10-K 1 besv_10k.htm ANNUAL REPORT besv_10k.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
  
FORM 10-K
 
þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2012
 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934
 
For the transition period from              to
 
Commission file number: 000-53725
 
PEDEVCO Corp.
(Exact Name of Registrant as Specified in Its Charter)
 
Texas
 
22-3755993
(State or other jurisdiction of incorporation or organization)
 
(IRS Employer Identification No.)
 
4125 Blackhawk Plaza Circle, Suite 201
Danville, California 94506
(Address of Principal Executive Offices)
 
(855) 733-3826
(Registrant’s Telephone Number,
Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:
None
 
Securities registered pursuant to Section 12(g) of the Act:
  Common Stock, $0.001 par value per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ
 
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 þ 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 þ No ¨
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the 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. þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer o Accelerated filer o
Non-accelerated filer o Smaller reporting company þ
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 29, 2012 based upon the closing price reported on such date was approximately $3,364,034. Shares of voting stock held by each officer and director and by each person who, as of June 29, 2012, may be deemed to have beneficially owned more than 10% of the outstanding voting stock have been excluded. This determination of affiliate status is not necessarily a conclusive determination of affiliate status for any other purpose.
 
APPLICABLE ONLY TO ISSUERS INVOLVED IN BANKRUPTCY
PROCEEDINGS DURING THE PRECEDING FIVE YEARS:

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.  Yes   ¨ No   ¨

As of March 22, 2013, 42,102,852 shares of the registrant’s common stock, $.001 par value per share, were outstanding
 


 
 

 

 
   
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Forward Looking Statements

ALL STATEMENTS IN THIS DISCUSSION THAT ARE NOT HISTORICAL ARE FORWARD-LOOKING STATEMENTS. STATEMENTS PRECEDED BY, FOLLOWED BY OR THAT OTHERWISE INCLUDE THE WORDS "BELIEVES," "EXPECTS," "ANTICIPATES," "INTENDS,” "PROJECTS," "ESTIMATES,” "PLANS," "MAY INCREASE," "MAY FLUCTUATE" AND SIMILAR EXPRESSIONS OR FUTURE OR CONDITIONAL VERBS SUCH AS "SHOULD", "WOULD", "MAY" AND "COULD" ARE GENERALLY FORWARD-LOOKING IN NATURE AND NOT HISTORICAL FACTS. THESE FORWARD-LOOKING STATEMENTS WERE BASED ON VARIOUS FACTORS AND WERE DERIVED UTILIZING NUMEROUS IMPORTANT ASSUMPTIONS AND OTHER IMPORTANT FACTORS THAT COULD CAUSE ACTUAL RESULTS TO DIFFER MATERIALLY FROM THOSE IN THE FORWARD-LOOKING STATEMENTS. FORWARD-LOOKING STATEMENTS INCLUDE THE INFORMATION CONCERNING OUR FUTURE FINANCIAL PERFORMANCE, BUSINESS STRATEGY, PROJECTED PLANS AND OBJECTIVES. THESE FACTORS INCLUDE, AMONG OTHERS, THE FACTORS SET FORTH BELOW UNDER THE HEADING "RISK FACTORS." ALTHOUGH WE BELIEVE THAT THE EXPECTATIONS REFLECTED IN THE FORWARD-LOOKING STATEMENTS ARE REASONABLE, WE CANNOT GUARANTEE FUTURE RESULTS, LEVELS OF ACTIVITY, PERFORMANCE OR ACHIEVEMENTS. MOST OF THESE FACTORS ARE DIFFICULT TO PREDICT ACCURATELY AND ARE GENERALLY BEYOND OUR CONTROL. WE ARE UNDER NO OBLIGATION TO PUBLICLY UPDATE ANY OF THE FORWARD-LOOKING STATEMENTS TO REFLECT EVENTS OR CIRCUMSTANCES AFTER THE DATE HEREOF OR TO REFLECT THE OCCURRENCE OF UNANTICIPATED EVENTS. READERS ARE CAUTIONED NOT TO PLACE UNDUE RELIANCE ON THESE FORWARD-LOOKING STATEMENTS. REFERENCES IN THIS FORM 10-K, UNLESS ANOTHER DATE IS STATED, ARE TO DECEMBER 31, 2012. AS USED HEREIN, THE “COMPANY,” “WE,” “US,” “OUR” AND WORDS OF SIMILAR MEANING REFER TO PEDEVCO CORP. (D/B/A PACIFIC ENERGY DEVELOPMENT), WHICH WAS KNOWN AS BLAST ENERGY SERVICES, INC. UNTIL JULY 30, 2012, AND ITS WHOLLY-OWNED AND PARTIALLY-OWNED SUBSIDIARIES, EAGLE DOMESTIC DRILLING OPERATIONS LLC, BLAST AFJ, INC. PACIFIC ENERGY DEVELOPMENT CORP., CONDOR ENERGY TECHNOLOGY LLC, WHITE HAWK PETROLEUM, LLC, PACIFIC ENERGY TECHNOLOGY SERVICES, LLC, PACIFIC ENERGY & RARE EARTH LIMITED, BLACKHAWK ENERGY LIMITED AND PACIFIC ENERGY DEVELOPMENT MSL LLC, UNLESS OTHERWISE STATED.
 
This Annual Report on Form 10-K (this “Annual Report”) may contain forward-looking statements which are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs and cash flows, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “predict,” “potential,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
 
Forward-looking statements may include statements about our:
 
business strategy;
reserves;
technology;
cash flows and liquidity;
financial strategy, budget, projections and operating results;
oil and natural gas realized prices;
timing and amount of future production of oil and natural gas;
availability of oil field labor;
the amount, nature and timing of capital expenditures, including future exploration and development costs;
availability and terms of capital;
drilling of wells;
government regulation and taxation of the oil and natural gas industry;
marketing of oil and natural gas;
exploitation projects or property acquisitions;
costs of exploiting and developing our properties and conducting other operations;
general economic conditions;
competition in the oil and natural gas industry;
effectiveness of our risk management and hedging activities;
environmental liabilities;
counterparty credit risk;
developments in oil-producing and natural gas-producing countries;
future operating results;
estimated future reserves and the present value of such reserves; and
plans, objectives, expectations and intentions contained in this Annual Report that are not historical.
 
All forward-looking statements speak only at the date of the filing of this Annual Report. The reader should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Annual Report. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf. We do not undertake any obligation to update or revise publicly any forward-looking statements except as required by law, including the securities laws of the United States and the rules and regulations of the SEC.
 
Available Information
 
We are subject to the information and reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act, under which we file periodic reports, proxy and information statements and other information with the United States Securities and Exchange Commission, or SEC. Copies of the reports, proxy statements and other information may be examined without charge at the Public Reference Room of the SEC, 100 F Street, N.E., Room 1580, Washington, D.C. 20549, or on the Internet at http://www.sec.gov. Copies of all or a portion of such materials can be obtained from the Public Reference Room of the SEC upon payment of prescribed fees. Please call the SEC at 1-800-SEC-0330 for further information about the Public Reference Room.
 
Financial and other information about PEDEVCO Corp. is available on our website (www.pedevco.com). Information on our website is not incorporated by reference into this report. We make available on our website, free of charge, copies of our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC.
 
 
 
History
 
We were originally incorporated in September 2000 as Rocker & Spike Entertainment, Inc. In January 2001 we changed our name to Reconstruction Data Group, Inc., and in April 2003 we changed our name to Verdisys, Inc. and were engaged in the business of providing satellite services to agribusiness. In June 2005, we changed our name to Blast Energy Services, Inc. (“Blast”) to reflect our new focus on the energy services business.
 
In January 2007, Blast filed voluntary petitions with the U.S. Bankruptcy Court for the Southern District of Texas – Houston Division (the “Court”) under Chapter 11 of Title 11 of the U.S. Bankruptcy Code to dispose of burdensome and uneconomical assets and reorganize our financial obligations and capital structure. In February 2008, the Bankruptcy Court entered an order confirming our Second Amended Plan of Reorganization (the “Plan”). The overall impact of the confirmed Plan was for Blast to emerge with unsecured creditors fully paid, have no then existing debt service scheduled for at least two years, and keep equity shareholders’ interests intact.
 
During 2010, Blast's management chose to change the direction of the Company to attempting to generate operating capital from investing in oil producing properties. As a part of this shift in strategy, in September 2010, with an effective date of October 1, 2010, we closed on the acquisition of oil and gas interests in the North Sugar Valley Field located in Matagorda County, Texas, and we decided to divest our satellite services business unit, which we sold in December 2010.
 
On July 27, 2012, we acquired through a reverse acquisition, Pacific Energy Development Corp., a privately held Nevada corporation, which we refer to as Pacific Energy Development. As described below, pursuant to the acquisition, the shareholders of Pacific Energy Development gained control of approximately 95% of the voting securities of our company. Since the transaction resulted in a change of control, Pacific Energy Development is the acquirer for accounting purposes. In connection with the merger, which we refer to as the Pacific Energy Development merger, Pacific Energy Development became our wholly owned subsidiary and we changed our name from Blast Energy Services, Inc. to PEDEVCO Corp. Following the merger, we refocused our business plan on the acquisition, exploration, development and production of oil and natural gas resources in the United States, with a primary focus on oil and natural gas shale plays and a secondary focus on conventional oil and natural gas plays.
 
Business Operations
 
Overview
 
We are an energy company engaged in the acquisition, exploration, development and production of oil and natural gas resources in the United States (U.S.), with a primary focus on oil and natural gas shale plays and a secondary focus on conventional oil and natural gas plays. Our current operations are located primarily in the Niobrara Shale play in the Denver-Julesburg Basin in Morgan and Weld Counties, Colorado and the Eagle Ford Shale play in McMullen County, Texas. We also hold an interest in the North Sugar Valley Field in Matagorda County, Texas, though we consider this a non-core asset.
 
We have approximately 10,224 gross and 2,774 net acres of oil and gas properties in our Niobrara core area. Condor Energy Technology LLC (“Condor”), in which we own a 20% interest and manage with an affiliate of MIE Holdings, Inc., operates our Niobrara interests including three wells in the Niobrara asset with current daily production of approximately 494 BOE (150 BOE net). We believe our current Niobrara assets could contain a gross total of 197 drilling locations.
 
Our current Eagle Ford position is a 3.97% non-operated working interest in 1,331 acres net to us. This interest is held in White Hawk Petroleum, LLC (“White Hawk”), in which we own a 50% interest and manage with an affiliate of MIE Holdings, Inc. White Hawk owns a 7.939% non-operated working interest in 1,331 acres, of which 50% (3.97% of the non-operated working interest) is net to us.
 
We also have agreements in place (subject to customary closing conditions) for future operations in the Mississippian Lime play in Comanche, Harper, Barber and Kiowa Counties, Kansas and Woods County, Oklahoma. See “Recent Developments - Mississippian Opportunity (Pending Acquisition).” If the proposed acquisition of the Mississippian asset is completed, upon closing, we will have a 100% operated working interest in 7,006 gross (6,763 net) acres, and will hold an option to acquire an additional 7,880 gross (7,043 net) acres through May 30, 2013. We believe the Mississippian asset could contain a gross total of 84 drilling locations.

 
 
Business Strategy
 
Our goal is to increase shareholder value by building reserves, production and cash flows at an attractive return on invested capital. We intend to first focus on growing and developing reserves, production and cash flow in our U.S. core assets and then, if opportunity allows, use our relationships and partnership with MIE Holdings to expand into the Pacific Rim with a focus on the underdeveloped China shale gas and other conventional and non-conventional opportunities. We intend to achieve our objectives as follows:
 
Aggressively drill and develop our existing acreage positions. We plan to aggressively drill our core assets, drilling 11 gross wells on the Niobrara asset and two gross wells on the Eagle Ford asset through the end of 2013 subject to raising the required capital. We believe our drilling programs will allow us to begin converting our undeveloped acreage to developed acreage with production, cash flow and proved reserves.
 
Acquire additional oil and natural gas opportunities. We plan to leverage our relationships and experienced acquisition team to pursue additional leasehold assets in our core areas as well as continue to pursue additional oil and natural gas interests. We have signed a binding agreement (subject to customary closing conditions) for the acquisition of 100% operated working interests in the Mississippian Lime covering approximately 7,006 gross (6,763 net) acres located in Comanche, Harper, Barber and Kiowa Counties, Kansas, and we expect to complete the acquisition during March 2013, subject to our ability to secure sufficient financing. We also have an option to acquire an additional 7,880 gross (7,043 net) acres in the Mississippian Lime in these counties, as well as Woods County, Oklahoma. We estimate there could be up to 84 potential gross drilling locations on the Mississippian asset, and, if we consummate the acquisition, we anticipate drilling four net wells through the end of 2013. We are also exploring additional oil and natural gas opportunities in our core areas, other areas of the U.S. and Pacific Rim countries, with a particular focus on China.
 
Leverage expertise of management and external resources. We plan to focus on profitable investments that provide a platform for our management expertise, as described under “Competitive Strengths”. We have also engaged STXRA (as described below under “STXRA”) and other industry veterans as key advisors, and as discussed below, recently formed Pacific Energy Technology Services, LLC with STXRA, for the purpose of providing acquisition, engineering and oil drilling and completion technology services to third parties in the U.S. and Pacific Rim countries. As necessary, we intend to enlist external resources and talent to operate and manage our properties during peak operations.
 
Engage and leverage strategic alliances in the Pacific Rim. We have already entered into strategic alliances with MIE Holdings, and we intend to partner with additional Chinese energy companies, to (a) acquire producing oil field assets that could provide cash flow to help fund our U.S. development programs, (b) provide technical horizontal drilling expertise for a fee, thus acquiring valuable experience and data in regards to the China shale formations and successful engineering techniques, and (c) acquire interests in domestic China shale-gas blocks and commence exploration of the same.
 
Limit exposure and increase diversification through engaging in joint ventures. We own various oil and natural gas interests through joint ventures with MIE Holdings, and may in the future enter into similar joint ventures with respect to other oil and gas interests either with MIE Holdings or other partners. We believe that conducting many of our activities through partially owned joint ventures will enable us to lower our risk exposure while increasing our ability to invest in multiple ventures.
 
Leverage partnerships for financial strength and flexibility. Our joint venture partner, MIE Holdings, has been a strong financial partner. They have advanced us $4.17 million through a short-term note to fund operations and development of the Niobrara asset and $432,433 toward a performance deposit paid to the sellers in connection with the originally contemplated Mississippian transaction. We expect that proceeds from equity and debt offerings and internally generated cash flow will provide us with the financial resources to pay off these amounts due MIE Holdings and pursue our leasing and drilling and development programs through 2013. We have also met with financial institutions, introduced to us by MIE Holdings, seeking to secure a line of credit that could be used for both acquisition and development costs where needed. We cannot assure you, however, that we will be able to secure any such financing on terms acceptable to us, on a timely basis or at all.
 
Competition
 
The oil and natural gas industry is highly competitive. We compete and will continue to compete with major and independent oil and natural gas companies for exploration opportunities, acreage and property acquisitions. We also compete for drilling rig contracts and other equipment and labor required to drill, operate and develop our properties. Most of our competitors have substantially greater financial resources, staffs, facilities and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for drilling rigs or exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our competitors may also be able to afford to purchase and operate their own drilling rigs.
 
Our ability to drill and explore for oil and natural gas and to acquire properties will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. Many of our competitors have a longer history of operations than we have, and most of them have also demonstrated the ability to operate through industry cycles.
 
Competitive Strengths
 
We believe we are well positioned to successfully execute our business strategies and achieve our business objectives because of the following competitive strengths:
 
Management. We have assembled management teams at our Company and joint venture partnerships with extensive experience in the fields of international business development, petroleum engineering, geology, petroleum field development and production, petroleum operations and finance. Several members of the team developed and ran what we believe were successful energy ventures that were commercialized at Texaco, CAMAC Energy Inc., and Rosetta Resources, while members of our team at Condor have drilled and presently manage over 2,000 oil wells in the Pacific Rim and Kazakhstan. We believe that our management team is highly qualified to identify, acquire and exploit energy resources both in the U.S. and Pacific Rim countries, particularly China.
 
Our management team is headed by our President and Chief Executive Officer, Frank C. Ingriselli, an international oil and gas industry veteran with over 33 years of experience in the energy industry, including as the President of Texaco International Operations Inc., President and Chief Executive Officer of Timan Pechora Company, President of Texaco Technology Ventures, and President, Chief Executive Officer and founder of CAMAC Energy Inc. Our management team also includes Chief Financial Officer and Executive Vice President Michael L. Peterson, who brings extensive experience in the energy, corporate finance and securities sectors, including as a Vice President of Goldman Sachs & Co., Chairman and Chief Executive Officer of Nevo Energy, Inc. (formerly Solargen Energy, Inc.), and a former director of Aemetis, Inc. (formerly AE Biofuels Inc.). In addition, our Senior Vice President and Managing Director, Jamie Tseng, has over 25 years of financial management and operations experience and was a co-founder of CAMAC Energy Inc., and our Executive Vice President and General Counsel, Clark R. Moore, has nearly 10 years of energy industry experience, and formerly served as acting general counsel of CAMAC Energy Inc.
 
