Consultants, Inc. (“Great North”). As compensation for the work performed, Great North received 25,217 shares of restricted common stock of the Company and $67,760 in cash. The fair value of the restricted stock was $186,340 or $7.42 per share, based upon the market value of one share of common stock on the date the transaction closed. These costs were netted against the proceeds of the offering through additional paid-in capital.
On March 10, 2010, the Company purchased leasehold interests from South Fork Exploration, LLC (SFE) for $1,374,375 and 319,229 shares of restricted common stock with a fair value of $2,358,900. SFE’s president was J.R. Reger, Executive Chairman of the Company.
On February 8, 2011, the Company completed a private placement of 1,785,714 units, which consisted of one share of common stock and a warrant to purchase one-half of a share of common stock, at a subscription price of $28.00 per unit for total gross proceeds of $50 million. The exercise price of the warrants is $49.70 per whole share of common stock for a period of five years from the date of closing. The total number of shares that are issuable upon exercise of warrants is 892,857. The Company incurred costs of $3,397,749 related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital.
On September 28, 2012, the Company completed a public offering of 13,392,857 shares of common stock at a price of $5.60 per share for total gross proceeds of $75 million. The Company incurred costs of approximately $5.3 million related to this transaction, which costs were netted against the proceeds of the transaction through additional paid-in capital. The underwriters elected to exercise the over-allotment option to sell an additional 484,698 shares of common stock at $5.60 per share. The gross proceeds from the over-allotment exercise were $2.7 million, and the net proceeds are approximately $2.5 million after deducting underwriting discounts and commissions. The over-allotment exercise closed on October 26, 2012.
Stock Awards and Stock Unit Awards
In March 2012, the Company issued an aggregate of 14,286 shares of common stock to executives of the Company as compensation for their services. The shares were fully vested on the date of the grant. The fair value of the stock issued was approximately $294,000 or $20.58 per share, the market value of a share of common stock on the date the stock was issued. The Company expensed $160,718 in share-based compensation related to these grants in the year ended December 31, 2012. The remainder of the fair value of these grants was capitalized into the full cost pool.
| F-16 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
In March 2012, the Company issued an aggregate 85,714 shares of restricted common stock as compensation to its officers, of which 32,142 restricted shares had vested prior to the acquisition of Emerald Oil North America. The officers forfeited the remaining 53,572 shares of restricted common stock as part of the acquisition of Emerald Oil North America.
In May 2012, the Company issued 2,858 shares of restricted common stock as compensation to an employee, which shares vest equally over two years on May 11, 2013 and May 11, 2014. As of December 31, 2012, there was approximately $29,000 of unrecognized compensation expense related to unvested restricted stock. The Company will recognize compensation expense over the remaining vesting period of the restricted stock grant. The Company has assumed a 0% forfeiture rate for the restricted stock.
In July 2012, the Company issued an aggregate of 35,714 shares of common stock to executives of the Company as compensation for their services. The shares were fully vested on the date of the grant. The fair value of the stock issued was approximately $280,000 or $7.84 per share, the market value of a share of common stock on the date the stock was issued. The Company expensed $265,767 in share-based compensation related to these grants in the year ended December 31, 2012. The remainder of the fair value of these grants was capitalized into the full cost pool.
In July 2012, the Company issued 107,142 restricted stock units as compensation to its officers and certain employees. Unvested restricted stock units vest 35,714 on each of July 26, 2013, 2014 and 2015. As of December 31, 2012, there was approximately $723,000 of unrecognized compensation expense related to unvested restricted stock units. The Company will recognize compensation expense over the remaining vesting period of the restricted stock units. The Company has assumed a 0% forfeiture rate for the restricted stock units.
In November 2012, the Company issued an aggregate of 860,295 shares of common stock to executives of the Company as compensation for their services. The shares were fully vested on the date of the grant. The fair value of the stock issued was approximately $3,504,125 or $4.07 per share, the market value of a share of common stock on the date the stock was issued. The Company expensed $3,504,125 in share-based compensation related to these grants in the year ended December 31, 2012.
In November 2012, the Company issued 1,720,585 restricted stock units as compensation to its officers, directors and certain employees. Unvested restricted stock units vest 860,292 in each November 2013 and 2014. As of December 31, 2012, there was approximately $6,570,215 of unrecognized compensation expense related to the unvested restricted stock units. The Company will recognize compensation expense over the remaining vesting period of the restricted stock units. The Company has assumed a 0% forfeiture rate for the restricted stock units.
On December 17, 2012, the Company issued 51,351 restricted stock units as compensation to an employee. Unvested restricted stock units vest 17,117 on each December 17, 2013, 2014 and 2015. The restricted stock units vesting on December 17, 2014 and 2015 are contingent on the shareholders of the Company approving an amendment to the 2011 Plan for additional shares to be reserved under the Plan. As of December 31, 2012, there was approximately $76,706 of unrecognized compensation expense related to the unvested restricted stock units. The Company will recognize compensation expense over the remaining vesting period of the restricted stock units. The Company has assumed a 0% forfeiture rate for the restricted stock units.
The Company has estimated that $1,196,577 in federal and state withholding taxes is due on restricted stock granted to officers which vested during 2012. Of this amount, the Company estimates that it will be responsible for $62,728, which has been included in general and administrative expenses for the year ended December 31, 2012 with the remaining amount of $1,133,849 recorded as a receivable from officers as of December 31, 2012. The Company’s officers remitted payment on the receivable to the Company in February and March 2013.
The Company incurred compensation expense associated with restricted stock and restricted stock units granted of $4,684,009 and $126,962 for the years ended December 31, 2012 and 2011, respectively. There were 1,847,701 unvested restricted stock units and $7,398,893 associated remaining unrecognized compensation expense as of December 31, 2012 which is expected to be recognized over the weighted-average period of 1.4 years. The Company capitalized compensation expense associated with the restricted stock of $332,673 and $99,358 to oil and natural gas properties for the years ended December 31, 2012 and 2011, respectively.
| F-17 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
NOTE 7 STOCK OPTIONS AND WARRANTS
Stock Options
The total fair value of all stock options granted during the years ended December 31, 2012, 2011 and 2010 were calculated using the Black-Scholes valuation model based on factors present at the time the options were granted.
On April 21, 2010, the Company granted its outside directors stock options to purchase a total of 100,000 shares of common stock exercisable at $19.32 per share. The Company had assumed a 10% forfeiture rate on these options. As of December 31, 2012, 35,714 of these options have been forfeited and 7,146 of these options expired. On July 26, 2012 upon closing the acquisition of Emerald Oil North America, the remaining 57,140 options granted to the former non-employee directors of the Company became fully vested. The vesting of these options is considered a modification under GAAP. The fair value of the options calculated on the modification date was less than the remaining unamortized expense to be reported on the options. The Company expensed the remaining grant date fair value in the year ended December 31, 2012.