Key Advisors. Our key advisors include STXRA and other industry veterans. According to STXRA, the STXRA team has experience in drilling and completing horizontal wells, including over 100 horizontal wells with lengths exceeding 4,000 feet from 2010 to 2012, as well as experience in both slick water and hybrid multi-stage hydraulic fracturing technologies and in the operation of shale wells and fields. We believe that our relationship with STXRA, both directly and through our jointly-owned services company, Pacific Energy Technology Services, LLC, will supplement the core competencies of our management team and provide us with petroleum and reservoir engineering, petrophysical, and operational competencies that will help us to evaluate, acquire, develop, and operate petroleum resources into the future.
 
Significant acreage positions and drilling potential. Without giving effect to the Mississippian acquisition opportunity, we have accumulated interests in a total of 11,555 gross (2,827 net) acres in our existing core operating areas, each of which we believe represents a significant unconventional resource play. The majority of our interests are in or near areas of considerable activity by both major and independent operators, although such activity may not be indicative of our future operations. Based on our current acreage position, and without giving effect to the Mississippian acquisition opportunity, we estimate there could be up to 197 potential gross drilling locations on our acreage, and we anticipate drilling approximately 13 gross (3.06 net) wells through the end of 2013, leaving us a substantial drilling inventory for future years.
 
Marketing
 
The prices we receive for our oil and natural gas production fluctuate widely. Factors that cause price fluctuation include the level of demand for oil and natural gas, weather conditions, hurricanes in the Gulf Coast region, natural gas storage levels, domestic and foreign governmental regulations, the actions of OPEC, price and availability of alternative fuels, political conditions in oil and natural gas producing regions, the domestic and foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. Decreases in these commodity prices adversely affect the carrying value of our proved reserves and our revenues, profitability and cash flows. Short-term disruptions of our oil and natural gas production occur from time to time due to downstream pipeline system failure, capacity issues and scheduled maintenance, as well as maintenance and repairs involving our own well operations. These situations can curtail our production capabilities and ability to maintain a steady source of revenue for our company. In addition, demand for natural gas has historically been seasonal in nature, with peak demand and typically higher prices during the colder winter months. See “Risk Factors.”
 
Oil. Our crude oil is generally sold under short-term, extendable and cancellable agreements with unaffiliated purchasers based on published price bulletins reflecting an established field posting price. As a consequence, the prices we receive for crude oil move up and down in direct correlation with the oil market as it reacts to supply and demand factors. Transportation costs related to moving crude oil are also deducted from the price received for crude oil.
 
We have entered into a month-to-month Crude Oil Purchase Contract with a third party buyer, pursuant to which the buyer purchases the crude oil produced from our initial three wells in the Niobrara, the FFT2H, Waves 1H, and Logan 2H wells, periodically at a price per barrel equal to the average monthly “Light Sweet Crude Oil” contract price as reported by NYMEX from the first day of the delivery month through the last day of the delivery month, less $8.25 per barrel for transportation costs.
 
Natural Gas. Our natural gas is sold under both long-term and short-term natural gas purchase agreements. Natural gas produced by us is sold at various delivery points at or near producing wells to both unaffiliated independent marketing companies and unaffiliated mid-stream companies. We receive proceeds from prices that are based on various pipeline indices less any associated fees for processing, location or transportation differentials.
 
We have entered into a Gas Purchase Contract, dated June 1, 2012, with DCP Midstream, LP, which we refer to as DCP, pursuant to which we have agreed to sell, and DCP has agreed to purchase, all gas produced from our wells located in Weld County, Colorado as part of our Niobrara asset, at a purchase price equal to 83% of the net weighted average value for gas attributable to us that is received by DCP at its facilities sold during the month, less a $0.06/gallon local fractionation fee, for a period of ten years, terminating June 1, 2022.
 
We endeavor to assure that title to our properties is in accordance with standards generally accepted in the oil and natural gas industry. Some of our acreage will be obtained through farmout agreements, term assignments and other contractual arrangements with third parties, the terms of which often will require the drilling of wells or the undertaking of other exploratory or development activities in order to retain our interests in the acreage. Our title to these contractual interests will be contingent upon our satisfactory fulfillment of these obligations. Our properties are also subject to customary royalty interests, liens incident to financing arrangements, operating agreements, taxes and other burdens that we believe will not materially interfere with the use and operation of or affect the value of these properties. We intend to maintain our leasehold interests by making lease rental payments or by producing wells in paying quantities prior to expiration of various time periods to avoid lease termination.
 
Merger with Pacific Energy Development
 
On July 27, 2012, in order to carry out our business plan, we acquired through a reverse acquisition, Pacific Energy Development Corp., a privately held Nevada corporation, which we refer to as Pacific Energy Development. As described below, pursuant to the acquisition, the shareholders of Pacific Energy Development gained control of approximately 95% of the voting securities of our company. Since the transaction resulted in a change of control, Pacific Energy Development is the acquirer for accounting purposes. In connection with the merger, which we refer to as the Pacific Energy Development merger, Pacific Energy Development became our wholly owned subsidiary and we changed our name from Blast Energy Services, Inc. to PEDEVCO CORP.
 
As part of the Pacific Energy Development merger, we issued to the shareholders of Pacific Energy Development (a) 17,917,261 shares of our common stock, (b) 19,616,676 shares of our newly created Series A preferred stock, (c) warrants to purchase an aggregate of 1,120,000 shares of our common stock and 692,584 shares of our Series A preferred stock at various exercise prices, and (d) options to purchase an aggregate of 4,235,000 shares of our common stock at various exercise prices. Pursuant to the Pacific Energy Development merger, all of our shares of preferred stock that were outstanding prior to the Pacific Energy Development merger were converted into shares of common stock on a one-for-one basis and we effected a reverse stock split of our common stock on a 1 for 112 shares basis. All share and per share amounts used in this Annual Report have been restated to reflect this reverse stock split.
 
At the effective time of the Pacific Energy Development merger, (a) Pacific Energy Development owned the Niobrara and Eagle Ford assets and had begun discussions regarding the Mississippian acquisition opportunity, and (b) our primary business was developing the North Sugar Valley Field asset. As a result of our acquisition of Pacific Energy Development in the Pacific Energy Development merger, we acquired these assets and opportunities of Pacific Energy Development.
 
In connection with the Pacific Energy Development merger, the directors and executive officers of Pacific Energy Development became our directors and executive officers. See “Management.”
 
The following chart reflects our core subsidiaries and joint ventures as of December 31, 2012:
 
 
Oil and Gas Properties
 
We believe that the Niobrara, Eagle Ford and Mississippian Shale plays represent among the most promising unconventional oil and natural gas plays in the U.S. We plan to continue to seek additional acreage proximate to our currently held core acreage. Our strategy is to be the operator, directly or through our subsidiaries and joint ventures, in the majority of our acreage so we can dictate the pace of development in order to execute our business plan. The majority of our capital expenditure budget for the period from January 2013 to December 2013 will be focused on the acquisition, development and expansion of these formations.
 
The following table presents summary data for our leasehold acreage in our core areas as of December 31, 2012 and our drilling capital budget with respect to this acreage from January 1, 2013 to December 31, 2013, subject to availability of capital.
 
                                 
Drilling & Land Acquisition Capital Budget
January 1, 2013 - December 31, 2013
 
   
Total
Gross
Acreage
   
 
Ownership
Interest
   
Net Acres
   
Acre Spacing
   
Potential Gross -Drilling Locations(3)
   
Gross Wells
   
Net Wells
   
$/Well(4)
   
Capital Cost (4)
 
                                                       
Current Core Assets:
                                                     
                                                       
Niobrara(1)
    10,224       27.13 %     2,774       80       180       11       2.98     $ 4,500,000     $ 13,410,000  
                                                                         
Eagle Ford (2)
    1,331       3.97 %     53       60       17       2       0.08     $ 9,000,000     $ 720,000  
Current Assets
    11,555               2,827               197       13       3.06             $ 14,130,000  
 
(1)
As discussed below, we have a 27.13% net ownership interest in the leased acreage in the Niobrara asset (12.15% of the acreage is held directly by us plus 14.98% of the acreage is held by virtue of our 20% interest in Condor, which in turn holds a 74.88% working interest in the leased acreage in the Niobrara asset).
 
(2)
As discussed below, we have a 3.97% ownership in the leased acreage in the Eagle Ford asset (held by virtue of our 50% interest in White Hawk Petroleum, LLC, which holds a 7.939% working interest in the Eagle Ford asset).
 
(3)
Potential gross drilling locations are calculated using the acre spacings specified for each area in the table and adjusted assuming forced pooling in the Niobrara. Colorado, where the Niobrara asset is located, allows for forced pooling, which may create more potential gross drilling locations than acre spacing alone would otherwise indicate.
 
(4)
Cost per well are gross costs while capital costs presented are net to the Company’s working interests.
 
 
Niobrara Asset
 
Our interests in the Niobrara asset consist of the following:
 
We directly hold a portion of our interest in the Niobrara asset through our wholly-owned subsidiary, Pacific Energy Development Corp. These interests are all located within Weld County, Colorado.
We indirectly hold a portion of our interest in the Niobrara asset by virtue of our 20% ownership in Condor Energy Technology LLC (“Condor”), which is 80% owned by a subsidiary of our partner, MIE Holdings Corporation. These interests are all located within Weld and Morgan Counties, Colorado. Condor is the operator of all of our Niobrara assets (both directly and indirectly owned).
 
Eagle Ford Asset
 
We indirectly hold all of our interests in the Eagle Ford asset by virtue of our 50% ownership in White Hawk Petroleum, LLC (“White Hawk”), which is 50% owned by a subsidiary of our partner, MIE Holdings Corporation. These interests are all located within McMullen County, Texas.
 
North Sugar Valley Asset
 
We directly hold all of our interests in the North Sugar Valley asset. These interests are all located within Matagorada County, Texas.
 
Strategic Alliances
 
MIE Holdings
 
Through the relationships developed by our founder and Chief Executive Officer, Frank Ingriselli, we formed a strategic relationship with MIE Holdings Corporation (Hong Kong Stock Exchange code: 1555.HK), one of the largest independent upstream onshore oil companies in China, which we refer to as MIE Holdings, to assist us with our plans to develop unconventional shale properties. According to information provided by MIE Holdings, MIE Holdings has drilled and currently operates over 2,000 oil wells in China and brings extensive drilling and completion experience and expertise, as well as a strong geological team. MIE Holdings has also been a significant investor in our operations, and as discussed below, the majority of our oil and gas interests are held all or in part by the following joint ventures which we jointly own with affiliates of MIE Holdings:
 
Condor Energy Technology LLC, which we refer to as Condor, which is a Nevada limited liability company owned 20% by us and 80% by an affiliate of MIE Holdings; and
White Hawk Petroleum, LLC, which we refer to as White Hawk, which is a Nevada limited liability company owned 50% by us and 50% by an affiliate of MIE Holdings.
 
Although our initial focus is on oil and natural gas opportunities in the U.S., we plan to use our strategic relationship with MIE Holdings and our experience in operating U.S.-based shale oil and natural gas interests to acquire, explore, develop and produce oil and natural gas resources in Pacific Rim countries, with a particular focus on China.
 
MIE Holdings has been a valuable partner providing us necessary capital in the early stages of our development. It purchased 4 million shares of our Series A preferred stock and acquired an 80% interest in Condor for total consideration of $3 million, and has loaned us the funds to drill and complete our first three Niobrara wells, and to cover other of our Niobrara-related operating and development expenses. MIE Holdings has also introduced us to its banking relationships in order for us to start the process of seeking to obtain a line of credit for future acquisition and development costs.
 
 
STXRA
 
On October 4, 2012, we established a technical services subsidiary, Pacific Energy Technology Services, LLC, which is 70% owned by us and 30% owned by South Texas Reservoir Alliance, LLC, which we refer to as STXRA, through which we plan to provide acquisition, engineering, and oil drilling and completion technology services in joint cooperation with STXRA in the U.S. and Pacific Rim countries, particularly in China. While Pacific Energy Technology Services, LLC currently has no operations, only nominal assets and liabilities and has limited capitalization, we anticipated actively developing this venture in 2013. STXRA is a consulting firm specializing in the delivery of petroleum resource acquisition services and practical engineering solutions to clients engaged in the acquisition, exploration and development of petroleum resources. In April 2011, we entered into an agreement of joint cooperation with STXRA in an effort to identify suitable energy ventures for acquisition by us, with a focus on plays in shale oil and natural gas bearing regions in the U.S. According to information provided by STXRA, the STXRA team has experience in their collective careers of drilling and completing horizontal wells, including over 100 horizontal wells with lengths exceeding 4,000 feet from 2010 to 2012, as well as experience in both slick water and hybrid multi-stage hydraulic fracturing technologies and in the operation of shale wells and fields. We believe that our relationship with STXRA, both directly and through our jointly-owned services company, Pacific Energy Technology Services, LLC, will supplement the core competencies of our management team and provide us with petroleum and reservoir engineering, petrophysical, and operational competencies that will help us to evaluate, acquire, develop and operate petroleum resources in the future.
 
 
Our Core Areas
 
The majority of our capital expenditure budget for the period from January to December 2013 will be focused on the acquisition and development of our core oil and natural gas properties: the Niobrara and Eagle Ford Shale plays and the Mississippian Lime play, if acquired as contemplated through the recently executed definitive purchase agreement. The following paragraphs summarize each of these core areas. For additional information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” and “Business.”
 
 
Niobrara Asset
 
 
As of December 31, 2012, we held 2,774 net acres in oil and natural gas properties covering approximately 10,224 gross acres that are located in Morgan and Weld Counties, Colorado that include the Niobrara formation, which we refer to as the Niobrara asset. We hold 1,243 of our Niobrara leased acreage directly, and hold the remaining 1,531 acres through our ownership in Condor, which holds 8,035 acres in the leased acreage in the Niobrara asset. We and/or Condor own working interests in the Niobrara asset ranging from 0.03% to 100%.
 
Condor is designated as the operator of the Niobrara asset. The day-to-day operations of Condor are managed by our management, and Condor’s Board of Managers is comprised of our President and Chief Executive Officer, Mr. Frank Ingriselli, and two designees of MIE Holdings. In addition, MIE Holdings has loaned us approximately $4.17 million to fund operations and development of the Niobrara asset.
 
Based on approximately 250 square miles of 3D seismic data covering the Niobrara asset, we estimate that there are up to 180 potential gross drilling locations in the Niobrara asset, with 14 initial gross well locations identified for our 2012-2013 Niobrara development plan, including our initial well completed in July 2012 and our second and third wells completed in February 2013, leaving 11 gross wells to be drilled and completed in our plan for 2013. We believe that the Niobrara asset affords us the opportunity to participate in this emerging play at an early stage, with a position in the Denver-Julesburg Basin adjacent to significant drilling activity.
 
Condor completed drilling the initial horizontal well on the Niobrara asset, the FFT2H, in April 2012, reaching a total combined vertical and horizontal depth of 11,307 feet. Halliburton performed a 20-stage frack of the well in mid-June 2012, with the well being completed in July 2012 with an initial production rate of 437 BOE per day from the Niobrara formation. Condor completed drilling its second horizontal well on the Niobrara asset, the Waves 1H, in November 2012, drilling to 11,114 feet measured depth (6,200 true vertical foot depth) in eight days. The 4,339 foot lateral section was completed in 18 stages by Halliburton in February 2013, and the well tested at an initial production rate of 528 barrels of oil per day and 360 Mcf per day (588 BOE per day) from the Niobrara “B” Bench target zone. Condor also completed drilling its third horizontal well on the Niobrara asset, the Logan 2H, in December 2012 to 12,911 feet measured depth (6,112 true vertical depth) in nine days. The 6,350 foot lateral section was completed in 25 stages by Halliburton in January 2013, and tested at an initial production rate of 522 barrels of oil per day and 360 Mcf per day (585 BOE per day) from the Niobrara “B” Bench target zone.
 
Based on publicly available information, we believe that average drilling and completion costs for wells in the Niobrara core area which, for purposes of industry comparisons, we define as Morgan and Weld Counties, Colorado, have ranged between $3.6 million and $6.0 million per well with average estimated ultimate recoveries, or EURs, of 100,000 to 300,000 BOE per well and initial 30-day average production of 300 to 600 BOE per day per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.
 