On November 12, 2010, the Company granted an outside director stock options to purchase a total of 21,428 shares of common stock exercisable at $25.90 per share. The Company had assumed a 10% forfeiture rate on these options. On July 26, 2012 upon closing the acquisition of Emerald Oil North America, these options became fully vested. The vesting of these options is considered a modification under GAAP. The fair value of the options calculated on the modification date was less than the remaining unamortized expense to be reported on the options. The Company expensed the remaining grant date fair value in the year ended December 31, 2012.
In May 2011, the Company granted stock options to two employees to purchase a total of 14,286 and 7,143 shares of common stock exercisable at $21.14 and $24.85 per share, respectively. The Company has assumed a 10% forfeiture rate on these options. The options vested over one year with all of the options vesting on the anniversary date of the grant.
On May 27, 2011, the Company granted stock options to non-employee directors to purchase a total of 17,855 shares of common stock exercisable at $21.00 per share. The Company had assumed a 10% forfeiture rate on these options. On July 26, 2012 upon closing the acquisition of Emerald Oil North America, these options became fully vested. The vesting of these options is considered a modification under GAAP. The fair value of the options calculated on the modification date was less than the remaining unamortized expense to be reported on the options. The Company expensed the remaining grant date fair value in the year ended December 31, 2012.
On January 6, 2012, the Company granted stock options to an employee to purchase a total of 3,571 shares of common stock exercisable at $18.55 per share. The Company has assumed a 10% forfeiture rate on these options. The options vest on the one year anniversary date of the grant.
On March 30, 2012, the Company granted stock options to an employee to purchase a total of 50,000 shares of common stock exercisable at $17.01 per share. The Company has assumed a 10% forfeiture rate on these options. The options vest on the one year anniversary date of the grant.
On May 23, 2012, the Company granted stock options to an employee to purchase a total of 35,714 shares of common stock exercisable at $12.39 per share. The Company has assumed a 10% forfeiture rate on these options. The options vest over 30 months with 14,286 options vesting on May 23, 2013 and 2014 and 7,142 options vesting on November 23, 2014.
On May 24, 2012, the Company granted stock options to non-employee directors to purchase a total of 17,857 shares of common stock exercisable at $13.30 per share. The Company had assumed a 10% forfeiture rate on these options. On July 26, 2012 upon closing the acquisition of Emerald Oil North America, these options became fully vested. The vesting of these options is considered a modification under GAAP. The fair value of the options calculated on the modification date was less than the remaining unamortized expense to be reported on the options. The Company expensed the remaining grant date fair value in the year ended December 31, 2012.
On July 26, 2012, the Company granted stock options to officers and certain employees to purchase a total of 428,572 shares of common stock exercisable at $7.84 per share. The Company has assumed a forfeiture rate of 0% to 15% on these options. Twenty-five percent, or options to purchase 107,143 shares of common stock, vested immediately on the grant date, and the remaining options vest equally over 36 months with 107,143 options vesting on July 26, 2013 and 2014 and 2015.
On November 15, 2012 the Company granted stock options to certain employees to purchase a total of 150,000 shares of common stock exercisable at $4.43 per share. The options vested immediately on the grant date.
The impact on the Company’s statement of operations of stock-based compensation expense related to options granted for the years ended December 31, 2012, 2011, and 2010 was $2,634,681, $334,520 and $170,219, respectively, net of $0 tax. The Company capitalized $249,367 and $109,688 in compensation to oil and natural gas properties related to outstanding options for the years ended December 31, 2012 and 2011, respectively. No compensation related to outstanding options for the year ended December 31, 2010 was capitalized.
| F-18 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
A summary of options for the years ended December 31, 2012, 2011, and 2010 is as follows:
Number of Options | Weighted Average Exercise Price | Remaining Contractual Term (in Years) |
Intrinsic Value | |||||||||||||
| Outstanding at January 1, 2010 | — | $ | — | — | $ | — | ||||||||||
| Granted | 121,428 | 20.51 | — | — | ||||||||||||
| Pre-Merger ante4, Inc. Options | 38,429 | 17.50 | — | — | ||||||||||||
| Exercised | (5,714 | ) | 4.06 | — | — | |||||||||||
| Forfeited | (14,286 | ) | 19.32 | — | — | |||||||||||
| Outstanding at December 31, 2010 | 139,857 | 20.51 | 8.9 | 2,420,660 | ||||||||||||
| Granted | 39,284 | 22.40 | — | — | ||||||||||||
| Exercised | (571 | ) | 29.68 | — | — | |||||||||||
| Forfeited or Expired | (28,570 | ) | 19.32 | — | — | |||||||||||
| Outstanding at December 31, 2011 | 150,000 | 20.44 | 7.2 | — | ||||||||||||
| Granted | 685,713 | 8.11 | — | — | ||||||||||||
| Exercised | — | — | — | — | ||||||||||||
| Forfeited or Expired | — | — | — | — | ||||||||||||
| Outstanding at December 31, 2012 | 835,713 | $ | 10.43 | 7.7 | $ | — | ||||||||||
| Stock Options Exercisable at December 31, 2010 | 32,714 | $ | 20.02 | 7.0 | $ | 581,660 | ||||||||||
| Stock Options Exercisable at December 31, 2011 | 51,786 | $ | 18.90 | 6.9 | $ | 302,750 | ||||||||||
| Stock Options Exercisable at December 31, 2012 | 424,997 | $ | 11.39 | 5.9 | $ | 121,500 | ||||||||||
For the year ended December 31, 2012, 2011 and 2010, other information pertaining to stock options was as follows:
| 2012 | 2011 | 2010 | ||||||||||
| Weighted-average per share grant-date fair value of stock options granted | $ | 4.62 | $ | 14.35 | $ | 12.95 | ||||||
| Total intrinsic value of options exercised | — | 3,520 | 96,946 | |||||||||
| Total grant-date fair value of stock options vested during the year | 2,159,307 | 349,875 | — | |||||||||
A summary of the status of the Company’s nonvested options as of December 31, 2012 and changes during the year then ended is as follows:
Number of Options | Weighted-Average Grant-Date Fair Value | |||||||
| Nonvested at December 31, 2011 | 98,214 | $ | 13.09 | |||||
| Granted | 685,713 | 4.78 | ||||||
| Vested | (373,211 | ) | 6.14 | |||||
| Forfeited | — | — | ||||||
| Nonvested at December 31, 2012 | 410,716 | $ | 5.87 | |||||
| F-19 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
The following assumptions were used for the Black-Scholes model to value the options granted during the years ended December 31, 2012, 2011 and 2010.
| 2012 | 2011 | 2010 | ||||
| Risk free rates | 0.17% to 1.20% | 0.91% to 0.96% | 1.35% to 2.52% | |||
| Dividend Yield | 0% | 0% | 0% | |||
| Expected volatility | 69.70% to 78.99% | 85.90% to 86.17% | 69.19% to 70.93% | |||
| Weighted average expected life | 4 years | 3 years | 6 years |
All stock options related to the pre-merger entity ante4, Inc. were expensed prior to the merger date, April 16, 2010. ante4, Inc. completed a spin-off of certain assets and liabilities to ante5, Inc. concurrently with the merger. As part of this spin-off, the holders of stock options for ante4, Inc. received an equal number of stock options in ante5, Inc. at an exercise price determined by methodology in accordance with the spin-off distribution agreement. As a result, the exercise prices of the stock options held in Emerald were adjusted to reflect the spin-off. The above table takes into consideration the changes in weighted average exercise price based on a modification as described in ASC 718-20-35-3. The total exercise price adjustment for the options outstanding at December 31, 2010 was $44,470 and the adjustment on shares exercised during 2010 was $1,464.