Recently, there has been significant industry activity in the Niobrara Shale play. The most active operators offsetting our acreage position include Carrizo Oil and Gas, Inc. (NASDAQ: CRZO), Continental Resources, Inc. (NYSE: CLR), EOG Resources (NYSE: EOG), Anadarko Petroleum (NYSE: APC), SM Energy (NYSE: SM), Noble Energy (NYSE: NBL), Chesapeake Energy (NYSE: CHK), Whiting Petroleum (NYSE: WLL), Quicksilver Resources (NYSE: KWK), MDU Resources (NYSE: MDU), and Bill Barrett Corp. (NYSE: BBG).
 
Eagle Ford Asset
 
As of December 31, 2012, we held 53 net acres in certain oil and gas leases covering approximately 1,331 gross acres in the Leighton Field located in McMullen County, Texas, which is currently producing oil and natural gas from the highly-prospective Eagle Ford Shale formation, which we refer to as the Eagle Ford asset. We hold these interests through our 50% ownership interest in White Hawk, which holds a 7.939% working interest in the Eagle Ford asset.
 
The Eagle Ford asset currently has three wells that have been drilled and are producing, with gross initial production rates, as publicly disclosed by Texon Petroleum Limited, the operator of the Eagle Ford asset, of 1,202 Bbl per day and 782 Mcf per day for the first well, 1,488 Bbl per day and 700 Mcf per day for the second well, and 1,072 Bbl per day and 1,137 Mcf per day for the third well. During the month of January 2013 the net production attributable to our 3.97% interest from these wells was 330 Bbl of oil and 507 Mcf of natural gas. Based on our current understanding of the field, on the approximately 1,331 gross acre Eagle Ford asset, approximately 17 more Eagle Ford gross wells may be drilled. We expect that the operator will drill two additional gross wells during 2013.
 
First discovered in 2008, according to data provided by Baker Hughes, the Eagle Ford Shale resource area had an active drilling rig count of 233 horizontal rigs as of December 31, 2012, which accounts for nearly half of the 473 horizontal drilling rigs in the State of Texas as of such date.
 
Based on publicly available information, we believe that average drilling and completion costs for wells in the Eagle Ford core area which, for purposes of industry comparisons, we define as McMullen County, Texas, have ranged between $8 million and $11 million per well with average estimated ultimate recoveries, or EURs, of 300,000 to 500,000 BOE per well and initial 30-day average production of 800 to 1,500 BOE per day per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.
 
Our Non-Core Area
 
North Sugar Valley Field Asset
 
We acquired the North Sugar Valley asset in Matagorda County, Texas in connection with our merger with Blast representing an approximately 65% working interest (net revenue interest of approximately 50%) in three wells, the Millberger #1, Millberger #2 and Oxbow #1 wells. Our 2012 year-end reserve report estimates contains approximately 36,988 barrels of proved reserves net to the interest we acquired.
 
Sun Resources Texas, Inc., a privately-held company based in Longview, Texas, which we refer to as Sun, is the operator of the properties. Sun retains a 1% working interest in the wells.
 
During late 2011 and early 2012, the down-hole equipment on the Oxbow #1 well began to fail which eventually caused the well to be deemed uneconomic. The Oxbow #1 oil production declined to a point where it was determined it would be more cost effective to have it converted into a salt water disposal well, or SWDs, for the water produced by the Millberger #1 and #2 wells. We have given our consent to pursue such a conversion and Sun is seeking to obtain the approvals and permits for the SWD well. If permits or permissions are not able to be obtained, we will pay our share of the plugging and abandonment costs and will then most likely seek to drill a disposal well at another location on the leases.
 
 
Recent Developments
 
Mississippian Opportunity (Pending Acquisition)
 
Pacific Energy Development MSL LLC, our wholly owned Nevada subsidiary which we refer to as PEDCO MSL, has signed a binding agreement (subject to customary closing conditions) with a third party for the acquisition of 100% operated working interests in the Mississippian Lime covering approximately 7,006 gross (6,763 net) acres located in Comanche, Harper, Barber and Kiowa Counties, Kansas, which we refer to as the Mississippian asset, for an aggregate purchase price of $4,207,117. We have also entered into an option agreement with the seller to acquire an additional 7,880 gross (7,043 net) acres in these counties and Woods County, Oklahoma, expiring May 30, 2013. The closing of the acquisition of the Mississippian asset is anticipated to occur in March 2013, subject to satisfaction of certain conditions to closing, and our ability to secure sufficient financing, of which there can be no assurances. Accordingly, we cannot guarantee that we will complete the acquisition in March 2013, or at all.
 
This pending Mississippian acquisition replaces and supersedes the acquisition previously contemplated by Condor of this Mississippian asset pursuant to an acquisition agreement entered into in November 2012 with the seller, which transaction contemplated the acquisition of the full 13,806 gross acres by Condor for an aggregate purchase price of $8,648,661, with the Company and an affiliate of MIE Holdings each sharing 50% of the purchase price, ownership interest, development and operational expenses with respect to the asset. The new Mississippian transaction now provides for the Company’s subsidiary, PEDCO MSL, to acquire the interests in approximately half of the originally contemplated 13,806 total gross acres for approximately half of the originally contemplated cost, with an option to acquire the remaining interests by May 30, 2013, on substantially the same terms and conditions as originally contemplated in Condor’s superseded Mississippian acquisition.
 
We will be the operator of the Mississippian asset, and we anticipate drilling the first well on the Mississippian asset in the second quarter of 2013, with a total of four wells planned in 2013. The Mississippian oil play is one of the latest oil plays that have recently captured attention in the industry, and we believe that there is an opportunity to acquire additional interests in this emerging play on attractive terms.
 
The following table presents summary data for the leasehold acreage associated with the Mississippian opportunity, not including those acres where we have an option to purchase, and our proposed drilling capital budget with respect to this acreage thru December 31, 2013, assuming we are able to secure sufficient funding and acquire this acreage.
 
                                 
Drilling & Land Acquisition Capital Budget
April 1, 2013 - December 31, 2013
 
   
Total
Gross
Acreage
   
 
Ownership Interest
   
Net Acres
   
Acre Spacing
   
Potential Gross-Drilling Locations(2)
   
Gross Wells
   
Net Wells
   
$/Well
   
Capital Cost
 
                                                       
Mississippian
   
7,006
     
100
%
   
6,763
     
160
     
42
     
4.0
     
4.0
   
$
3,300,000
   
$
13,200,000
 
Acquisition Cost(1)
                                                                 
$
4,207,117
 
                                                                   
$
17,407,117
 
 
(1) Represents our share of the anticipated acquisition costs for the Mississippian asset, assuming we pay 100% of the purchase price, and excluding the exercise of the option to acquire an additional 7,880 gross (7,043 net) acres for an additional $4.2 million.
 
(2) Potential gross drilling locations are calculated using the acre spacing specified in the table. We have no proved, probable or possible reserves attributable to any of these potential gross drilling locations.
 
Based on publicly available information, we believe that average drilling and completion costs for wells in the Mississippian core area which, for purposes of industry comparisons, we define as Comanche, Harper, Barber and Kiowa Counties, Kansas and Woods County, Oklahoma, have ranged between $3.2 million and $4.0 million per well with average estimated ultimate recoveries, or EURs, of 250,000 to 500,000 BOE per well and initial 30-day average production of 250 to 1,500 BOE per day per well. The costs incurred, EURs and initial production rates achieved by others may not be indicative of the well costs we will incur or the results we will achieve from our wells.
 
Possible Reverse Stock Split
 
On December 3, 2012, our company’s board of directors approved a possible reverse stock split of our common stock and Series A preferred stock in a ratio ranging between 1-for-2 and 1-for-5, with the specific ratio and effective time (if we decide to proceed with the split) to be later determined by the board of directors. Effective December 5, 2012, holders of a majority of our common stock and Series A preferred stock granted the board of directors discretionary authority to determine the specific ratio and effective time for the reverse split. We have filed and mailed to our shareholders an Information Statement on Schedule 14C in connection with such approval. We have not made any adjustments to the amount of shares disclosed in this Annual Report to account for this intended reverse stock split.
 
 
Shale Oil and Natural Gas Overview
 
The relatively recent surge of oil and natural gas production from underground shale rock formations has had a dramatic impact on the oil and natural gas market in the U.S., where the practice was first developed, and globally. Shale oil production is facilitated by the combination of a set of technologies that had been applied separately to other hydrocarbon reservoir types for many decades. In combination these technologies and techniques have enabled large volumes of oil to be produced from deposits with characteristics that would not otherwise permit oil to flow at rates sufficient to justify its exploitation. The application of horizontal drilling, hydraulic fracturing and advanced reservoir assessment tools to these reservoirs is unlocking a global resource of shale and other unconventional oil and natural gas that the International Energy Agency estimates could eventually double recoverable global oil reserves.
 
In 2008, U.S. natural gas production was in decline, and the U.S. was on its way to becoming a significant importer of liquefied natural gas (LNG). By 2009, U.S.-marketed natural gas production was 14% higher than in 2005, and in 2010 it surpassed the previous annual production record set in 1973. This turnaround is mainly attributable to shale oil and natural gas output that has more than tripled since 2007. Knowledge is expanding rapidly concerning the shale oil reservoirs that are already being exploited and others that appear suitable for development with current technology. In its preliminary 2011 Annual Energy Outlook, the U.S. Department of Energy (DOE) increased its estimate of recoverable U.S. shale natural gas resources by 238% compared to its previous estimate, bringing U.S. potential natural gas resources to 2,552 trillion cubic feet (TCF), equivalent to more than a century’s supply at current consumption rates.
 
Along with the reduction in economic activity resulting from the recession, the increase in production from shale natural gas has had a significant impact on U.S. average natural gas wellhead prices, which have fallen by more than 30% since 2007. As a result, the value of natural gas has diverged significantly from that of petroleum on an energy-equivalent basis. That has provided substantial economic benefits to natural gas-consuming industries. It has also led to both economic and environmental benefits for the electricity sector, as fired power plants displace power from higher-cost and higher-emitting sources. Shale natural gas has been cited by U.S. Secretary of Energy, Stephen Chu, as helping the world shift to cleaner fuels. A report by the National Petroleum Council (NPC) to Stephen Chu in September 2011 stated that shale oil fields in the U.S. could produce 2 to 3 million barrels of oil per day by 2025, given the right regulatory environment and technology breakthroughs.
 
Oil and natural gas produced from shale is considered an unconventional resource. Commercial oil and natural gas production from unconventional sources requires special techniques in order to achieve attractive oil and natural gas flow rates. Unlike conventional oil and natural gas, which is typically generated in deeper source rock and subsequently migrates into a sandstone structure with an overlying impermeable layer forming a “trap,” shale oil and natural gas is generated from organic material contained within the shale and retained by the rock’s inherent low permeability. Permeability is a measure of the ease with which natural gas, oil or other fluids can flow through the material. The same low permeability that secures large volumes of natural gas and liquids in place within the shale strata makes it much more difficult to extract them, even with a large pressure difference between the reservoir and the surface. The location and potential of many of today’s productive shale reservoirs were known for many years, but until the development of current shale oil and natural gas techniques these deposits were considered noncommercial or inaccessible.
 
The main challenge of shale oil and natural gas drilling is to overcome the low permeability of the shale reservoirs. A conventional vertical oil or natural gas well drilled into one of these reservoirs might achieve production, though at reduced rates and for a limited duration before the oil or natural gas volume in proximity to the wellbore is exhausted. That often renders such an approach impractical and uneconomic for exploiting shale oil and natural gas. The two main technologies associated with U.S. shale oil and natural gas production are horizontal drilling and hydraulic fracturing, or “hydrofracking.” They are employed to overcome these constraints by greatly increasing the exposure of each well to the shale stratum and enabling oil and natural gas located farther from the well to flow through the rock and replace the nearby oil and natural gas that has been extracted to the surface.
 
Instead of drilling a simple vertical well through the shale and then perforating the well within the zone where it is in contact with the shale, the drilling company drills a directional well vertically to within proximity of the shale and then executes a 90-degree turn in order to intersect the shale and then travel for a significant horizontal distance through it. A typical North American shale well has a horizontal extent of 1,000 feet to 5,000 feet or more.
 
Once the lateral portion of the well has reached the desired extent, the other main technique of shale oil and natural gas drilling is deployed. After the well has been completed, the farthest section of the lateral is perforated, opening up holes through which fluid can flow. This portion of the reservoir is then hydrofracked by injecting fluid into the well under high pressure to fracture the exposed shale rock and open up pathways through which oil and natural gas can flow. The “fracking fluid” consists mainly of water with a variety of chemical additives intended to reduce friction and dissolve minerals, among other purposes, along with sand or sand-like material to prop open the new pathways created by hydrofracking. This process is then repeated at intervals along the well’s horizontal extent, successively perforating and hydrofracking each section in turn. This process creates a producing well that emulates the effect of a vertical well drilled into a conventional oil and natural gas reservoir by substituting multiple horizontal “pay zones” in the shale stratum for the thinner but more prolific vertical pay zone in a more permeable reservoir. Compared to conventional oil and natural gas drilling, the production of oil and natural gas from shale reservoirs thus entails more drilling, on average, and requires a substantial supply of water.
 
Shale oil and natural gas are currently being produced from a number of reservoirs in the U.S. Among these are the Bakken Shale in Montana and North Dakota, the Niobrara Shale in northeastern Colorado and parts of adjacent Wyoming, Nebraska, and Kansas, the Eagle Ford Shale in southern Texas, the Mississippian Lime in Kansas and Oklahoma, and the Marcellus Shale spanning several states in the northeastern U.S. According to the 2007 Survey of Energy Resources Report issued by the World Energy Counsel in 2007, the total world resources of shale oil are conservatively estimated at 2.8 trillion barrels, with an estimated nearly 74% of the world’s potentially recoverable shale oil resources being concentrated in the U.S., totaling approximately 1.96 trillion barrels of oil.
 
Regulation
 
Oil and Natural Gas Regulation
 
Our oil and natural gas exploration, development, production and related operations are subject to extensive federal, state and local laws, rules and regulations. Failure to comply with these laws, rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry increases our cost of doing business and affects our profitability. Because these rules and regulations are frequently amended or reinterpreted and new rules and regulations are promulgated, we are unable to predict the future cost or impact of complying with the laws, rules and regulations to which we are, or will become, subject. Our competitors in the oil and natural gas industry are generally subject to the same regulatory requirements and restrictions that affect our operations. We cannot predict the impact of future government regulation on our properties or operations.
 
Texas, Colorado, Kansas, Oklahoma and many other states require permits for drilling operations, drilling bonds and reports concerning operations and impose other requirements relating to the exploration, development and production of oil and natural gas. Many states also have statutes or regulations addressing conservation of oil and natural gas matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, the regulation of well spacing, the surface use and restoration of properties upon which wells are drilled, the sourcing and disposal of water used in the drilling and completion process and the plugging and abandonment of these wells. Many states restrict production to the market demand for oil and natural gas. Some states have enacted statutes prescribing ceiling prices for natural gas sold within their boundaries. Additionally, some regulatory agencies have, from time to time, imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below natural production capacity in order to conserve supplies of oil and natural gas. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.
 
Some of our oil and natural gas leases are issued by agencies of the federal government, as well as agencies of the states in which we operate. These leases contain various restrictions on access and development and other requirements that may impede our ability to conduct operations on the acreage represented by these leases.
 
Our sales of natural gas, as well as the revenues we receive from our sales, are affected by the availability, terms and costs of transportation. The rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, as well as under Section 311 of the Natural Gas Policy Act. Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, non-discriminatory basis. The natural gas industry has historically, however, been heavily regulated and we can give no assurance that the current less stringent regulatory approach of FERC will continue.
 
In 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. FERC has promulgated regulations to implement the Energy Policy Act. Should we violate the anti-market manipulation laws and related regulations, in addition to FERC-imposed penalties, we may also be subject to third-party damage claims.
 
Intrastate natural gas transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Because these regulations will apply to all intrastate natural gas shippers within the same state on a comparable basis, we believe that the regulation in any states in which we operate will not affect our operations in any way that is materially different from our competitors that are similarly situated.
 
The price we receive from the sale of oil and natural gas liquids will be affected by the availability, terms and cost of transportation of the products to market. Under rules adopted by FERC, interstate oil pipelines can change rates based on an inflation index, though other rate mechanisms may be used in specific circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions, which varies from state to state. We are not able to predict with certainty the effects, if any, of these regulations on our operations.
 
In 2007, the Energy Independence & Security Act of 2007 (the “EISA”), went into effect. The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations and establishes penalties for violations thereunder. We cannot predict any future regulations or their impact.
 