There was $1,385,207 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted as of December 31, 2012. At December 31, 2012, the remaining cost is expected to be recognized over a weighted-average period of 2.3 years. These estimates are subject to change based on a variety of future events which include, but are not limited to, changes in estimated forfeiture rates, cancellations and the issuance of new options.
Warrants
The impact on the Company’s statement of operations of stock-based compensation expense related to warrants granted for the years ended December 31, 2012, 2011, and 2010 was $0, $267,065 and $483,082, respectively, net of $0 tax. The Company capitalized $209,370 in compensation related to outstanding warrants to oil and natural gas properties for the year ended December 31, 2011.
| F-20 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
A summary of warrants granted to employees, directors and consultants for the years ended December 31, 2012, 2011 and 2010 is as follows:
Number of Warrants | Weighted Average Exercise Price | Remaining Contractual Term (in Years) |
Intrinsic Value | |||||||||||||
| Outstanding at December 31, 2009 | 699,651 | $ | 6.58 | 9.7 | $ | 203,200 | ||||||||||
| Granted | — | — | — | — | ||||||||||||
| Exercised | 476,358 | 6.44 | ||||||||||||||
| Outstanding at December 31, 2010 | 223,293 | 6.86 | 9.5 | 6,908,681 | ||||||||||||
| Granted | — | — | — | — | ||||||||||||
| Exercised | — | — | — | — | ||||||||||||
| Outstanding at December 31, 2011 | 223,293 | 6.86 | 8.0 | 2,458,251 | ||||||||||||
| Granted | — | — | — | — | ||||||||||||
| Exercised | — | — | — | — | ||||||||||||
| Outstanding at December 31, 2012 | 223,293 | $ | 6.86 | 7.0 | $ | — | ||||||||||
On February 8, 2011, in conjunction with the sale of 1,785,714 shares of common stock (see Note 6), the Company issued investors warrants to purchase a total of 892,858 shares of common stock exercisable at $49.70 per share.
For the years ended December 31, 2012, 2011 and 2010, other information pertaining to warrants was as follows:
| 2012 | 2011 | 2010 | ||||||||||
| Weighted-average grant-date fair value of warrants granted | $ | — | $ | 2.02 | $ | — | ||||||
| Total intrinsic value of warrants exercised | $ | — | $ | — | $ | 8,096,977 | ||||||
| Total grant-date fair value of warrants vested during the year | $ | — | $ | 12,625,000 | $ | — | ||||||
The following assumptions were used for the Black-Scholes model to value the warrants granted during the years ended December 31, 2012, 2011 and 2010.
| 2012 | 2011 | 2010 | ||||||||||
| Risk free rates | — | 2.02 | — | |||||||||
| Dividend yield | — | 0 | % | — | ||||||||
| Expected volatility | — | 75.52 | % | — | ||||||||
| Weighted average expected life | — | 5 years | — | |||||||||
The table below reflects the status of warrants outstanding at December 31, 2012:
| Warrants | Exercise Price | Expiration Date | |||||||||
| December 1, 2009 | 37,216 | $ | 6.86 | December 1, 2019 | |||||||
| December 31, 2009 | 186,077 | $ | 6.86 | December 31, 2019 | |||||||
| February 8, 2011 | 892,858 | $ | 49.70 | February 8, 2016 | |||||||
| 1,116,151 | |||||||||||
| F-21 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
NOTE 8 SENIOR SECURED PROMISSORY NOTES
In September 2010, the Company issued senior secured promissory notes in the principal amount of $15 million (the “Notes”) in order to finance future drilling and development activities. Proceeds of the Notes were used primarily to fund developmental drilling on the Company’s significant acreage positions targeting the Williston Basin — Bakken/Three Forks area and the Niobrara formation located in the DJ Basin through the joint venture with Slawson.
The Notes were paid in full on February 10, 2012 in conjunction with the Company entering into a credit facility (“the Macquarie Facility”) with Macquarie Bank Limited (“MBL”) (see Note 9 – Revolving Credit Facility). The remaining unamortized debt issuance costs of $217,809 were written off to interest expense in the year ended December 31, 2012.
NOTE 9 REVOLVING CREDIT FACILITY
On February 10, 2012, the Company entered into a credit facility (the “Macquarie Facility”) with Macquarie Bank Limited (“MBL”). The Macquarie Facility provided up to a maximum of $150 million in principal amount of borrowings to be used as working capital for exploration and production operations. Initially, $15 million of financing was available under the Macquarie Facility based on reserves (Tranche A), with an additional $50 million available under a development tranche (Tranche B).
The borrowing base of funds that were available to the Company under Tranche A was re-determined semi-annually based upon the net present value, discounted at 10% per annum, of the future net revenues expected to accrue from the Company’s interests in proved reserves estimated to be produced from its crude oil and natural gas properties. The Macquarie Facility had a termination date of February 10, 2015. Tranche B was uncommitted, however, MBL could, in its sole discretion and subject to an approved revised development plan and the satisfaction of certain conditions, commit additional funds under Tranche B. Outstanding borrowings, if any, under Tranche B were due in six equal monthly installments beginning on August 10, 2015.
The Company had the option to designate the reference rate of interest for each specific borrowing under the Macquarie Facility as amounts were advanced. Under Tranche A, borrowings that were designated to be based upon the London Interbank Offered Rate (“LIBOR”) would bear interest at a rate equal to LIBOR plus a spread ranging from 2.75% to 3.25%, depending on the percentage of borrowing base that was advanced. Any borrowings not designated LIBOR-based would bear interest at a rate equal to the current prime rate published by the Wall Street Journal plus a spread ranging from 1.75% to 2.25%, depending on the percentage of borrowing base that is currently advanced. The Company had the option to designate either pricing mechanism. The Company’s interest rate on Tranche A was 3.482% when the Macquarie Facility was paid off. Tranche B borrowing would bear interest at a rate equal to LIBOR plus 7.5%. The Company’s interest rate on Tranche B was 7.732% when the Macquarie Facility was paid off. Interest payments were due under the Facility in arrears; in the case of a LIBOR-based loan, on the last day of the specified interest period and in the case of all other loans on the last day of each March, June, September and December. All outstanding principal was due and payable upon termination of the Macquarie Facility.
On July 26, 2012, the Company entered into an amended and restated credit agreement with MBL to expand the existing availability and outstanding balance under its existing Macquarie Facility and drew $15 million of additional debt on a new third tranche at an initial rate of 9% above the applicable LIBOR and had the potential to draw a maximum of $20 million. The $15 million drawn was used for existing development activities and was paid in full with proceeds from the equity offering completed on September 28, 2012.
Upon an event of default, the applicable interest rate under the Macquarie Facility would have increased, and the lenders could have accelerated payments under the Macquarie Facility or call all obligations due under certain circumstances. The Macquarie Facility referenced various events constituting a default, including, but not limited to, failure to pay interest on any loan under the Macquarie Facility, any material violation of any representation or warranty under the Macquarie Facility, failure to observe or perform certain covenants, conditions or agreements under the Macquarie Facility, a change in control of the Company, default under any other material indebtedness of the Company, bankruptcy and similar proceedings and failure to pay disbursements from lines of credit issued under the Macquarie Facility.
The Macquarie Facility required the Company to enter into hedging agreements with MBL for each month of the 36-month period following the date on which each such hedge agreement is executed, the notional volumes for which, when aggregated with other commodity derivative agreements and additional fixed-price physical off-take contracts then in effect are not less than 50%, nor greater than 90%, of the reasonably anticipated projected production from our proved developed producing reserves. The Facility also required the Company to maintain certain financial ratios, including current ratio (at least 1.00 to 1.00), debt coverage ratio (no more than 3.50 to 1.00), interest coverage ratio (at least 2.50 to 1.00) and a ceiling on general and administrative expenses (no more than $500,000 per fiscal quarter, excluding certain non-cash, audit and engineering-related expenses).
| F-22 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
All of the Company’s obligations under the Macquarie Facility and the derivative agreements with MBL were secured by a first priority security interest in any and all of the Company’s assets.
On November 20, 2012, the Company entered into a credit agreement (the “Credit Agreement”) with Wells Fargo Bank, N.A. (“Wells Fargo”), as administrative agent, and the lenders party thereto. The Credit Agreement is a senior secured reserve-based revolving credit facility with a maximum commitment of $400 million and an initial borrowing base of $27.5 million (the “Wells Fargo Facility”). The Macquarie Facility was paid in full on November 20, 2012. The remaining unamortized debt issuance costs of $389,333 related to the Macquarie Facility were written off to interest expense in the year ended December 31, 2012.
Amounts borrowed under the Wells Fargo Facility will mature on November 20, 2017, and upon such date, any amounts outstanding under the Facility are due and payable. Redeterminations of the borrowing base will be on a semi-annual basis, with an option to elect an additional redetermination every six months between the semi-annual redeterminations.
The annual interest cost, which is dependent upon the percentage of the borrowing base utilized, is, at the Company’s option, based on either the Alternate Base Rate (as defined in the Credit Agreement) plus 0.75% to 1.75% or the London Interbank Offer Rate (LIBOR) plus 1.75% to 2.75%; provided, in no event may the interest exceed the maximum interest rate allowed by any current or future law. As of December 31, 2012, the annual interest rate on the Wells Fargo Facility was 2.81%, which is based on LIBOR plus 2.25%. Interest on ABR Loans is due and payable on a quarterly basis, and interest on Eurodollar Loans is due and payable, at the Company’s option, at one-, two-, three-, six- (or in some cases nine- or twelve-) month intervals. The Company will also pay a commitment fee ranging from 0.375% to 0.5%, depending on the percentage of the borrowing base utilized.
A portion of the Wells Fargo Facility not in excess of $5 million will be available for the issuance of letters of credit by Wells Fargo. The Company will pay a rate per annum ranging from 1.75% to 2.75% on the face amount of each letter of credit issued and will pay a fronting fee equal to the greater of $500 and 0.125% of the face amount of each letter of credit issued. The Company did not obtain any letters of credit under the Wells Fargo Facility in 2012.
Each of the Company’s subsidiaries is a guarantor under the Wells Fargo Facility. The Wells Fargo Facility is secured by first priority, perfected liens and security interests on substantially all assets of the Company and the guarantors, including a pledge of their ownership in their respective subsidiaries.
The Credit Agreement contains customary covenants that include among other things, limitations on the ability of the Company to incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; make certain types of investments; enter into transactions with affiliates; and sell assets or merge with other companies. The Credit Agreement also requires compliance with certain financial covenants, including, (a) a ratio of current assets to current liabilities of at least 1.00 to 1.00, (b) a maximum ratio of debt to EBITDA for the preceding four fiscal quarters of no more than 3.50 to 1.00, and (c) a fixed charge coverage ratio for any four fiscal quarters of at least 3.00 to 1.00. The Company was not in compliance with the current ratio covenant as of December 31, 2012, and a waiver was obtained from Wells Fargo.
The Company had $4.0 million available under the Wells Fargo Facility as of December 31, 2012. The principal balance amount on the Credit Agreement was $23.5 million at December 31, 2012
| F-23 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
NOTE 10 ASSET RETIREMENT OBLIGATION
The Company has asset retirement obligations associated with the future plugging and abandonment of its proved oil and natural gas properties and related facilities. Under the provisions of ASC 410-20-25, the fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long lived asset. The liability is accreted to its present value each period, and the capitalized cost is depleted using the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. The fair value of additions to the asset retirement obligations is estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plug and abandon costs per well based on existing regulatory requirements; (ii) remaining life per well; (iii) future inflation factors (2.5% for each of the years in the three-year period ended December 31, 2012); and (iv) a credit-adjusted risk-free interest rate (average of 7.0% for each of the years in the three-year period ended December 31, 2012). These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The Company has no assets that are legally restricted for purposes of settling asset retirement obligations.
The following table summarizes the Company’s asset retirement obligation transactions recorded in accordance with the provisions of ASC 410-20-25 for the years ended December 31, 2012 and 2011:
| 2012 | 2011 | |||||||
| Beginning Asset Retirement Obligation | $ | 116,119 | $ | 10,522 | ||||
| Liabilities Incurred or Acquired | 164,967 | 100,715 | ||||||
| Accretion of Discount on Asset Retirement Obligations | 14,988 | 4,882 | ||||||
| Ending Asset Retirement Obligation | $ | 296,074 | $ | 116,119 | ||||
NOTE 11 INCOME TAXES
The Company utilizes the asset and liability approach to measuring deferred tax assets and liabilities based on temporary differences existing at each balance sheet date using currently enacted tax rates in accordance with ASC 740-10-30. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment.