U.S. Federal and State Taxation
 
The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. President Obama has recently proposed sweeping changes in federal laws on the income taxation of small oil and natural gas exploration and production companies such as us. President Obama has proposed to eliminate allowing small U.S. oil and natural gas companies to deduct intangible U.S. drilling costs as incurred and percentage depletion. Many states have raised state taxes on energy sources, and additional increases may occur. Changes to tax laws could adversely affect our business and our financial results.
 
Environmental Regulation
 
The exploration, development and production of oil and natural gas, including the operation of saltwater injection and disposal wells, are subject to various federal, state and local environmental laws and regulations. These laws and regulations can increase the costs of planning, designing, installing and operating oil and natural gas wells. Our activities are subject to a variety of environmental laws and regulations, including but not limited to the Oil Pollution Act of 1990 (OPA 90), the Clean Water Act (CWA), the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), the Resource Conservation and Recovery Act (RCRA), the Clean Air Act (CAA), the Safe Drinking Water Act (the SDWA) and the Occupational Safety and Health Act (OSHA), as well as comparable state statutes and regulations. We are also subject to regulations governing the handling, transportation, storage and disposal of wastes generated by our activities and naturally occurring radioactive materials (NORM) that may result from our oil and natural gas operations. Civil and criminal fines and penalties may be imposed for noncompliance with these environmental laws and regulations. Additionally, these laws and regulations require the acquisition of permits or other governmental authorizations before undertaking some activities, limit or prohibit other activities because of protected wetlands, areas or species and require investigation and cleanup of pollution. We intend to remain in compliance in all material respects with currently applicable environmental laws and regulations.
 
OPA 90 and its regulations impose requirements on “responsible parties” related to the prevention of crude oil spills and liability for damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the U.S. A “responsible party” under OPA 90 may include the owner or operator of an onshore facility. OPA 90 subjects responsible parties to strict joint and several financial liability for removal costs and other damages, including natural resource damages, caused by an oil spill that is covered by the statute. It also imposes other requirements on responsible parties, such as the preparation of an oil spill contingency plan. Failure to comply with OPA 90 may subject a responsible party to civil or criminal enforcement action. We may conduct operations on acreage located near, or that affects navigable waters subject to OPA 90.
 
The CWA imposes restrictions and strict controls regarding the discharge of produced waters and other wastes into navigable waters. These controls have become more stringent over the years, and it is possible that additional restrictions will be imposed in the future. Permits are required to discharge pollutants into state and federal waters and to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the federal National Pollutant Discharge Elimination System program prohibit the discharge of produced water, produced sand, drilling fluids, drill cuttings and certain other substances related to the oil and natural gas industry into certain coastal and offshore waters. Furthermore, the EPA has adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. The CWA and comparable state statutes provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other pollutants and impose liability for the costs of removal or remediation of contamination resulting from such discharges. In furtherance of the CWA, the EPA promulgated the Spill Prevention, Control, and Countermeasure (SPCC) regulations, which require certain oil-storing facilities to prepare plans and meet construction and operating standards.
 
CERCLA, also known as the “Superfund” law, and comparable state statutes impose liability, without regard to fault or the legality of the original conduct, on various classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site where the release occurred and companies that disposed of, or arranged for the disposal of, the hazardous substances found at the site. Persons who are responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances and for damages to natural resources. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. Our operations may, and in all likelihood will, involve the use or handling of materials that may be classified as hazardous substances under CERCLA. Furthermore, we may acquire or operate properties that unknown to us have been subjected to, or have caused or contributed to, prior releases of hazardous wastes.
 
RCRA and comparable state and local statutes govern the management, including treatment, storage and disposal, of both hazardous and nonhazardous solid wastes. We generate hazardous and nonhazardous solid waste in connection with our routine operations. At present, RCRA includes a statutory exemption that allows many wastes associated with crude oil and natural gas exploration and production to be classified as nonhazardous waste. A similar exemption is contained in many of the state counterparts to RCRA. At various times in the past, proposals have been made to amend RCRA to eliminate the exemption applicable to crude oil and natural gas exploration and production wastes. Repeal or modifications of this exemption by administrative, legislative or judicial process, or through changes in applicable state statutes, would increase the volume of hazardous waste we are required to manage and dispose of and would cause us, as well as our competitors, to incur increased operating expenses. Hazardous wastes are subject to more stringent and costly disposal requirements than are nonhazardous wastes.
 
The CAA and comparable state laws restrict the emission of air pollutants from many sources, including oil and natural gas production. These laws and any implementing regulations impose stringent air permit requirements and require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, or to use specific equipment or technologies to control emissions. On July 28, 2011, the EPA proposed new regulations targeting air emissions from the oil and natural gas industry. The proposed rules, if adopted, would impose new requirements on production and processing and transmission and storage facilities.
 
Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements or operating requirements could materially adversely affect our operations and financial position, as well as those of the oil and natural gas industry in general. For instance, recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases,” and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere. As a result, there have been attempts to pass comprehensive greenhouse gas legislation. To date, such legislation has not been enacted. Any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could, and in all likelihood would, require us to incur increased operating costs adversely affecting our profits and could adversely affect demand for the oil and natural gas we produce depressing the prices we receive for oil and natural gas.
 
On December 15, 2009, the EPA published its finding that emissions of greenhouse gases presented an endangerment to human health and the environment. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Subsequently, the EPA proposed and adopted two sets of regulations, one of which requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which regulated emissions of greenhouse gases from certain large stationary sources. In addition, on October 30, 2009, the EPA published a rule requiring the reporting of greenhouse gas emissions from specified sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a rule that expands its final rule on greenhouse gas emissions reporting to include owners and operators of onshore and offshore oil and natural gas production, onshore natural gas processing, natural gas storage, natural gas transmission and natural gas distribution facilities. Reporting of greenhouse gas emissions from such onshore production became required on an annual basis beginning in 2012 for emissions occurring in 2011. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could, and in all likelihood will, require us to incur costs to reduce emissions of greenhouse gases associated with our operations adversely affecting our profits or could adversely affect demand for the oil and natural gas we produce depressing the prices we receive for oil and natural gas.
 
Some states have begun taking actions to control and/or reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date focused on significant sources of greenhouse gas emissions, such as coal-fired electric plants, it is possible that less significant sources of emissions could become subject to greenhouse gas emission limitations or emissions allowance purchase requirements in the future. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on our business, financial condition and results of operations.
 
Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and natural gas production. In our industry, underground injection not only allows us to economically dispose of produced water, but if injected into an oil bearing zone, it can increase the oil production from such zone. The SDWA establishes a regulatory framework for underground injection, the primary objective of which is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. The disposal of hazardous waste by underground injection is subject to stricter requirements than the disposal of produced water. We currently do not own or operate any underground injection wells, but may do so in the future. Failure to obtain, or abide by, the requirements for the issuance of necessary permits could subject us to civil and/or criminal enforcement actions and penalties.
 
Oil and natural gas exploration and production, operations and other activities have been conducted at some of our properties by previous owners and operators. Materials from these operations remain on some of the properties, and, in some instances, may require remediation. In addition, we occasionally must agree to indemnify sellers of producing properties from whom we acquire reserves against some of the liability for environmental claims associated with these properties. We cannot assure you that the costs we incur for compliance with environmental regulations and remediating previously or currently owned or operated properties will not result in material expenditures that adversely affect our profitability.
 
Additionally, in the course of our routine oil and natural gas operations, surface spills and leaks, including casing leaks, of oil or other materials will occur, and we will incur costs for waste handling and environmental compliance. It is also possible that our oil and natural gas operations may require us to manage NORM. NORM is present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes in contact with crude oil and natural gas production and processing streams. Some states, including Texas, have enacted regulations governing the handling, treatment, storage and disposal of NORM. Moreover, we will be able to control directly the operations of only those wells for which we act as the operator. Despite our lack of control over wells owned by us but operated by others, the failure of the operator to comply with the applicable environmental regulations may, in certain circumstances, be attributable to us.
 
We are subject to the requirements of OSHA and comparable state statutes. The OSHA Hazard Communication Standard, the “community right-to-know” regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize information about hazardous materials used, released or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in OSHA workplace standards.
 
We cannot assure you that more stringent laws and regulations protecting the environment will not be adopted or that we will not otherwise incur material expenses in connection with environmental laws and regulations in the future. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and, thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. We may be unable to pass on such increased compliance costs to our customers. Moreover, accidental releases or spills may occur in the course of our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such releases or spills, including any third party claims for damage to property, natural resources or persons.
 
We maintain insurance against some, but not all, potential risks and losses associated with our industry and operations. We do not currently carry business interruption insurance. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could materially adversely affect our financial condition and results of operations.
 
Hydraulic Fracturing Regulation
 
We use hydraulic fracturing as a means to maximize the productivity of our oil and natural gas wells in most wells that we drill and complete. Although average drilling and completion costs for each area will vary, as will the cost of each well within a given area, on average approximately 60% of the drilling and completion costs for our horizontal wells are associated with hydraulic fracturing activities. These costs are treated in the same way that all other costs of drilling and completion of our wells are treated and are built into and funded through our normal capital expenditures budget.
 
Hydraulic fracturing technology, which has been used by the oil and natural gas industry for more than 60 years and is constantly being enhanced, enables companies to produce crude oil and natural gas that would otherwise not be recovered. Specifically, hydraulic fracturing is a process in which pressurized fluid is pumped into underground formations to create tiny fractures or spaces that allow crude oil and natural gas to flow from the reservoir into the well so that it can be brought to the surface. The makeup of the fluid used in the hydraulic fracturing process is typically more than 99% water and sand, and less than 1% highly diluted chemical additives. While the majority of the sand remains underground to hold open the fractures, a significant percentage of the water and chemical additives flow back and are then either recycled or safely disposed of at sites that are approved and permitted by the appropriate regulatory authorities. Hydraulic fracturing generally takes place thousands of feet underground, a considerable distance below any drinking water aquifers, and there are impermeable layers of rock between the area fractured and the water aquifers.
 
Recently, there has been increasing regulatory scrutiny of hydraulic fracturing, which is generally exempted from regulation as underground injection on the federal level pursuant to the SDWA. However, the U.S. Senate and House of Representatives have considered legislation to repeal this exemption. If enacted, these proposals would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations, and meet plugging and abandonment requirements. These legislative proposals have also contained language to require the reporting and public disclosure of chemicals used in the fracturing process. If the exemption for hydraulic fracturing is removed from the SDWA, or if other legislation is enacted at the federal, state or local level, any restrictions on the use of hydraulic fracturing contained in any such legislation could have a significant impact on our business, financial condition and results of operations.
 
In addition, at the federal level and in some states, there has been a push to place additional regulatory burdens upon hydraulic fracturing activities. Certain bills have been introduced in the Senate and the House of Representatives that, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance. At the state level, Wyoming and Texas, for example, have enacted requirements for the disclosure of the composition of the fluids used in hydraulic fracturing. On June 17, 2011, Texas signed into law a mandate for public disclosure of the chemicals that operators use during hydraulic fracturing in Texas. The law went into effect September 1, 2011. State regulators have until 2013 to complete implementing rules. In addition, several local governments in Texas have imposed temporary moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address hydraulic fracturing activities. Additional burdens upon hydraulic fracturing, such as reporting requirements or permitting requirements for the hydraulic fracturing activity, will result in additional expense and delay in our operations.
 
We are not able to predict the timing, scope and effect of any currently proposed or future laws or regulations regarding hydraulic fracturing, but the direct and indirect costs of such laws and regulations (if enacted) could materially and adversely affect our business, financial conditions and results of operations. See “Risk Factors,” including “Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured” and "Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and water disposal could result in creased costs and additional operating restrictions or delays."
 
International Regulation
 
Our anticipated future exploration and production operations outside the U.S. will be subject to various types of regulations imposed by the respective governments of the countries in which our operations may be conducted and that may affect our operations and costs. We currently have no operations outside of the U.S. We have not yet assessed the scope and effect of any currently proposed or future foreign laws, regulations or treaties, including those regarding climate change and hydraulic fracturing, but the direct and indirect costs of such laws, regulations and treaties (if enacted) could materially and adversely affect our business, results of operations, financial condition and competitive position.
 
Insurance
 
Our oil and gas properties are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, implosions, fires and oil spills. These conditions can cause:
 
damage to or destruction of property, equipment and the environment; and
personal injury or loss of life; and,
suspension of operations.
 
We maintain insurance coverage that we believe to be customary in the industry against these types of hazards. However, we may not be able to maintain adequate insurance in the future at rates we consider reasonable. In addition, our insurance is subject to coverage limits and some policies exclude coverage for damages resulting from environmental contamination. The occurrence of a significant event or adverse claim in excess of the insurance coverage that we maintain or that is not covered by insurance could have a material adverse effect on our financial condition and results of operations.
 
Patents and Licenses
 
In February 2009, we filed a provisional patent (application number 61/152,885) relating to the process and unique equipment related to our applied fluid jetting process ("AFJ"). In February 2010, the final patent application was submitted. This patent was approved by the U.S. Patent Office in September 2012. We are currently in the process of working with the inventor to assign the rights to the patent to us.
 
During 2009, we tested the AFJ process on wells in the Austin Chalk play in Central Texas operated by Reliance Oil & Gas, Inc., which we refer to as Reliance, and had some initial production success. We subsequently attempted to apply the process to third-party wells in West Texas and in Kentucky. Due to mechanical failures of the surface equipment, we were unable to achieve any lateral jetting in the down-hole environment. Currently, the AFJ rig and other support vehicles have been moved to a storage yard in Spring, Texas. The AFJ asset is a secondary, non-core business focus for our company and may not ever be commercialized.
 
Although we believe the applied fluid technology and related trade secrets may provide us with a competitive edge in the oil and gas service industry, we do not believe this technology to be core to our current business and we are currently not actively pursuing its development and commercialization. However, we are highly committed to protecting the technology. We cannot assure our investors that the scope of any protection we are able to secure for our technology will be adequate to protect such technology, or that we will have the financial resources to engage in litigation against parties who may infringe upon us or seek to rescind their agreements with us. We also cannot provide our investors with any degree of assurance regarding the possible independent development by others of technology similar to that which we have acquired, thereby possibly diminishing our competitive edge.
 
Employees
 
At December 31, 2012, we had 10 full-time employees. We believe that our relationships with our employees are satisfactory. No employee is covered by a collective bargaining agreement. In order to expand our operations in accordance with our business plan, we intend to hire additional employees with expertise in the areas of corporate development, petroleum engineering, geological and geophysical sciences and accounting, as well as hiring additional technical, operations and administrative staff. We are not currently able to estimate the number of employees that we will hire during the next twelve months since that number will depend upon the rate at which our operations expand and upon the extent to which we engage third parties to perform required services.
 
From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of geology and geophysics, construction, design, well site surveillance and supervision, permitting and environmental assessment and legal and income tax preparation and accounting services. Independent contractors, at our request, drill our wells and perform field and on-site production operation services for us, including pumping, maintenance, dispatching, inspection and testing.
 
GLOSSARY OF OIL AND NATURAL GAS TERMS
 
The following is a description of the meanings of some of the oil and natural gas terms used in this Annual Report.
 
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this Annual Report in reference to crude oil or other liquid hydrocarbons.
 
Bcf. An abbreviation for billion cubic feet. Unit used to measure large quantities of gas, approximately equal to 1 trillion Btu.
 
BOE. Barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids, to six Mcf of natural gas.
 
Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
 
Completion. The operations required to establish production of oil or natural gas from a wellbore, usually involving perforations, stimulation and/or installation of permanent equipment in the well or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
 
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
 
Conventional resources. Natural gas or oil that is produced by a well drilled into a geologic formation in which the reservoir and fluid characteristics permit the natural gas or oil to readily flow to the wellbore.
 
Developed acreage. The number of acres that are allocated or assignable to productive wells.
 
Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
Estimated ultimate recovery or EUR. Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.
 
Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
 
Farmin or farmout. An agreement under which the owner of a working interest in an oil or natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farmin” while the interest transferred by the assignor is a “farmout.”
 
FERC. Federal Energy Regulatory Commission.
 
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 in which a working interest is owned.
 
Held by production. An oil and natural gas property under lease in which the lease continues to be in force after the primary term of the lease in accordance with its terms as a result of production from the property.
 
Horizontal drilling or well. A drilling operation in which a portion of the well is drilled horizontally within a productive or potentially productive formation. This operation typically yields a horizontal well that has the ability to produce higher volumes than a vertical well drilled in the same formation. A horizontal well is designed to replace multiple vertical wells, resulting in lower capital expenditures for draining like acreage and limiting surface disruption.
 
Liquids. Liquids, or natural gas liquids, are marketable liquid products including ethane, propane, butane and pentane resulting from the further processing of liquefiable hydrocarbons separated from raw natural gas by a natural gas processing facility.
 
MBbl. One thousand barrels of crude oil or other liquid hydrocarbons.
 
Mcf. One thousand cubic feet of natural gas.
 