The income tax expense (benefit) for the year ended December 31, 2012, 2011, and 2010 consists of the following:
| 2012 | 2011 | 2010 | ||||||||||
| Current Income Taxes | $ | — | $ | — | $ | 65,240 | ||||||
| Deferred Income Taxes | ||||||||||||
| Federal | — | — | — | |||||||||
| State | — | — | — | |||||||||
| Total Expense | $ | — | $ | — | $ | 65,240 | ||||||
| F-24 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
The following is a reconciliation of the reported amount of income tax expense (benefit) for the years ended December 31, 2012, 2011 and 2010 to the amount of income tax expenses that would result from applying the statutory rate to pretax income.
Reconciliation of reported amount of income tax expense:
| 2012 | 2011 | 2010 | ||||||||||
| Loss Before Taxes | $ | (62,296,099 | ) | $ | (1,354,054 | ) | $ | (4,203,329 | ) | |||
| Federal Statutory Rate | 35 | % | 35 | % | 34 | % | ||||||
| Benefit Computed at Federal Statutory Rates | (21,803,635 | ) | (473,919 | ) | (1,429,132 | ) | ||||||
| State Benefit, Net of Federal Benefit | (1,969,364 | ) | (68,416 | ) | (157,760 | ) | ||||||
| Effects of: | ||||||||||||
| Nondeductible expenses | 10,941 | — | — | |||||||||
| Other | (119,872 | ) | 48,919 | 4,132 | ||||||||
| Nondeductible Merger Costs Paid | — | — | 283,000 | |||||||||
| Merger with ante4, Inc. | — | — | (195,000 | ) | ||||||||
| Change in Valuation Allowance | 23,881,930 | 493,416 | 1,560,000 | |||||||||
| Reported Provision | $ | — | $ | — | $ | 65,240 | ||||||
The components of the Company’s deferred tax asset were as follows:
| Year Ended December 31, | ||||||||
| 2012 | 2011 | |||||||
| Deferred Tax Assets | ||||||||
| Current: | ||||||||
| Share Based Compensation | $ | 1,672,296 | $ | 455,000 | ||||
| Derivatives | 78,027 | — | ||||||
| Other | — | 28,550 | ||||||
| Current | 1,750,323 | 483,550 | ||||||
| Non-Current: | ||||||||
| Net Operating Loss Carryforwards (NOLs) | 19,654,346 | 14,022,924 | ||||||
| Equity Investments | 116,488 | — | ||||||
| Derivatives | (9,589 | ) | — | |||||
| Oil and Natural Gas Properties | 6,522,543 | (11,698,388 | ) | |||||
| Other | (9,491 | ) | — | |||||
| Non-Current | 26,274,297 | 2,324,536 | ||||||
| Total Deferred Tax Assets | 28,024,620 | 2,808,086 | ||||||
| Less: Valuation Allowance | (28,024,620 | ) | (2,808,086 | ) | ||||
| Net Deferred Tax Asset | $ | — | $ | — | ||||
| F-25 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
At December 31, 2012, the Company has U.S. Federal net operating loss (NOL) carryovers of $58,142,000, which expire at various dates from 2029 through 2032. In addition, the Company has state NOL carryovers of approximately $50,712,000. During 2012, the Company had a IRC Section 382 change of ownership which may restrict its ability to utilize its NOL carryovers. Valuation allowances of $28,025,000 and $2,808,000 have been established to offset the Company's net deferred tax assets as of December 31, 2012 and December 31, 2011, respectively, as the realization of these deferred tax assets is not more likely than not.
Tax benefits are recognized only for tax positions that are more likely than not to be sustained upon examination by tax authorities. The amount recognized is measured as the largest amount of benefit that is greater than 50 percent likely to be realized upon ultimate settlement. Unrecognized tax benefits are tax benefits claimed in the Company's tax returns that do not meet these recognition and measurement standards. The Company has no liabilities for unrecognized tax benefits.
The Company's policy is to recognize potential interest and penalties accrued related to unrecognized tax benefits within income tax expenses. For the years ended December 31, 2012, 2011 and 2010, the Company did not recognize any interest or penalties in its statement of operations, nor did it have any interest or penalties accrued in its balance sheet at December 31, 2012 and 2011 relating to unrecognized benefits.
The tax years 2009 through 2012 remain open to examination for U.S. federal income tax purposes. The Company files tax returns with various state taxing authorities and these returns remain open to examination for the tax years 2008 through 2012.
NOTE 12 FAIR VALUE
ASC 820-10-55 defines fair value, establishes a framework for measuring fair value under GAAP and enhances disclosures about fair value measurements. Fair value is defined under ASC 820-10-55 as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The standard describes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value which are the following:
Level 1 – Unadjusted quoted prices in active markets that are accessible at measurement date for identical assets or liabilities.
Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities; quoted prices in markets that are not active; or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities and less observable from objective sources.
The following schedule summarizes the valuation of financial instruments measured at fair value on a recurring basis in the consolidated balance sheet as of December 31, 2012:
| Fair Value Measurements at December 31, 2012 Using | ||||||||||||
| Quoted Prices In Active Markets for Identical Assets (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) | ||||||||||
| Commodity Derivatives – Current Liability (oil swaps and collars) | $ | — | $ | (206,645 | ) | $ | — | |||||
| Commodity Derivatives – Long Term Asset (oil swaps and collars) | — | 25,397 | — | |||||||||
| Total | $ | — | $ | (181,248 | ) | $ | — | |||||
There were no financial instruments measured at fair value on a recurring basis as of December 31, 2011.
| F-26 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
Level 2 assets consist of commodity derivative assets and liabilities (See Note 14 – Derivative Instruments and Price Risk Management). The fair value of the commodity derivative assets and liabilities are estimated by the Company by utilizing an option pricing model which takes into account notional quantities, market volatility, market prices, contract parameters and discount rates based on published LIBOR rates. The Company validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings, public bond yield spreads and credit default swap spreads, are applied to the Company’s commodity derivatives. Significant changes in the quoted forward prices for commodities and changes in market volatility generally leads to corresponding changes in the fair value measurement of our oil derivative contracts. The fair value of all derivative contracts is reflected on the consolidated balance sheet.
NOTE 13 FINANCIAL INSTRUMENTS
The Company’s non-derivative financial instruments include cash and cash equivalents, accounts receivable, accounts payable and the revolving credit facility. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximate fair value because of their immediate or short-term maturities. The book value of the revolving credit facility approximates fair value because of its floating rate structure. The Company has classified the credit facility as a Level 2 item with the fair value hierarchy.
NOTE 14 DERIVATIVE INSTRUMENTS AND PRICE RISK MANAGEMENT
The Company utilizes commodity swap contracts and costless collars (purchased put options and written call options) to (i) reduce the effects of volatility in price changes on the oil commodities it produces and sells, (ii) reduce commodity price risk and (iii) provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending.
All derivative positions are carried at their fair value on the consolidated balance sheet and are marked-to-market at the end of each period. Both the unrealized and realized gains and losses resulting from the contract settlement of derivatives are recorded in the loss on commodity derivatives line on the consolidated statement of operations.
The Company has a master netting agreement on each of the individual oil contracts and therefore the current asset and liability are netted on the consolidated balance sheet and the non-current asset and liability are netted on the consolidated balance sheet.
The Company realized a loss on settled derivatives of $34,191 and an unrealized loss on mark-to-market of derivatives instruments of $181,248 for the year ended December 31, 2012. The Company did not enter into derivative instruments prior to 2012.
The following table reflects open commodity swap contracts as of December 31, 2012, the associated volumes and the corresponding weighted average NYMEX reference price.
Settlement Period |
Oil (Barrels) |
Fixed Price | Weighted Avg NYMEX Reference Price | |||||||||
| Oil Swaps | ||||||||||||
| January 1, 2013 - December 31, 2013 | 73,370 | $ | 88.00 | $ | 92.70 | |||||||
| January 1, 2014 – December 31, 2014 | 48,742 | $ | 88.00 | $ | 92.70 | |||||||
| January 1, 2015 – February 28, 2015 | 6,404 | $ | 88.00 | $ | 92.70 | |||||||
| Total | 128,516 | |||||||||||
Costless collars are used to establish floor and ceiling prices on anticipated oil production. There were no premiums paid or received by the Company related to the costless collar agreements. The following table reflects open costless collar agreements as of December 31, 2012.
| Term | Oil (Barrels) | Price | Basis | ||||||||
| Costless Collars | |||||||||||
| January 1, 2013 – December 31, 2013 | 73,389 | $ | 90.00–$103.50 | NYMEX | |||||||
| January 1, 2014 – December 31, 2014 | 54,525 | $ | 90.00–$103.50 | NYMEX | |||||||
| January 1, 2015 – February 28, 2015 | 7,472 | $ | 90.00–$103.50 | NYMEX | |||||||
| Total | 135,386 | ||||||||||
| F-27 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
At December 31, 2012, the Company had derivative financial instruments recorded on the consolidated balance sheet as set forth below:
| Type of Contract | Balance Sheet Location | |||||
| Derivative Assets: | ||||||
| Costless Collars | Non-current assets | 630,441 | ||||
| Costless Collars | Non-current liabilities | (382,872 | ) | |||
| Swap Contracts | Non-current liabilities | (222,172 | ) | |||
| Total Derivative Assets | $ | 25,397 | ||||
| Derivative Liabilities: | ||||||
| Costless Collars | Current liabilities | $ | (194,810 | ) | ||
| Costless Collars | Current assets | $ | 365,679 | |||
| Swap Contracts | Current liabilities | (377,514 | ) | |||
| Total Derivative Liabilities | $ | (206,645 | ) | |||
| Net Derivative Position | $ | (181,248 | ) | |||
The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The Company has netting arrangements with Wells Fargo Bank, N.A. that provide for offsetting payables against receivables from separate derivative instruments.
On January 4, 2013, the Company executed a NYMEX West Texas Intermediate oil derivative swap contract that unwound the swap and collar contracts and combined the swap and collar contracts into a single swap contract (see Note 16 – Subsequent Events).
NOTE 15 COMMITMENTS AND CONTINGENCIES
We are subject to litigation claims and governmental and regulatory proceedings arising in the ordinary course of business. We believe that all such litigation matters are not likely to have a material adverse effect on the Company’s financial position, cash flows or results of operations
NOTE 16 SUBSEQUENT EVENTS
Sand Wash Basin Sale
On January 7, 2013, the Company entered into a definitive agreement with East Management Services, LP (“East”), under which the Company has agreed to sell its undivided 45% working interest in and to certain oil and natural gas leaseholds in the Sand Wash Basin, comprising approximately 30,902 net acres of the Company’s 45,800 net acres located in Routt and Moffatt Counties, Colorado and Carbon County, Wyoming. The effective time for the transfer of the leases will be the date of closing. The closing of the transaction is expected to occur during the first quarter of 2013, subject to the satisfaction of customary closing conditions and the condition that East and Entek GRB, LLC enter into and timely perform an agreement by which East acquires Entek’s interest in the certain oil and gas leaseholds.
The aggregate estimated sales price is approximately $10.0 million, subject to adjustment for certain title defects and title benefits and for leases with a primary term expiring on or before June 30, 2013 that cannot be renewed or extended. The Company is currently determining the appropriate sales allocation for this transaction. The agreement may be terminated (i) by mutual agreement of the parties; (ii) by East if certain representations by the Company regarding overriding royalty interests or working interests are not true; (iii) by East if during the 45-day period following execution of the Agreement, title defects exceed 5% of the net acres of the certain oil and gas leaseholds; (iv) by East if there are any environmental claims against the Company that might result in a material adverse effect on the certain oil and natural gas leaseholds, or (v) by either party if East is unable to acquire Entek’s interest in the certain oil and natural gas leaseholds.
| F-28 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
Acreage Acquisitions
On January 9, 2013, the Company entered into a purchase and sale agreement with a third party pursuant to which the Company acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $4.7 million purchase price of the acquired leases, the Company issued 851,315 shares of its common stock at a per share value of $5.50 per share, based on the five-day trading volume-weighted average price of the Company’s common stock prior to closing. The Company issued the shares of common stock in reliance upon an exemption from the registration requirements under the Securities Act of 1933, as amended, provided by Section 4(2) thereof. The Company is currently determining the appropriate purchase price allocation for this transaction. Under the terms of each purchase and sale agreement, the Company agreed to register the shares issued to each respective seller for resale from time to time.
On February 4, 2013, the Company entered into a purchase and sale agreement with a third party pursuant to which the Company acquired leases of oil and natural gas properties in McKenzie County, North Dakota. Pursuant to the purchase and sale agreement and as consideration for the approximate $1.9 million purchase price of the acquired leases, the Company issued 313,700 shares of its common stock at a per share value of $6.058 per share, based on the five-day trading volume-weighted average price of the Company’s common stock prior to closing. The Company issued the shares of common stock in reliance upon an exemption from the registration requirements under the Securities Act of 1933, as amended, provided by Section 4(2) thereof. The Company is currently determining the appropriate purchase price allocation for this transaction. Under the terms of each purchase and sale agreement, the Company agreed to register the shares issued to each respective seller for resale from time to time.