MMcf. One million cubic feet of natural gas.
 
MMBtu. One million British thermal units.
 
Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells.
 
Net revenue interest. The interest that defines the percentage of revenue that an owner of a well receives from the sale of oil, natural gas and/or natural gas liquids that are produced from the well.
 
NYMEX. New York Mercantile Exchange.
 
Permeability. A reference to the ability of oil and/or natural gas to flow through a reservoir.
 
Petrophysical analysis. The interpretation of well log measurements, obtained from a string of electronic tools inserted into the borehole, and from core measurements, in which rock samples are retrieved from the subsurface, then combining these measurements with other relevant geological and geophysical information to describe the reservoir rock properties.
 
Play. A set of known or postulated oil and/or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, migration pathways, timing, trapping mechanism and hydrocarbon type.
 
Possible reserves. Additional reserves that are less certain to be recognized than probable reserves.
 
Probable reserves. Additional reserves that are less certain to be recognized than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered.
 
Producing well, production well or productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the well’s production exceed production-related expenses and taxes.
 
Properties. Natural gas and oil wells, production and related equipment and facilities and natural gas, oil or other mineral fee, leasehold and related interests.
 
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is considered to have potential for the discovery of commercial hydrocarbons.
 
Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
 
 
Proved reserves. Reserves of oil and natural gas that have been proved to a high degree of certainty by analysis of the producing history of a reservoir and/or by volumetric analysis of adequate geological and engineering data.
 
Proved undeveloped reserves. 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.
 
Repeatability. The potential ability to drill multiple wells within a prospect or trend.
 
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.
 
Royalty interest. An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.
 
2-D seismic. The method by which a cross-section of the earth’s subsurface is created through the interpretation of reflecting seismic data collected along a single source profile.
 
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 2-D seismic surveys and contribute significantly to field appraisal, exploitation and production.
 
Trend. A region of oil and/or natural gas production, the geographic limits of which have not been fully defined, having geological characteristics that have been ascertained through supporting geological, geophysical or other data to contain the potential for oil and/or natural gas reserves in a particular formation or series of formations.
 
Unconventional resource play. A set of known or postulated oil and or natural gas resources or reserves warranting further exploration which are extracted from (a) low-permeability sandstone and shale formations and (b) coalbed methane. These plays require the application of advanced technology to extract the oil and natural gas resources.
 
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. Undeveloped acreage is usually considered to be all acreage that is not allocated or assignable to productive wells.
 
Unproved and unevaluated properties. Refers to properties where no drilling or other actions have been undertaken that permit such property to be classified as proved.
 
Vertical well. A hole drilled vertically into the earth from which oil, natural gas or water flows or is pumped.
 
Volumetric reserve analysis. A technique used to estimate the amount of recoverable oil and natural gas. It involves calculating the volume of reservoir rock and adjusting that volume for the rock porosity, hydrocarbon saturation, formation volume factor and recovery factor.
 
Wellbore. The hole made by a well.
 
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.
 
An investment in our common stock involves a high degree of risk. You should carefully consider the risks described below as well as the other information in this filing before deciding to invest in our company. Any of the risk factors described below could significantly and adversely affect our business, prospects, financial condition and results of operations. Additional risks and uncertainties not currently known or that are currently considered to be immaterial may also materially and adversely affect our business, prospects, financial condition and results of operations. As a result, the trading price or value of our common stock could be materially adversely affected and you may lose all or part of your investment.
 
 
Risks Related to the Oil and Natural Gas Industry and Our Business
 
We have a limited operating history and expect to continue to incur losses for an indeterminable period of time.
 
We have a limited operating history and are engaged in the initial stages of exploration, development and exploitation of our leasehold acreage and will continue to be so until commencement of substantial production from our oil and natural gas properties, which will depend upon successful drilling results, additional and timely capital funding, and access to suitable infrastructure. Companies in their initial stages of development face substantial business risks and may suffer significant losses. We have generated substantial net losses and negative cash flows from operating activities in the past and expect to continue to incur substantial net losses as we continue our drilling program. In considering an investment in our common stock, you should consider that there is only limited historical and financial operating information available upon which to base your evaluation of our performance. In addition, the accompanying consolidated financial statements have been prepared on a going concern basis, which contemplates the realization of assets and liquidation of liabilities in the normal course of business. The Company has incurred losses from operations of $12,776,688 from the date of inception (February 9, 2011) through December 31, 2012. Additionally, the Company is dependent on obtaining additional debt and/or equity financing to roll-out and scale its planned principal business operations. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters consist principally of seeking additional debt and/or equity financing combined with expected cash flows from current oil and gas assets held and additional oil and gas assets that it may acquire. There can be no assurance that the Company’s efforts will be successful. The financial statements do not include any adjustments that may result from the outcome of this uncertainty. We face challenges and uncertainties in financial planning as a result of the unavailability of historical data and uncertainties regarding the nature, scope and results of our future activities. New companies must develop successful business relationships, establish operating procedures, hire staff, install management information and other systems, establish facilities and obtain licenses, as well as take other measures necessary to conduct their intended business activities. We may not be successful in implementing our business strategies or in completing the development of the infrastructure necessary to conduct our business as planned. In the event that one or more of our drilling programs is not completed or is delayed or terminated, our operating results will be adversely affected and our operations will differ materially from the activities described in this Annual Report. As a result of industry factors or factors relating specifically to us, we may have to change our methods of conducting business, which may cause a material adverse effect on our results of operations and financial condition. The uncertainty and risks described in this Annual Report may impede our ability to economically find, develop, exploit and acquire oil and natural gas reserves. As a result, we may not be able to achieve or sustain profitability or positive cash flows provided by our operating activities in the future.
 
Drilling for and producing oil and natural gas are highly speculative and involve a high degree of risk, with many uncertainties that could adversely affect our business. We have not recorded significant proved reserves, and areas that we decide to drill may not yield oil or natural gas in commercial quantities or at all.
 
Exploring for and developing hydrocarbon reserves involves a high degree of operational and financial risk, which precludes us from definitively predicting the costs involved and time required to reach certain objectives. Our potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation before they can be drilled. The budgeted costs of planning, drilling, completing and operating wells are often exceeded and such costs can increase significantly due to various complications that may arise during the drilling and operating processes. Before a well is spud, we may incur significant geological and geophysical (seismic) costs, which are incurred whether a well eventually produces commercial quantities of hydrocarbons or is drilled at all. Exploration wells bear a much greater risk of loss than development wells. The analogies we draw from available data from other wells, more fully explored locations or producing fields may not be applicable to our drilling locations. If our actual drilling and development costs are significantly more than our estimated costs, we may not be able to continue our operations as proposed and could be forced to modify our drilling plans accordingly.
 
If we decide to drill a certain location, there is a risk that no commercially productive oil or natural gas reservoirs will be found or produced. We may drill or participate in new wells that are not productive. We may drill wells that are productive, but that do not produce sufficient net revenues to return a profit after drilling, operating and other costs. There is no way to predict in advance of drilling and testing whether any particular location will yield oil or natural gas in sufficient quantities to recover exploration, drilling or completion costs or to be economically viable. Even if sufficient amounts of oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while drilling or completing the well, resulting in a reduction in production and reserves from the well or abandonment of the well. Whether a well is ultimately productive and profitable depends on a number of additional factors, including the following:
 
general economic and industry conditions, including the prices received for oil and natural gas;
shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel;
potential drainage by operators on adjacent properties;
loss of or damage to oilfield development and service tools;
problems with title to the underlying properties;
increases in severance taxes;
adverse weather conditions that delay drilling activities or cause producing wells to be shut down;
domestic and foreign governmental regulations; and
proximity to and capacity of transportation facilities.
 
 
If we do not drill productive and profitable wells in the future, our business, financial condition and results of operations could be materially and adversely affected.
 
Our success is dependent on the prices of oil and natural gas. Low oil or natural gas prices and the substantial volatility in these prices may adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure requirements and financial obligations.
 
The prices we receive for our oil and natural gas heavily influence our revenue, profitability, cash flow available for capital expenditures, 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. For example, for the four years ended December 31, 2012, the NYMEX — WTI oil price ranged from a high of $120.92 per Bbl to a low of $33.87 per Bbl, while the NYMEX — Henry Hub natural gas price ranged from a high of $8.26 per MMBtu to a low of $1.82 per MMBtu. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors. These factors include the following:

the domestic and foreign supply of oil and natural gas;
the domestic and foreign demand for oil and natural gas;
the prices and availability of competitors’ supplies of oil and natural gas;
the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls;
the price and quantity of foreign imports of oil and natural gas;
the impact of U.S. dollar exchange rates on oil and natural gas prices;
domestic and foreign governmental regulations and taxes;
speculative trading of oil and natural gas futures contracts;
localized supply and demand fundamentals, including the availability, proximity and capacity of gathering and transportation systems for natural gas;
the availability of refining capacity;
the prices and availability of alternative fuel sources;
weather conditions and natural disasters;
political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America;
the continued threat of terrorism and the impact of military action and civil unrest;
public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;
the level of global oil and natural gas inventories and exploration and production activity;
authorization of exports from the Unites States of liquefied natural gas;
the impact of energy conservation efforts;
technological advances affecting energy consumption; and
overall worldwide economic conditions.
 
Declines in oil or natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas that we can produce economically. Should natural gas or oil prices decrease from current levels and remain there for an extended period of time, we may elect in the future to delay some of our exploration and development plans for our prospects, or to cease exploration or development activities on certain prospects due to the anticipated unfavorable economics from such activities, each of which would have a material adverse effect on our business, financial condition and results of operations.
 
Our exploration, development and exploitation projects require substantial capital expenditures that may exceed our cash flows from operations and potential borrowings, and we may be unable to obtain needed capital on satisfactory terms, which could adversely affect our future growth.
 
Our exploration and development activities are capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. The net proceeds we may receive from future debt and/or equity offerings, our operating cash flows and future potential borrowings may not be adequate to fund our future acquisitions or future capital expenditure requirements. The rate of our future growth may be dependent, at least in part, on our ability to access capital at rates and on terms we determine to be acceptable.
 
 
Our cash flows from operations and access to capital are subject to a number of variables, including:
 
our estimated proved oil and natural gas reserves;
the amount of oil and natural gas we produce from existing wells;
the prices at which we sell our production;
the costs of developing and producing our oil and natural gas reserves;
our ability to acquire, locate and produce new reserves;
the ability and willingness of banks to lend to us; and
our ability to access the equity and debt capital markets.
 
In addition, future events, such as terrorist attacks, wars or combat peace-keeping missions, financial market disruptions, general economic recessions, oil and natural gas industry recessions, large company bankruptcies, accounting scandals, overstated reserves estimates by major public oil companies and disruptions in the financial and capital markets have caused financial institutions, credit rating agencies and the public to more closely review the financial statements, capital structures and earnings of public companies, including energy companies. Such events have constrained the capital available to the energy industry in the past, and such events or similar events could adversely affect our access to funding for our operations in the future.
 
If our revenues decrease as a result of lower oil and natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels, further develop and exploit our current properties or invest in additional exploration opportunities. Alternatively, a significant improvement in oil and natural gas prices or other factors could result in an increase in our capital expenditures and we may be required to alter or increase our capitalization substantially through the issuance of debt or equity securities, the sale of production payments, the sale or farm out of interests in our assets, the borrowing of funds or otherwise to meet any increase in capital needs. If we are unable to raise additional capital from available sources at acceptable terms, our business, financial condition and results of operations could be adversely affected. Further, future debt financings may require that a portion of our cash flows provided by operating activities be used for the payment of principal and interest on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Debt financing may involve covenants that restrict our business activities. If we succeed in selling additional equity securities to raise funds, at such time the ownership percentage of our existing stockholders would be diluted, and new investors may demand rights, preferences or privileges senior to those of existing stockholders. If we choose to farm-out interests in our prospects, we may lose operating control over such prospects.
 
Our oil and natural gas reserves are estimated and may not reflect the actual volumes of oil and natural gas we will receive, and significant inaccuracies in these reserves estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
 
The process of estimating accumulations of oil and natural gas is complex and is not exact, due to numerous inherent uncertainties. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions related to, among other things, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserves estimate is a function of:
 
the quality and quantity of available data;
the interpretation of that data;
the judgment of the persons preparing the estimate; and
the accuracy of the assumptions.
 
 
The accuracy of any estimates of proved reserves generally increases with the length of the production history. Due to the limited production history of our properties, the estimates of future production associated with these properties may be subject to greater variance to actual production than would be the case with properties having a longer production history. As our wells produce over time and more data are available, the estimated proved reserves will be re-determined on at least an annual basis and may be adjusted to reflect new information based upon our actual production history, results of exploration and development, prevailing oil and natural gas prices and other factors.
 
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas most likely will vary from our estimates. It is possible that future production declines in our wells may be greater than we have estimated. Any significant variance to our estimates could materially affect the quantities and present value of our reserves.
 
There is no guarantee that the proposed acquisition of the Mississippian asset will be completed, and the failure to acquire the Mississippian asset could adversely affect our business and results of operations.
 
We have signed a binding agreement to acquire 100% operated working interests in the Mississippian Lime covering approximately 7,006 gross (6,763 net) acres located in Kansas. We anticipate that the acquisition will occur during March 2013. However, the completion of the Mississippian acquisition is subject to customary closing conditions, and our ability to secure sufficient financing, of which there can be no assurances. We cannot guarantee that the acquisition will occur in March 2013 or at any time thereafter. The Mississippian asset represents a significant business opportunity for us and, if we fail to acquire the Mississippian asset, our anticipated business and results of operations could be adversely affected and there is no guarantee that we could subsequently acquire an equally attractive oil play.
 
We may have accidents, equipment failures or mechanical problems while drilling or completing wells or in production activities, which could adversely affect our business.
 
While we are drilling and completing wells or involved in production activities, we may have accidents or experience equipment failures or mechanical problems in a well that cause us to be unable to drill and complete the well or to continue to produce the well according to our plans. We may also damage a potentially hydrocarbon-bearing formation during drilling and completion operations. Such incidents may result in a reduction of our production and reserves from the well or in abandonment of the well.
 
Our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured.
 
There are numerous operational hazards inherent in oil and natural gas exploration, development, production and gathering, including:
 
unusual or unexpected geologic formations;
natural disasters;
adverse weather conditions;
unanticipated pressures;
loss of drilling fluid circulation;
blowouts where oil or natural gas flows uncontrolled at a wellhead;
cratering or collapse of the formation;
pipe or cement leaks, failures or casing collapses;
fires or explosions;
releases of hazardous substances or other waste materials that cause environmental damage;
pressures or irregularities in formations; and
equipment failures or accidents.
  
In addition, there is an inherent risk of incurring significant environmental costs and liabilities in the performance of our operations, some of which may be material, due to our handling of petroleum hydrocarbons and wastes, our emissions to air and water, the underground injection or other disposal of our wastes, the use of hydraulic fracturing fluids and historical industry operations and waste disposal practices.
 
Any of these or other similar occurrences could result in the disruption or impairment of our operations, substantial repair costs, personal injury or loss of human life, significant damage to property, environmental pollution and substantial revenue losses. The location of our wells, gathering systems, pipelines and other facilities near populated areas, including residential areas, commercial business centers and industrial sites, could significantly increase the level of damages resulting from these risks.
 
 
Insurance against all operational risks is not available to us. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. Also, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could, therefore, occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Moreover, insurance may not be available in the future at commercially reasonable prices or on commercially reasonable terms. Changes in the insurance markets due to various factors may make it more difficult for us to obtain certain types of coverage in the future. As a result, we may not be able to obtain the levels or types of insurance we would otherwise have obtained prior to these market changes, and the insurance coverage we do obtain may not cover certain hazards or all potential losses that are currently covered, and may be subject to large deductibles. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our business, financial condition and results of operations.
 
Our strategy as an onshore unconventional resource player may result in operations concentrated in certain geographic areas and may increase our exposure to many of the risks described in this Annual Report.
 
We currently anticipate that our initial operations will be concentrated in the States of Colorado, Texas, Kansas and Oklahoma. This anticipated concentration may increase the potential impact of many of the risks described in this Annual Report. For example, we may have greater exposure to regulatory actions impacting these four states, natural disasters in these states, competition for equipment, services and materials available in the areas and access to infrastructure and markets in those areas.
 
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.
 
The rate of production from our oil and natural gas properties will decline as our reserves are depleted. Our future oil and natural gas reserves and production and, therefore, our income and cash flow, are highly dependent on our success in (a) efficiently developing and exploiting our current reserves on properties owned by us or by other persons or entities and (b) economically finding or acquiring additional oil and natural gas producing properties. In the future, we may have difficulty acquiring new properties. During periods of low oil and/or natural gas prices, it will become more difficult to raise the capital necessary to finance expansion activities. If we are unable to replace our production, our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
 
Our strategy includes acquisitions of oil and natural gas properties, and our failure to identify or complete future acquisitions successfully could reduce our earnings and hamper our growth.
 
We may be unable to identify properties for acquisition or to make acquisitions on terms that we consider economically acceptable. There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. The completion and pursuit of acquisitions may be dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to grow through acquisitions will require us to continue to invest in operations, financial and management information systems and to attract, retain, motivate and effectively manage our employees. The inability to manage the integration of acquisitions effectively could reduce our focus on subsequent acquisitions and current operations, and could negatively impact our results of operations and growth potential. Our financial position and results of operations may fluctuate significantly from period to period as a result of the completion of significant acquisitions during particular periods. If we are not successful in identifying or acquiring any material property interests, our earnings could be reduced and our growth could be restricted.
 
We may engage in bidding and negotiating to complete successful acquisitions. We may be required to alter or increase substantially our capitalization to finance these acquisitions through the use of cash on hand, the issuance of debt or equity securities, the sale of production payments, the sale of non-strategic assets, the borrowing of funds or otherwise. If we were to proceed with one or more acquisitions involving the issuance of our common stock, our shareholders would suffer dilution of their interests. Furthermore, our decision to acquire properties that are substantially different in operating or geologic characteristics or geographic locations from areas with which our staff is familiar may impact our productivity in such areas.
 
We may purchase oil and natural gas properties with liabilities or risks that we did not know about or that we did not assess correctly, and, as a result, we could be subject to liabilities that could adversely affect our results of operations.
 
Before acquiring oil and natural gas properties, we estimate the reserves, future oil and natural gas prices, operating costs, potential environmental liabilities and other factors relating to the properties. However, our review involves many assumptions and estimates, and their accuracy is inherently uncertain. As a result, we may not discover all existing or potential problems associated with the properties we buy. We may not become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We do not generally perform inspections on every well or property, and we may not be able to observe mechanical and environmental problems even when we conduct an inspection. The seller may not be willing or financially able to give us contractual protection against any identified problems, and we may decide to assume environmental and other liabilities in connection with properties we acquire. If we acquire properties with risks or liabilities we did not know about or that we did not assess correctly, our business, financial condition and results of operations could be adversely affected as we settle claims and incur cleanup costs related to these liabilities.
 
 
We may incur losses or costs as a result of title deficiencies in the properties in which we invest.
 
If an examination of the title history of a property that we have purchased reveals an oil and natural gas lease has been purchased in error from a person who is not the owner of the property, our interest would be worthless. In such an instance, the amount paid for such oil and natural gas lease as well as any royalties paid pursuant to the terms of the lease prior to the discovery of the title defect would be lost.
 
Prior to the drilling of an oil and natural gas well, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil and natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, and such curative work entails expense. Our failure to cure any title defects may adversely impact our ability in the future to increase production and reserves. In the future, we may suffer a monetary loss from title defects or title failure. Additionally, unproved and unevaluated acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss which could adversely affect our business, financial condition and results of operations.
 
Our identified drilling locations are scheduled over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
 
Our management team has identified and scheduled drilling locations in our operating areas over a multi-year period. Our ability to drill and develop these locations depends on a number of factors, including the availability of equipment and capital, approval by regulators, seasonal conditions, oil and natural gas prices, assessment of risks, costs and drilling results. The final determination on whether to drill any of these locations will be dependent upon the factors described elsewhere in this Annual Report as well as, to some degree, the results of our drilling activities with respect to our established drilling locations. Because of these uncertainties, we do not know if the drilling locations we have identified will be drilled within our expected timeframe or at all or if we will be able to economically produce hydrocarbons from these or any other potential drilling locations. Our actual drilling activities may be materially different from our current expectations, which could adversely affect our business, financial condition and results of operations.
 
We currently own only a limited amount of seismic and other geological data and may have difficulty obtaining additional data at a reasonable cost, which could adversely affect our future results of operations.
 
We currently own only a limited amount of seismic and other geological data to assist us in exploration and development activities. We intend to obtain access to additional data in our areas of interest through licensing arrangements with companies that own or have access to that data or by paying to obtain that data directly. Seismic and geological data can be expensive to license or obtain. We may not be able to license or obtain such data at an acceptable cost.
 
The unavailability or high cost of drilling rigs, completion equipment and services, supplies and personnel, including hydraulic fracturing equipment and personnel, could adversely affect our ability to establish and execute exploration and development plans within budget and on a timely basis, which could have a material adverse effect on our business, financial condition and results of operations.
 
Shortages or the high cost of drilling rigs, completion equipment and services, supplies or personnel could delay or adversely affect our operations. When drilling activity in the U.S. increases, associated costs typically also increase, including those costs related to drilling rigs, equipment, supplies and personnel and the services and products of other vendors to the industry. These costs may increase, and necessary equipment and services may become unavailable to us at economical prices. Should this increase in costs occur, we may delay drilling activities, which may limit our ability to establish and replace reserves, or we may incur these higher costs, which may negatively affect our business, financial condition and results of operations.
 
In addition, the demand for hydraulic fracturing services currently exceeds the availability of fracturing equipment and crews across the industry and in our operating areas in particular. The accelerated wear and tear of hydraulic fracturing equipment due to its deployment in unconventional oil and natural gas fields characterized by longer lateral lengths and larger numbers of fracturing stages has further amplified this equipment and crew shortage. If demand for fracturing services continues to increase or the supply of fracturing equipment and crews decreases, then higher costs could result and could adversely affect our business, financial condition and results of operations.
 
We have limited control over activities on properties we do not operate.
 
We are not the operator on some of our properties and, as a result, our ability to exercise influence over the operations of these properties or their associated costs is limited. Our dependence on the operators and other working interest owners of these projects and our limited ability to influence operations and associated costs or control the risks could materially and adversely affect the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of our drilling and development activities on properties operated by others therefore depends upon a number of factors, including:
 
 
timing and amount of capital expenditures;
the operator’s expertise and financial resources;
the rate of production of reserves, if any;
approval of other participants in drilling wells; and
selection of technology.
 
The marketability of our production is dependent upon oil and natural gas gathering and transportation facilities owned and operated by third parties, and the unavailability of satisfactory oil and natural gas transportation arrangements would have a material adverse effect on our revenue.
 
The unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay production from our wells. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for, and supply of, oil and natural gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain these services on acceptable terms could materially harm our business. We may be required to shut-in wells for lack of a market or because of inadequacy or unavailability of pipeline or gathering system capacity. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver our production to market. Furthermore, if we were required to shut-in wells we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. We do not expect to purchase firm transportation capacity on third-party facilities. Therefore, we expect the transportation of our production to be generally interruptible in nature and lower in priority to those having firm transportation arrangements.
 
The disruption of third-party facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. The third parties control when or if such facilities are restored and what prices will be charged. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.
 
Strategic relationships, including with MIE Holdings and STXRA, upon which we may rely are subject to risks and uncertainties which may adversely affect our business, financial conditions and results of operations.
 
Our ability to explore, develop and produce oil and natural gas resources successfully and acquire oil and natural gas interests and acreage depends on our developing and maintaining close working relationships with industry participants and on our ability to select and evaluate suitable acquisition opportunities in a highly competitive environment. These realities are subject to risks and uncertainties that may adversely affect our business, financial condition and results of operations.
 
To develop our business, we will endeavor to use the business relationships of our management and board to enter into strategic relationships, which may take the form of contractual arrangements with other oil and natural gas companies, including those that supply equipment and other resources that we expect to use in our business. For example, we have entered into a strategic relationship with MIE Holdings with respect to several of our oil and natural gas interests, and have both retained STXRA as a key advisor for our exploration and drilling efforts, and formed Pacific Energy Technology Services, LLC as a jointly-owned technical services venture with STXRA to provide acquisition, engineering, and oil drilling and completion technology services in the U.S. and abroad, as discussed in greater detail above under “Business.” We may not be able to establish these 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 incur in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business, financial condition and results of operations may be adversely affected.
 
An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price we receive for our production could adversely affect our business, financial condition and results of operations.
 
The prices that we will receive for our oil and natural gas production sometimes may reflect a discount to the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the benchmark price and the prices we receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price we receive could adversely affect our business, financial condition and results of operations. We do not have, and may not have in the future, any derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we will be exposed to any increase in such differentials.
 
 
Our success depends, to a large extent, on our ability to retain our key personnel, including our Chairman of the Board, Chief Executive Officer and President, and the loss of any of our key personnel could disrupt our business operations.
 
Investors in our common stock must rely upon the ability, expertise, judgment and discretion of our management and the success of our technical team in identifying, evaluating and developing prospects and reserves. Our performance and success are dependent to a large extent on the efforts and continued employment of our management and technical personnel, including our Chairman, President and Chief Executive Officer, Frank C. Ingriselli. We do not believe that they could be quickly replaced with personnel of equal experience and capabilities, and their successors may not be as effective. If Mr. Ingriselli or any of our other key personnel resign or become unable to continue in their present roles and if they are not adequately replaced, our business operations could be adversely affected. Except for a $3 million insurance policy on the life of Mr. Ingriselli, we do not currently maintain any insurance against the loss of any of these individuals.
 
We have an active board of directors that meets several times throughout the year and is intimately involved in our business and the determination of our operational strategies. Members of our board of directors work closely with management to identify potential prospects, acquisitions and areas for further development. Three of our directors have been involved with us since the inception of Pacific Energy Development and have a deep understanding of our operations and culture. If any of our directors resign or become unable to continue in their present role, it may be difficult to find replacements with the same knowledge and experience and as a result, our operations may be adversely affected.
 
We may have difficulty managing growth in our business, which could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a timely fashion.
 
Because of our small size, growth in accordance with our business plans, if achieved, will place a significant strain on our financial, technical, operational and management resources. As we expand our activities, including our planned increase in oil exploration, development and production, and increase the number of projects we are evaluating or in which we participate, there will be additional demands on our financial, technical and management resources. The failure to continue to upgrade our technical, administrative, operating and financial control systems or the occurrence of unexpected expansion difficulties, including the inability to recruit and retain experienced managers, geoscientists, petroleum engineers and landmen could have a material adverse effect on our business, financial condition and results of operations and our ability to execute our business plan in a timely fashion.
 
Financial difficulties encountered by our oil and natural gas purchasers, third-party operators or other third parties could decrease our cash flow from operations and adversely affect the exploration and development of our prospects and assets.
 
We will derive substantially all of our revenues from the sale of our oil and natural gas to unaffiliated third-party purchasers, independent marketing companies and mid-stream companies. Any delays in payments from our purchasers caused by financial problems encountered by them will have an immediate negative effect on our results of operations.
 
Liquidity and cash flow problems encountered by our working interest co-owners or the third-party operators of our non-operated properties may prevent or delay the drilling of a well or the development of a project. Our working interest co-owners may be unwilling or unable to pay their share of the costs of projects as they become due. In the case of a farmout party, we would have to find a new farmout party or obtain alternative funding in order to complete the exploration and development of the prospects subject to a farmout agreement. In the case of a working interest owner, we could be required to pay the working interest owner’s share of the project costs. We cannot assure you that we would be able to obtain the capital necessary to fund either of these contingencies or that we would be able to find a new farmout party.
 
The calculated present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
 
You should not assume that the present value of future net cash flows included in this Annual Report is the current market value of our estimated proved oil and natural gas reserves. We generally base the estimated discounted future net cash flows from proved reserves on current costs held constant over time without escalation and on commodity prices using an unweighted arithmetic average of first-day-of-the-month index prices, appropriately adjusted, for the 12-month period immediately preceding the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs used for these estimates and will be affected by factors such as:
 
actual prices we receive for oil and natural gas;
actual cost and timing of development and production expenditures;
the amount and timing of actual production; and
changes in governmental regulations or taxation.
 
 
In addition, the 10% discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under GAAP is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.
 
We may incur additional indebtedness which could reduce our financial flexibility, increase interest expense and adversely impact our operations and our unit costs.
 
In the future, we may incur significant amounts of additional indebtedness in order to make acquisitions or to develop our properties. Our level of indebtedness could affect our operations in several ways, including the following:
 
a significant portion of our cash flows could be used to service our indebtedness;
a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
any covenants contained in the agreements governing our outstanding indebtedness could limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments;
a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, may be able to take advantage of opportunities that our indebtedness may prevent us from pursuing; and
debt covenants to which we may agree may affect our flexibility in planning for, and reacting to, changes in the economy and in our industry.
 
A high level of indebtedness increases the risk that we may default on our debt obligations. We may not be able to generate sufficient cash flows to pay the principal or interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. If we do not have sufficient funds and are otherwise unable to arrange financing, we may have to sell significant assets or have a portion of our assets foreclosed upon which could have a material adverse effect on our business, financial condition and results of operations.
 
Competition in the oil and natural gas industry is intense, making it difficult for us to acquire properties, market oil and natural gas and secure trained personnel.
 
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, and many of our competitors have more established presences in the U.S. and the Pacific Rim than we have. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel has increased in recent years due to competition and may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business, financial condition and results of operations.
 
Our competitors may use superior technology and data resources that we may be unable to afford or that would require a costly investment by us in order to compete with them more effectively.
 
Our industry is subject to rapid and significant advancements in technology, including the introduction of new products and services using new technologies and databases. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. In addition, many of our competitors will have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that we will use or that we may implement in the future may become obsolete, and we may be adversely affected.
 
If we do not hedge our exposure to reductions in oil and natural gas prices, we may be subject to significant reductions in prices. Alternatively, we may use oil and natural gas price hedging contracts, which involve credit risk and may limit future revenues from price increases and result in significant fluctuations in our profitability.
 
 
In the event that we choose not to hedge our exposure to reductions in oil and natural gas prices by purchasing futures and by using other hedging strategies, we may be subject to significant reduction in prices which could have a material negative impact on our profitability. Alternatively, we may elect to use hedging transactions with respect to a portion of our oil and natural gas production to achieve more predictable cash flow and to reduce our exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use also may limit future revenues from price increases. Hedging transactions also involve the risk that the counterparty may be unable to satisfy its obligations.
 
We are subject to government regulation and liability, including complex environmental laws, which could require significant expenditures.
 
The exploration, development, production and sale of oil and natural gas in the U.S. are subject to many federal, state and local laws, rules and regulations, including complex environmental laws and regulations. Matters subject to regulation include discharge permits, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, taxation or environmental matters and health and safety criteria addressing worker protection. Under these laws and regulations, we may be required to make large expenditures that could materially adversely affect our business, financial condition and results of operations. These expenditures could include payments for:
 
personal injuries;
property damage;
containment and cleanup of oil and other spills;
the management and disposal of hazardous materials;
remediation and clean-up costs; and
other environmental damages.
 
We do not believe that full insurance coverage for all potential damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties, injunctive relief and/or the imposition of investigatory or other remedial obligations. Laws, rules and regulations protecting the environment have changed frequently and the changes often include increasingly stringent requirements. These laws, rules and regulations may impose liability on us for environmental damage and disposal of hazardous materials even if we were not negligent or at fault. We may also be found to be liable for the conduct of others or for acts that complied with applicable laws, rules or regulations at the time we performed those acts. These laws, rules and regulations are interpreted and enforced by numerous federal and state agencies. In addition, private parties, including the owners of properties upon which our wells are drilled or the owners of properties adjacent to or in close proximity to those properties, may also pursue legal actions against us based on alleged non-compliance with certain of these laws, rules and regulations.
 
Part of our strategy involves drilling in existing or emerging shale plays using some of the latest available horizontal drilling and completion techniques. The results of our planned exploratory drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production. As a result, we may incur material write-downs and the value of our undeveloped acreage could decline if drilling results are unsuccessful.
 
Our operations in the Eagle Ford and Niobrara, and anticipated operations in the Mississippian involve utilizing the latest drilling and completion techniques in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we may face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore and being able to run tools and other equipment consistently through the horizontal well bore. Risks that we may face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the well bore during completion operations and successfully cleaning out the well bore after completion of the final fracture stimulation stage.
 
The results of our drilling in new or emerging formations will be more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and consequently we are less able to predict future drilling results in these areas.
 
 
Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems and limited takeaway capacity or otherwise, and/or natural gas and oil prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.
 
Our acreage must be drilled before lease expiration, generally within three to five years, in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.
 
Our leases on oil and natural gas properties typically have a primary term of three to five years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres. As of December 31, 2012, we had leases representing 1,510 net acres expiring in 2013, 429 net acres expiring in 2014, 123 net acres expiring in 2015, and 95 net acres expiring thereafter in our Niobrara asset, and we had leases representing 26 net acres expiring in 2013 in our Eagle Ford asset (see “Undeveloped Acreage Expirations”). If our extension options expire and we have to renew such leases on new terms, we could incur significant cost increases, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.
 