White Deer Energy Securities Purchase Agreement
On February 1, 2013, the Company entered into a securities purchase agreement with WDE Emerald Holdings LLC, a Delaware limited liability company, and White Deer Energy FI L.P., a Cayman Islands exempted limited partnership, pursuant to which, in exchange for a cash investment of $50 million, the Company issued to the Investors the following (collectively, the “Investment”):
| · | 500,000 shares of a new Series A Perpetual Preferred Stock, $0.001 par value per share (the “Series A Preferred Stock”); |
| · | 5,114,633 shares of a new Series B Voting Preferred Stock, $0.001 par value per share (the “Series B Preferred Stock”); and |
| · | warrants to purchase an initial aggregate amount of 5,114,633 shares of the Company’s common stock, $0.001 par value per share (the “Common Stock”), at an initial exercise price of $5.77 per share. |
The Series A Preferred Stock, the Series B Preferred Stock and the warrants are referred to herein as the “Securities.” The warrants will entitle the holders thereof to acquire a number of shares of Common Stock equal to approximately 19.75% of the shares of Common Stock outstanding as of February 19, 2013, or approximately 16.49% of the Company’s outstanding Common Stock on a diluted basis taking into account the exercise of the warrants. The Company is currently evaluating the accounting for the issuance of the preferred stock and related warrants to determine whether equity and/or liability treatment is required.
Prior to April 1, 2015, the Company may pay dividends on the outstanding shares of Series A Preferred Stock either in cash or by issuance of additional shares of Series A Preferred Stock valued at the volume-weighted average trading price of the Common Stock for the ten consecutive trading days preceding the dividend payment date and an additional warrant to purchase shares of Common Stock at an exercise price equal to such volume-weighted average price; provided that such dividends must be paid in cash unless and until the Company’s shareholders vote to approve the issuance of any warrants and any shares of Common Stock issuable upon exercise of such warrants.
Derivative Instruments
On January 4, 2013, the Company executed the following NYMEX West Texas Intermediate oil derivative swap contract that unwound the swap and collar contracts disclosed in Note 14 - Derivative Instruments and Price Risk Management above and combined the swap and collar contracts into a single swap contract as indicated below:
Settlement Period |
Oil (Barrels) |
Fixed Price | Weighted Avg NYMEX Reference Price | |||||||||
| Oil Swaps | ||||||||||||
| January 1, 2013 - December 31, 2013 | 146,759 | $ | 91.00 | $ | 93.12 | |||||||
| January 1, 2014 – December 31, 2014 | 103,267 | $ | 91.00 | $ | 93.12 | |||||||
| January 1, 2015 – February 28, 2015 | 13,876 | $ | 91.00 | $ | 93.12 | |||||||
| Total | 263,902 | |||||||||||
| F-29 |
EMERALD OIL, INC.
(FORMERLY VOYAGER OIL & GAS, INC.)
Notes to Consolidated Financial Statements
NOTE 17 QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Quarterly data for the years ended December 31, 2012 and 2011 are as follows:
| Quarter Ended | ||||||||||||||||
| March 31, | June 30, | September 30, | December 31, | |||||||||||||
| 2012 | ||||||||||||||||
| Revenue | $ | 4,185,898 | $ | 9,014,972 | $ | 5,476,134 | $ | 9,237,542 | ||||||||
| Expenses | 3,926,478 | 15,806,435 | 2,065,334 | 65,769,914 | ||||||||||||
| Income (Loss) from Operations | 259,420 | (6,791,463 | ) | 3,410,800 | (56,532,372 | ) | ||||||||||
| Other Income (Expense), Net | (515,790 | ) | (169,445 | ) | (1,415,958 | ) | (541,291 | ) | ||||||||
| Net Income (Loss) | $ | (256,370 | ) | $ | (6,960,908 | ) | $ | 1,994,842 | $ | (57,073,663 | ) | |||||
| Net Loss Per Common Share – Basic and diluted | $ | (0.00 | ) | $ | (0.12 | ) | $ | 0.20 | $ | (2.36 | ) | |||||
| Quarter Ended | ||||||||||||||||
| March 31, | June 30, | September 30, | December 31, | |||||||||||||
| 2011 | ||||||||||||||||
| Revenue | $ | 832,621 | $ | 1,666,535 | $ | 2,872,674 | $ | 3,054,299 | ||||||||
| Expenses | 1,233,288 | 1,592,166 | 2,310,151 | 2,577,136 | ||||||||||||
| Income (Loss) from Operations | (400,667 | ) | 74,369 | 562,523 | 477,163 | |||||||||||
| Other Income (Expense), Net | (489,107 | ) | (539,426 | ) | (506,649 | ) | (523,260 | ) | ||||||||
| Net Income (Loss) | $ | (889,774 | ) | $ | (465,057 | ) | $ | 55,874 | $ | (46,097 | ) | |||||
| Net Loss Per Common Share – Basic and diluted | $ | (0.12 | ) | $ | (0.06 | ) | $ | 0.01 | $ | (0.01 | ) | |||||
| F-30 |
SUPPLEMENTAL OIL AND NATURAL
GAS INFORMATION
(UNAUDITED)
Oil and Natural Gas Exploration and Production Activities
Oil and natural gas sales reflect the market prices of net production sold or transferred with appropriate adjustments for royalties, net profits interest, and other contractual provisions. Production expenses include lifting costs incurred to operate and maintain productive wells and related equipment including such costs as operating labor, repairs and maintenance, materials, supplies and fuel consumed. Production taxes include production and severance taxes. Depletion of oil and natural gas properties relates to capitalized costs incurred in acquisition, exploration, and development activities. Results of operations do not include interest expense and general corporate amounts. The results of operations for the Company’s oil and natural gas production activities are provided in the Company’s related statements of operations.
Costs Incurred and Capitalized Costs
The costs incurred in oil and natural gas acquisition, exploration and development activities follow:
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Costs Incurred for the Year: | ||||||||||||
| Proved Property Acquisition | $ | 7,799,945 | $ | — | $ | — | ||||||
| Unproved Property Acquisition | 54,917,350 | 18,351,743 | 22,886,390 | |||||||||
| Exploration Costs | 1,939,440 | 251,566 | 1,358,867 | |||||||||
| Development | 71,811,058 | 36,125,604 | 9,154,054 | |||||||||
| Total | $ | 136,467,793 | $ | 54,728,913 | $ | 33,399,311 | ||||||
Excluded costs for unproved properties are accumulated by year. Costs are reflected in the full cost pool as the drilling costs are incurred or as costs are evaluated and deemed impaired. The Company anticipates these excluded costs will be included in the depletion computation over the next five years. The Company is unable to predict the future impact on depletion rates. The following is a summary of capitalized costs excluded from depletion at December 31, 2012 by year incurred.
| Year Ended December 31, | ||||||||||||||||||||
| Total | 2012 | 2011 | 2010 | Prior Years | ||||||||||||||||
| Property Acquisition | $ | 55,127,107 | $ | 34,486,397 | $ | 9,712,705 | $ | 8,402,218 | $ | 2,525,787 | ||||||||||
| Exploration | 3,549,873 | 1,939,440 | 251,565 | 1,358,868 | — | |||||||||||||||
| Drilling | 2,777,851 | 1,973,696 | 642,225 | 161,930 | — | |||||||||||||||
| Total | $ | 61,454,831 | $ | 38,399,533 | $ | 10,606,495 | $ | 9,923,016 | $ | 2,525,787 | ||||||||||
Oil and Natural Gas Reserves and Related Financial Data
Information with respect to the Company’s oil and natural gas producing activities is presented in the following tables. Reserve quantities, as well as certain information regarding future production and discounted cash flows, were determined by Pressler Petroleum Consultants, Inc. and audited by Netherland Sewell & Associates, Inc.