Competition and regulation of hydraulic fracturing services and water disposal could impede our ability to develop our shale plays.
 
The unavailability or high cost of high pressure pumping services (or hydraulic fracturing services), chemicals, proppant, water and water disposal and related services and equipment could limit our ability to execute our exploration and development plans on a timely basis and within our budget. The oil and natural gas industry is experiencing a growing emphasis on the exploitation and development of shale natural gas and shale oil resource plays, which are dependent on hydraulic fracturing for economically successful development. Hydraulic fracturing in shale plays requires high pressure pumping service crews. A shortage of service crews or proppant, chemical, water or water disposal options, especially if this shortage occurred in southern Texas, southern Kansas, northern Oklahoma or eastern Colorado, could materially and adversely affect our operations and the timeliness of executing our development plans within our budget. There is significant regulatory uncertainty as some states have begun to regulate hydraulic fracturing and the U.S. Environmental Protection Agency is expected to release a progress report on its study of the impact of hydraulic fracturing on drinking water sources in early 2013, which could affect the current regulatory jurisdiction of the states and increase the cycle times and costs to receive permits, delay or possibly preclude receipt of permits in certain areas, impact water usage and waste water disposal and require chemical additives disclosures.
 
We are subject to federal, state and local taxes, and may become subject to new taxes or have eliminated or reduced certain federal income tax deductions currently available with respect to oil and natural gas exploration and production activities as a result of future legislation, which could adversely affect our business, financial condition and results of operations.
 
The federal, state and local governments in the areas in which we operate impose taxes on the oil and natural gas products we sell and, for many of our wells, sales and use taxes on significant portions of our drilling and operating costs. In the past, there has been a significant amount of discussion by legislators and presidential administrations concerning a variety of energy tax proposals. Many states have raised state taxes on energy sources, and additional increases may occur. Changes to tax laws that are applicable to us could adversely affect our business and our financial results.
 
Periodically, legislation is introduced to eliminate certain key U.S. federal income tax preferences currently available to oil and natural gas exploration and production companies. Such possible changes include, but are not limited to, (a) the repeal of the percentage depletion allowance for oil and natural gas properties, (b) the elimination of current deductions for intangible drilling and development costs, (c) the elimination of the deduction for certain U.S. production activities, and (d) the increase in the amortization period for geological and geophysical costs paid or incurred in connection with the exploration for, or development of, oil or natural gas within the U.S. It is unclear whether any such changes will actually be enacted or, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of the budget proposals or any other similar change in U.S. federal income tax law could affect certain tax deductions that are currently available with respect to oil and natural gas exploration and production activities and could negatively impact our business, financial condition and results of operations.
 
 
The derivatives legislation adopted by Congress, and implementation of that legislation by federal agencies, could have an adverse impact on our ability to hedge risks associated with our business.
 
On July 21, 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) which, among other things, sets forth the new framework for regulating certain derivative products including the commodity hedges of the type that we may elect to use, but many aspects of this law are subject to further rulemaking and will take effect over several years. As a result, it is difficult to anticipate the overall impact of the Dodd-Frank Act on our ability or willingness to enter into and maintain such commodity hedges and the terms of such hedges. There is a possibility that the Dodd-Frank Act could have a substantial and adverse impact on our ability to enter into and maintain these commodity hedges. In particular, the Dodd-Frank Act could result in the implementation of position limits and additional regulatory requirements on derivative arrangements, which could include new margin, reporting and clearing requirements. In addition, this legislation could have a substantial impact on our counterparties and may increase the cost of our derivative arrangements in the future.
 
If these types of commodity hedges become unavailable or uneconomic, our commodity price risk could increase, which would increase the volatility of revenues and may decrease the amount of credit available to us. Any limitations or changes in our use of derivative arrangements could also materially affect our future ability to conduct acquisitions.
 
Federal and state legislation and regulatory initiatives relating to hydraulic fracturing and water disposal could result in increased costs and additional operating restrictions or delays.
 
Congress has considered, but has not yet passed, legislation to amend the federal Safe Drinking Water Act to remove the exemption from restrictions on underground injection of fluids near drinking water sources granted to hydraulic fracturing operations and require reporting and disclosure of chemicals used by oil and natural gas companies in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand or other propping agents and chemicals under pressure into rock formations to stimulate natural gas production. We routinely use hydraulic fracturing to produce commercial quantities of oil, liquids and natural gas from shale formations. Sponsors of bills before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Such legislation, if adopted, could increase the possibility of litigation and establish an additional level of regulation at the federal level that could lead to operational delays or increased operating costs and could, and in all likelihood would, result in additional regulatory burdens, making it more difficult to perform hydraulic fracturing operations and increasing our costs of compliance.
 
In addition, certain members of Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, the U.S. Securities and Exchange Commission to investigate the natural-gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural-gas deposits in shales by means of hydraulic fracturing, and the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural-gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. The U.S. Government Accountability Office released its report on hydraulic fracturing in September 2012. Depending on the outcome of these studies, federal and state legislatures and agencies may seek to further regulate hydraulic fracturing activities.
 
The U.S. Environmental Protection Agency, or the EPA, is also involved in regulating hydraulic fracturing. On April 17, 2012, the EPA approved final rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. These rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion (REC) techniques developed in EPA’s Natural Gas STAR program along with pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (MACT) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently researching the effect these proposed rules could have on our business. While these rules have been finalized, many of the rule’s provisions will be phased-in over time, with the more stringent requirements like REC not becoming effective until 2015.
 
Moreover, the EPA is conducting a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on drinking water and groundwater. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution of a natural gas field in Wyoming, although this study remains subject to review and public comments. Consequently, even if federal legislation is not adopted soon or at all, the performance of the hydraulic fracturing study by the EPA could spur further action at a later date towards federal legislation and regulation of hydraulic fracturing or similar production operations.
 
 
In addition, a number of states are considering or have implemented more stringent regulatory requirements applicable to fracturing, which could include a moratorium on drilling and effectively prohibit further production of natural gas through the use of hydraulic fracturing or similar operations. For example, Texas has adopted legislation that requires the disclosure of information regarding the substances used in the hydraulic fracturing process to the Railroad Commission of Texas and the public. This legislation and any implementing regulation could increase our costs of compliance and doing business.
 
The adoption of new laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing and related water disposal processes could make it more difficult to complete oil and natural gas wells in shale formations. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, fracturing activities could become subject to additional permitting requirements, and also to attendant permitting delays and potential increases in cost, which could adversely affect our business, financial condition and results of operations.
 
Legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the natural gas, natural gas liquids and oil we produce while the physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
 
On December 15, 2009, the EPA published its final findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to public health and welfare because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has adopted regulations that would require a reduction in emissions of greenhouse gases from motor vehicles and permitting and presumably requiring a reduction in greenhouse gas emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. On November 30, 2010, the EPA released a final rule that expands its rule on reporting of greenhouse gas emissions to include owners and operators of petroleum and natural gas systems. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations. Further, various states have adopted legislation that seeks to control or reduce emissions of greenhouse gases from a wide range of sources. Any such legislation could adversely affect demand for the natural gas, oil and liquids that we produce.
 
Some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our exploration and production operations. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses, or costs that may result from potential physical effects of climate change.
 
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
 
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing, or fracking, processes. According to the Lower Colorado River Authority, during 2011, Texas experienced the lowest inflows of water of any year in recorded history. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing in order to protect local water supply. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
 
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
 
Oil and natural gas operations in our operating areas can be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures.
 
 
As a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to consider listing more than 250 species as endangered under the Endangered Species Act. The law prohibits the harming of endangered or threatened species, provides for habitat protection, and imposes stringent penalties for noncompliance. The final designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations, delays, or prohibitions on our exploration and production activities that could have an adverse impact on our ability to develop and produce our reserves.
 
Potential conflicts of interest could arise for certain members of our management team that hold management positions with other entities.
 
Frank C. Ingriselli, our Chairman of the Board and Chief Executive Officer, is also president and Chief Executive Officer of Global Venture Investments LLC and Michael L. Peterson, our Chief Financial Officer, is a managing partner of Pascal Management. We believe these positions require only an immaterial amount of Messrs. Ingriselli’s and Peterson’s time and will not conflict with each of their respective roles or responsibilities with our company. If either of these entities enters into one or more transactions with our company, or if either of these positions require significantly more time than currently anticipated, potential conflicts of interests could arise from Messrs. Ingriselli and Peterson performing services for us and these other entities.
 
Risks Related to Our Common Stock
 
The market price and trading volume of our common stock may be volatile.
 
The market price of our common stock could vary significantly as a result of a number of factors. In addition, the trading volume of our common stock may fluctuate and cause significant price variations to occur. If the market price of our common stock declines, you could lose a substantial part or all of your investment in our common stock. Factors that could affect our stock price or result in fluctuations in the market price or trading volume of our common stock include:
 
  
our actual or anticipated operating and financial performance and drilling locations, including reserves estimates;
 
  
quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and cash flows, or those of companies that are perceived to be similar to us;
 
  
changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts;
 
  
speculation in the press or investment community;
 
  
public reaction to our press releases, announcements and filings with the SEC;
 
  
sales of our common stock by us or other shareholders, or the perception that such sales may occur;
 
  
the limited amount of our freely tradable common stock available in the public marketplace;
 
  
general financial market conditions and oil and natural gas industry market conditions, including fluctuations in commodity prices;
 
  
the realization of any of the risk factors presented in this Annual Report;
 
  
the recruitment or departure of key personnel;
 
 
  
commencement of, or involvement in, litigation;
 
  
the prices of oil and natural gas;
 
  
the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;
 
  
changes in market valuations of companies similar to ours; and
 
  
domestic and international economic, legal and regulatory factors unrelated to our performance.
 
The stock markets in general have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.
 
An active liquid trading market for our common stock may not develop.
 
Our common stock currently trades on the OTC Bulletin Board, although our common stock’s trading volume is very low. Liquid and active trading markets usually result in less price volatility and more efficiency in carrying out investors’ purchase and sale orders. However, our common stock may continue to have limited trading volume, and many investors may not be interested in owning our common stock because of the inability to acquire or sell a substantial block of our common stock at one time. Such illiquidity could have an adverse effect on the market price of our common stock. In addition, a shareholder may not be able to borrow funds using our common stock as collateral because lenders may be unwilling to accept the pledge of securities having such a limited market. We cannot assure you that an active trading market for our common stock will develop or, if one develops, be sustained.
 
We do not presently intend to pay any cash dividends on or repurchase any shares of our common stock.
 
We do not presently intend to pay any cash dividends on our common stock or to repurchase any shares of our common stock. Any payment of future dividends will be at the discretion of the board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Cash dividend payments in the future may only be made out of legally available funds and, if we experience substantial losses, such funds may not be available. Accordingly, you may have to sell some or all of your common stock in order to generate cash flow from your investment.
 
Because we are a small company, the requirements of being a public company, including compliance with the reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and the requirements of the Sarbanes-Oxley Act and the Dodd-Frank Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.
 
As a public company with listed equity securities, we must comply with the federal securities laws, rules and regulations, including certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”) and the Dodd-Frank Act, related rules and regulations of the SEC. Complying with these laws, rules and regulations will occupy a significant amount of time of our board of directors and management and will significantly increase our costs and expenses, which we cannot estimate accurately at this time. Among other things, we must:
 
establish and maintain a system of internal control over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;
prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;
maintain various internal compliance and disclosures policies, such as those relating to disclosure controls and procedures and insider trading in our common stock;
involve and retain to a greater degree outside counsel and accountants in the above activities;
maintain a comprehensive internal audit function; and
maintain an investor relations function.
 
 
In addition, being a public company subject to these rules and regulations may require us to accept less director and officer liability insurance coverage than we desire or to incur substantial costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.
 
Future sales of shares of our common stock by existing shareholders and future offerings of our common stock by us could depress the price of our common stock.
 
The market price of our common stock could decline as a result of sales of a large number of shares of our common stock in the market, and the perception that these sales could occur may also depress the market price of our common stock. As of the date of this Annual Report, we have approximately 41,305,283 shares that are currently immediately freely tradable, without restriction, in the public market, except to the extent the shares are held by any of our affiliates (generally, directors, executive officers and holders of more than 10% of our shares). If our existing shareholders sell, or indicate an intent to sell, substantial amounts of our common stock in the public market, the trading price of our common stock could decline significantly. Sales of our common stock may make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. These sales also could cause our stock price to fall and make it more difficult for you to sell shares of our common stock.
 
We may also sell additional shares of common stock or securities convertible into common stock in future offerings. We cannot predict the size of future issuances of our common stock or convertible securities or the effect, if any, that future issuances and sales of shares of our common stock or convertible securities will have on the market price of our common stock.
 
Our outstanding options, warrants and convertible securities may adversely affect the trading price of our common stock.
 
As of the date of this Annual Report, there were outstanding stock options to purchase approximately 3,738,286 shares of our common stock, and outstanding warrants to purchase approximately 1,794,196 shares of common stock. For the life of the options and warrants, the holders have the opportunity to profit from a rise in the market price of our common stock without assuming the risk of ownership. The issuance of shares upon the exercise of outstanding securities will also dilute the ownership interests of our existing stockholders.
 
The availability of these shares for public resale, as well as any actual resale of these shares, could adversely affect the trading price of our common stock. In the near future we intend to file a registration statement with the SEC on Form S-8 providing for the registration of 11,950,000 shares of our common stock issuable or reserved for issuance under our equity incentive plans. Subject to the satisfaction of vesting conditions, the expiration of lockup agreements, any management 10b5-1 plans and certain restrictions on sales by affiliates, shares registered under a registration statement on Form S-8 will be available for resale immediately in the public market without restriction.
 
We cannot predict the size of future issuances of our common stock pursuant to the exercise of outstanding options or warrants or conversion of other securities, or the effect, if any, that future issuances and sales of shares of our common stock may have on the market price of our common stock. Sales or distributions of substantial amounts of our common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may cause the market price of our common stock to decline.

Four of our directors and executive officers own 24.4% of our common stock, and two of our major shareholders own approximately 19.3% of our common stock, which may give them influence over important corporate matters in which their interests are different from your interests.
 
Four of our directors and executive officers beneficially own approximately 24.4% of our outstanding shares of common stock, and our largest two non-director or officer shareholders own approximately 19.3% of our outstanding shares of common stock (on a fully-diluted basis, assuming exercise of options and warrants held thereby exercisable within 60 days of the date hereof) based on a total of 42,102,852 shares of common stock outstanding. These directors, executive officers and major shareholders will be positioned to influence or control to some degree the outcome of matters requiring a shareholder vote, including the election of directors, the adoption of amendments to our certificate of formation or bylaws and the approval of mergers and other significant corporate transactions. These directors, executive officers and major shareholders, subject to any fiduciary duties owed to the shareholders generally, may have interests different than the rest of our shareholders. Their influence or control of our company may have the effect of delaying or preventing a change of control of our company and may adversely affect the voting and other rights of other shareholders. In addition, due to the ownership interest of these directors and officers in our common stock, they may be able to remain entrenched in their positions.
 
Furthermore, one of our major shareholders, MIE Holdings, is an independent oil company in China with its own oil and natural gas operations separate from its relationship with us. Potential conflicts of interest could arise as a result, either in the terms of our relationship with MIE Holdings or in MIE Holdings competing with us in its operations outside its relationship with us.
 
 
Provisions of Texas law may have anti-takeover effects that could prevent a change in control even if it might be beneficial to our shareholders.
 
Provisions of Texas law may discourage, delay or prevent someone from acquiring or merging with us, which may cause the market price of our common stock to decline. Under Texas law, a shareholder who beneficially owns more than 20% of our voting stock, or any “affiliated shareholder,” cannot acquire us for a period of three years from the date this person became an affiliated shareholder, unless various conditions are met, such as approval of the transaction by our board of directors before this person became an affiliated shareholder or approval of the holders of at least two-thirds of our outstanding voting shares not beneficially owned by the affiliated shareholder. See “Description of Capital Stock - Business Combinations Under Texas Law.”
 
Our board of directors can authorize the issuance of preferred stock, which could diminish the rights of holders of our common stock and make a change of control of our company more difficult even if it might benefit our shareholders.
 
Our board of directors is authorized to issue shares of preferred stock in one or more series and to fix the voting powers, preferences and other rights and limitations of the preferred stock. Accordingly, we may issue shares of preferred stock with a preference over our common stock with respect to dividends or distributions on liquidation or dissolution, or that may otherwise adversely affect the voting or other rights of the holders of common stock. Issuances of preferred stock, depending upon the rights, preferences and designations of the preferred stock, may have the effect of delaying, deterring or preventing a change of control of our company, even if that change of control might benefit our shareholders.
None.
 