Oil and Natural Gas Reserve Data
The following tables present the Company’s estimates of its proved oil and natural gas reserves. The Company emphasizes that reserves are approximations and are expected to change as additional information becomes available. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
| F-31 |
| Natural Gas (MCF) | Oil (BLS) | |||||||
| Proved Developed and Undeveloped Reserves at December 31, 2009 | — | — | ||||||
| Revisions of Previous Estimates | 187,130 | 354,757 | ||||||
| Production | (3,489 | ) | (13,198 | ) | ||||
| Proved Developed and Undeveloped Reserves at December 31, 2010 | 183,641 | 341,559 | ||||||
| Revisions of Previous Estimates | 21,651 | 104,077 | ||||||
| Extensions, Discoveries and Other Additions | 1,548,713 | 2,876,902 | ||||||
| Production | (14,962 | ) | (95,517 | ) | ||||
| Proved Developed and Undeveloped Reserves at December 31, 2011 | 1,739,043 | 3,227,021 | ||||||
| Revisions of Previous Estimates | (1,225,387 | ) | (2,738,676 | ) | ||||
| Extensions, Discoveries and Other Additions | 841,310 | 1,808,282 | ||||||
| Acquisition of Reserves | 1,680,618 | 2,892,866 | ||||||
| Production | (127,091 | ) | (320,147 | ) | ||||
| Proved Developed and Undeveloped Reserves at December 31, 2012 | 2,908,493 | 4,869,346 | ||||||
| Proved Developed Reserves: | ||||||||
| Proved Developed Reserves at December 31, 2009 | — | — | ||||||
| Proved Developed Reserves at December 31, 2010 | 35,573 | 94,783 | ||||||
| Proved Developed Reserves at December 31, 2011 | 410,092 | 1,066,504 | ||||||
| Proved Developed Reserves at December 31, 2012 | 1,014,158 | 1,788,230 | ||||||
| Proved Undeveloped Reserves: | ||||||||
| Proved Undeveloped Reserves at December 31, 2009 | — | — | ||||||
| Proved Undeveloped Reserves at December 31, 2010 | 148,067 | 246,776 | ||||||
| Proved Undeveloped Reserves at December 31, 2011 | 1,328,953 | 2,160,518 | ||||||
| Proved Undeveloped Reserves at December 31, 2012 | 1,894,335 | 3,081,116 |
Proved reserves are estimated quantities of oil and natural gas, which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are included for reserves for which there is a high degree of confidence in their recoverability and they are scheduled to be drilled within the next five years.
Standardized Measure of Discounted Future Net Cash Inflows and Changes Therein
The following table presents a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves and the changes in standardized measure of discounted future net cash flows relating to proved oil and natural gas were prepared in accordance with the provisions of ASC 932-235-555. Future cash inflows were computed by applying average prices of oil and natural gas for the last 12 months as of December 31, 2012 to estimated future production. Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Future income tax expenses were calculated by applying appropriate year-end tax rates to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities. Future net cash flows are discounted at the rate of 10% annually to derive the standardized measure of discounted future cash flows. Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves.
| F-32 |
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Future Cash Inflows | $ | 432,483,781 | $ | 297,627,312 | $ | 24,430,880 | ||||||
| Future Production Costs | (135,774,945 | ) | (78,513,840 | ) | (6,183,310 | ) | ||||||
| Future Development Costs | (93,833,711 | ) | (65,608,984 | ) | (8,643,951 | ) | ||||||
| Future Income Taxes | (12,157,129 | ) | — | — | ||||||||
| Future Net Cash Inflows | 190,717,996 | 153,504,488 | 9,603,619 | |||||||||
| 10% Annual Discount for Estimated Timing of Cash Flows | (105,433,212 | ) | (93,879,486 | ) | (4,828,213 | ) | ||||||
| Standardized Measure of Discounted Future Net Cash Flows | $ | 85,284,784 | $ | 59,625,002 | $ | 4,775,406 | ||||||
The twelve month average prices for the year ended December 31, 2012 was adjusted to reflect applicable transportation and quality differentials on a well-by-well basis to arrive at realized sales prices used to estimate the Company’s reserves. The prices for the Company’s reserve estimates were as follows:
| Natural Gas MCF | Oil Bbl | |||||||
| December 31, 2012 | $ | 5.13 | $ | 85.75 | ||||
| December 31, 2011 | $ | 6.34 | $ | 88.81 | ||||
| December 31, 2010 | $ | 4.05 | $ | 69.35 | ||||
Changes in the future net cash inflows discounted at 10% per annum follow:
| Year Ended December 31, | ||||||||||||
| 2012 | 2011 | 2010 | ||||||||||
| Beginning of Period | $ | 59,625,002 | $ | 4,775,406 | $ | — | ||||||
| Sales of Oil and Natural Gas Produced, Net of Production Costs | (22,447,837 | ) | (6,981,743 | ) | (813,411 | ) | ||||||
| Extensions and Discoveries | 38,895,353 | 45,912,799 | 5,588,817 | |||||||||
| Previously Estimated Development Cost Incurred During the Period | 11,482,616 | 7,959,195 | — | |||||||||
| Net Change of Prices and Production Costs | (3,003,652 | ) | 6,349,467 | — | ||||||||
| Change in Future Development Costs | (13,726,678 | ) | (197,986 | ) | — | |||||||
| Revisions of Quantity and Timing Estimates | (30,431,352 | ) | 1,079,350 | — | ||||||||
| Accretion of Discount | 5,962,520 | 477,541 | — | |||||||||
| Change in Income Taxes | (2,534,578 | ) | — | — | ||||||||
| Purchase of Reserves in Place | 31,348,048 | — | — | |||||||||
| Changes in timing and other | 10,115,342 | 250,973 | — | |||||||||
| $ | 85,284,784 | $ | 59,625,002 | $ | 4,775,406 | |||||||
| F-33 |