Oil and Gas Properties

All oil and gas properties are currently in the United States.

Productive Wells

The following table presents our total gross and net productive wells by core operating area and by oil or natural gas completion as of December 31, 2012:

   
Gross Productive Wells
   
Net Productive Wells
       
   
Oil
   
Natural Gas
   
Total
   
Oil
   
Natural Gas
   
Total
   
% Operated
 
December 31, 2012
                                         
Niobrara (1)(2)
    1.0       -       1.0       0.31       -       0.31       100 %
Eagle Ford
    3.0       -       3.0       0.12       -       0.12       0 %
Sugar Valley
    2.0       -       2.0       1.00       -       1.00       0 %
Total
    6.0       -       6.0       1.43       -       1.43          
 
(1)  
Operated by Condor, which our company jointly owns and manages with MIE Holdings.
(2)  
Two gross wells, the Waves 1H and Logan 2H were drilled in the Niobrara during November and December, 2012 but not completed until January and February, 2013 respectively.  Both wells are currently productive and we hold a 31.0% working interest in the Waves 1H and 29.3% working interest in the Logan 2H.
 
“Gross wells” represents the number of wells in which a working interest is owned, and “net wells” represents the total of our fractional working interests owned in gross wells.
 
 
Acreage
 
The following table sets forth certain information regarding the developed and undeveloped acreage in which we own a working interest as of December 31, 2012 for each of our core operating areas, without giving effect to our pending acquisition of the Mississippian asset.  Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.
 
   
Undeveloped Acres
   
Developed Acres
   
Total
   
% of
Acreage
Held-by-
 
As of December 31, 2012
 
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Production
 
Current Assets:
                                         
Niobrara     8,232       2,157       1,992       617       10,224       2,774       19.5 %
Eagle Ford
    1,133       45       198       8       1,331       53       52.7 %
Sugar Valley
    -       -       251       164       251       164       100 %
Total
    9,365       2,202       2,441       789       11,806       2,991          
 
Undeveloped Acreage Expirations

The following table sets forth the number of gross and net undeveloped acres on our Niobrara, Eagle Ford, and North Sugar Valley assets as of December 31, 2012 that will expire over the next three years unless production is established within the spacing units covering the acreage prior to the expiration dates: 
 
   
As of December 31, 2012
 
   
2013
   
2014
   
2015
   
Thereafter
 
Assets  
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                                 
Niobrara (1)
    5,757       1,510       1,618       429       547       123       310       95  
Eagle Ford (2)
    642       26       -       -       -       -       -       -  
North Sugar Valley (3)
    -       -       -       -       -       -       -       -  
Total
    6,399       1,536       1,618       429       547       123       310       95  
 
(1)  
We plan to continue to hold, and not allow to expire, significantly all of this acreage through an active program of completing producing wells thereon to hold such acreage by production, and seeking to extend leases where drilling is not planned prior to expiration.  All “net” acreage reflects our acreage held directly and our 20% proportionate share of acreage held by Condor by virtue of our 20% ownership interest in Condor.

(2)  
Currently 686 gross (27 net) acres are held by production.  Pursuant to the terms of the four (4) Eagle Ford asset leases, our remaining acreage requires drilling of at least one (1) well on each of the leases, respectively, that comprise this acreage every six (6) months to retain each such lease, with either shallow wells (i.e., Olmos or other shallow formation wells, rights which are owned by a third party operator who has been actively developing this acreage) or deep wells (i.e., Eagle Ford wells, rights in which we have an interest) holding such acreage.  We anticipate that none of our Eagle Ford acreage will expire in 2013 or thereafter as we anticipate that (i) the operator of our Eagle Ford asset, Texon Petroleum Limited (“Texon”), will continue to complete wells in which we plan to participate in order to hold these leases, (ii) the third party operator with rights to the shallow depths will continue to complete wells that will hold these leases, and (iii) if required to hold leases, we will seek to sole risk drilling and completion of wells on the asset.

(3)  
All of our North Sugar Valley acreage is currently held by production.
 
 
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. While we may attempt to secure a new lease upon the expiration of certain of our acreage, there are some third-party leases that may become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. We have options to extend some of our leases through payment of additional lease bonus payments prior the expiration of the primary term of the leases. Our leases are mainly fee leases with three to five years of primary term. We believe that our leases are similar to our competitors’ fee lease terms as they relate to primary term and reserved royalty interests.
 
Drilling Activity
 
The following table summarizes our operated and non-operated drilling activity for exploratory and development wells drilled from 2010 through 2012 on our Niobrara, Eagle Ford, and North Sugar Valley assets.
 
   
Net Exploratory
   
Net Development
 
   
2010
   
2011
   
2012
   
2010
   
2011
   
2012
 
Wells Drilled
                                   
Productive
   
-
     
-
     
0.31
     
-
     
-
     
0.04
 
Dry
   
-
     
-
     
-
     
-
     
-
     
-
 
Total
   
-
     
-
     
0.31
     
-
     
-
     
0.04
 

Natural Gas and Oil Reserves

Reserves Estimates
 
The following table sets forth, by property and as of December 31, 2012, our estimated net proved oil and natural gas reserves, and the estimated present value (discounted at an annual rate of ten percent (10%)) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves, each prepared in accordance with assumptions described by the Securities and Exchange Commission (“SEC”).
 
The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent (10%). PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies because of differences in the amounts and timing of deductible basis, net operating loss carry forwards and other factors. We believe investors and creditors use our PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and is not intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
 
These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.
 

   
Reserves
 
Reserve Category
 
Oil
(Bbls)
   
Natural Gas
(MMcf)
   
Total (4)
(BOE)
 
Owned Directly by PEDEVCO (1)
                 
Proved Developed
                 
-Niobrara Held Directly
    44,512       74       56,845  
-North Sugar Valley
    36,988       -       36,988  
Total Proved Developed (Direct)
    81,500       74       93,833  
                         
Proved Undeveloped
                       
-Niobrara Held Directly
    195,008       324       249,008  
-North Sugar Valley
    -       -       -  
Total Proved Undeveloped (Direct)
    195,008       324       249,008  
                         
Total Proved Reserves (Owned Directly by PEDEVCO)
    276,508       398       342,908  
                         
Owned Indirectly Through Equity Investees (2)
                       
Proved Developed
                       
-Niobrara Held in Condor
    29,082       48       37,082  
-Eagle Ford Held in White Hawk
    11,147       21       14,647  
Total Proved Developed (Indirect)
    40,229       69       51,729  
                         
Proved Undeveloped
                       
-Niobrara Held in Condor
    323,239       537       412,739  
-Eagle Ford Held in White Hawk
    127,480       181       157,647  
Total Proved Undeveloped (Indirect)
    450,719       718       570,386  
                         
Total Proved Reserves (Owned Indirectly through Investees)
    490,948       787       622,115  
                         
Combined Directly and Indirectly Owned (3)
                       
Combined Total Proved Developed Reserves
    121,729       143       145,562  
Combined Total Proved Undeveloped Reserves
    645,727       1,042       819,394  
                         
Combined Total Proved Reserves  (Direct & Indirect)
    767,456       1,185       964,956  

(1)  
Includes reserves attributable to our 18.75% directly held interest in the Niobrara asset and our North Sugar Valley asset.
(2)  
Includes reserves net to the Company’s equity interest held in unconsolidated investments in Condor and White Hawk.
(3)  
Includes combined reserves as described in both (1) and (2) above.
(4)  
Natural gas is converted on the basis of six (6) Mcf per one (1) barrel of oil equivalent.
 
 
The following table is a summary of Proved Reserves at December 31, 2012 for interests owned directly by PEDEVCO and indirectly through unconsolidated investments in Condor and White Hawk.  There were no proved reserves at December 31, 2011.

PV-10 (1) (‘000s)
 
Proved Developed
   
Proved Undeveloped
   
Total Proved
 
Directly Owned Proved Reserves
  $ 2,426     $ 689     $ 3,115  
Indirectly Owned Proved Reserves
  $ 1,219     $ 2,855     $ 4,074  
Combined Proved Reserves
  $ 3,645     $ 3,544     $ 7,189  

(1)  
In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2012. For purposes of determining prices, we used the unweighted arithmetical average of the prices on the first day of each month within the 12-month period ended December 31, 2012. The average prices utilized for purposes of estimating our proved reserves were $87.35 per barrel of oil and $4.73 per Mcf of natural gas for our properties, adjusted by property for energy content, quality, transportation fees and regional price differentials. The prices should not be interpreted as a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.
 
Due to the inherent uncertainties and the limited nature of reservoir data, proved reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.
 
Reserve Estimation Process, Controls and Technologies
 
The reserve estimates, including PV-10, set forth above were prepared by Ryder Scott Company, L.P. (“Ryder Scott”). The report from Ryder Scott was prepared on March 20, 2013.

These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards. Our year-end reserve report is prepared by Ryder Scott based upon a review of property interests being appraised, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, geosciences and engineering data, and other information provided to them by our management team. Ryder Scott also prepares reserve estimates for Condor and White Hawk. This information is reviewed by knowledgeable members of our Company to ensure accuracy and completeness of the data, as it pertains to our Company, prior to submission to Ryder Scott Company, L.P. Upon analysis and evaluation of data provided, Ryder Scott issues a preliminary appraisal report of our reserves. The preliminary appraisal report and changes in our reserves are reviewed by our independent petroleum consultant, South Texas Reservoir Alliance LLC (“STXRA”), a Certified Professional Petroleum Engineering Company, State of Texas Registration Number F-13460, Frank Ingriselli, President, our President and Chief Executive Officer, and Michael Peterson, our Executive Vice President and Chief Financial Officer, for completeness of the data presented and reasonableness of the results obtained. Messrs. Ingriselli and Peterson have a combined total of over 40 years’ experience in the oil and gas industry. Once any questions have been addressed, Ryder Scott issues the final appraisal report, reflecting their conclusions.
 
Ryder Scott is an independent professional engineering firm specializing in the technical and financial evaluation of oil and gas assets. Ryder Scott Company, L.P.’s report was conducted under the direction of Michael F. Stell of Ryder Scott. Ryder Scott, and its employees, have no interest in our Company and were objective in determining our reserves.
 
 
Ryder Scott estimated the proved reserves for our properties by performance methods and analogy. All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods, such as decline curve analysis, utilized extrapolations of historical production and pressure data available through November 2012 in those cases where such data were considered to be definitive. The data utilized were furnished to Ryder Scott by PEDEVCO or obtained from public data sources. All of the proved developed non-producing and undeveloped reserves were estimated by analogy.
 
Proved Undeveloped Reserves
 
As of December 31, 2012, our proved undeveloped reserves both owned directly and through equity interests in Condor and White Hawk totaled 645,727 Bbls of oil and 1,041 MMcf of natural gas, for a total of 819,395 BOE. At the close of our last fiscal year ending December 31, 2011 we had no proved undeveloped reserves. The increase in proved undeveloped reserves came through our purchasing leasehold interests in the Niobrara formation in Colorado and our equity positions in Condor and White Hawk and the subsequent drilling of the first three wells in the Niobrara acreage and one new well in the Eagle Ford acreage during 2012.
 
Our proved undeveloped reserves at December 31, 2012 were associated with our properties in both our Niobrara asset operated by Condor and our Eagle Ford asset operated by Aurora. In 2012, our first wells were drilled in the Niobrara acreage and a new well was drilled and completed in the Eagle Ford acreage which caused previously nonproducing and unproven acreage to be reclassified as proved developed, proved producing or proved undeveloped acreage. During the fiscal year 2012, we had capital expenditures of approximately $3.4 million in drilling and/or completing costs for these four wells (directly and through our equity interests). We intend to further increase our proved reserves during fiscal year 2013 by drilling additional wells in the Niobrara.
 
As this is the first year we have booked proved undeveloped reserves and thus none have been booked for longer than five years.

Oil & Gas Production, Production Prices and Production Costs
 
Oil   2010     2011     2012  
Geography/Field
 
Bbl Sold
   
Average Sales Price
   
Average Production
Cost
   
Bbl Sold
   
Average Sales Price
   
Average Production
Cost
   
Bbl Sold
   
Average Sales Price
   
Average Production
Cost
 
                                                       
-Niobrara
    -       -       -       -       -       -       2,235     $ 88.79     $ 53.52  
-North Sugar Valley
    -       -       -       -       -       -       1,475     $ 99.26     $ 66.11  
 
Gas   2010     2011     2012  
Geography/Field
 
Mcf Sold
   
Average Sales Price
   
Average Production
Cost
   
Mcf Sold
   
Average Sales Price
   
Average Production
Cost
   
Mcf Sold
   
Average Sales Price
   
Average Production
Cost
 
                                                       
-Niobrara
    -       -       -       -       -       -       -       -       -  
-North Sugar Valley
    -       -       -       -       -       -       -       -       -  
 
 
Mississippian Opportunity Summary (Pending Acquisition)
 
Acreage
 
The following table sets forth certain information regarding the developed and undeveloped acreage as of December 31, 2012, with respect to the acreage associated with the proposed Mississippian opportunity, if such acquisition is completed. Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary.
 
   
Undeveloped Acres
   
Developed Acres
   
Total
   
% of
Acreage
Held-by-
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
   
Production
 
                                                         
Mississippian 
   
7,006
     
6,763
     
-
     
-
     
7,006
     
6,763
     
-
%

Undeveloped Acreage Expirations
 
With respect to the acreage we intend to acquire in connection with the Mississippian acquisition opportunity, we expect that the gross and net undeveloped acres will expire as follows, unless production is established within the spacing units covering the acreage prior to the expiration dates:

2013 (1)
   
2014
   
2015
   
Thereafter
 
Gross
   
Net
   
Gross
 
Net
   
Gross
   
Net
   
Gross
   
Net
 
                                                             
  320       320       6,686       6,443       -       -       --       --  

(1)  
Under our Mississippian term assignment agreement, if we complete at least three (3) horizontal wells on the asset during the primary term which expires on December 29, 2014, we will have an option to extend the primary term an additional one (1) year to December 29, 2015.  However, if we do not complete three (3) horizontal wells on the asset by such date, then on December 29, 2014, all of our Mississippian acreage will expire on such date, save for acreage held by producing wells we have completed on such acreage, with each producing horizontal well holding 320 gross acres, each producing short-horizontal well holding 160 gross acres, and each producing vertical well holding 10 gross acres.  Of the 7,006 gross (6,763 net) Mississippian acres we plan to acquire, 5,450 gross (5,207 net) acres are held by vertical well production by other operators who are parties to the leases covering such acreage.
 
Many of the leases comprising the acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production in commercial quantities. While we may attempt to secure a new lease upon the expiration of certain of our acreage, there are some third-party leases that may become effective immediately if our leases expire at the end of their respective terms and production has not been established prior to such date. We have options to extend some of our leases through payment of additional lease bonus payments prior the expiration of the primary term of the leases. Our leases are mainly fee leases with three to five years of primary term. We believe that our leases are similar to our competitors’ fee lease terms as they relate to primary term and reserved royalty interests.
 
Office Lease
 
Our corporate headquarters are located in approximately 2,000 square feet of office space at 4125 Blackhawk Plaza Circle, Suite 201, Danville, California 94506.  We lease that space pursuant to a lease that expires on June 30, 2013 and that has a base monthly rent of approximately $4,100.
 
Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceeding. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us.

ITEM 4. MINE SAFETY DISCLOSURES.

None
 
 

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OFEQUITY SECURITIES.

Market Information
 
Our common stock has been traded on the OTC Bulletin Board over-the-counter market since January 13, 2003 and currently trades under the symbol “PEDO.”
 
On December 31, 2012, the last reported bid price per share of our common stock as quoted on the OTC Bulletin Board was $2.00. The following price information (a) has been adjusted to reflect the 1 for 112 reverse stock split of our common stock that was effected on July 30, 2012 and (b) does not reflect any value attributable to our merger with Pacific Energy Development, which occurred on that date. The following price information reflects inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions.
 
Quarter Ended
 
High
   
Low
 
             
March 31, 2012
 
$
2.02
   
$
0.34
 
June 30, 2012
   
1.12
     
0.34
 
September 30, 2012
   
5.00
     
0.90
 
December 31, 2012
   
3.50
     
2.00
 
                 
March 31, 2011
 
$
22.40
   
$
2.24
 
June 30, 2011
   
22.40
     
3.36
 
September 30, 2011
   
10.08
     
3.36
 
December 31, 2011
   
6.72
     
1.12
 
 
On December 3, 2012, our company’s board of directors approved a possible reverse stock split of our common stock and Series A preferred stock in a ratio ranging between 1-for-2 and 1-for-5, with the specific ratio and effective time (if we decide to proceed with the split) to be later determined by the board of directors. Effective December 5, 2012, holders of a majority of our common stock and Series A preferred stock granted the board of directors discretionary authority to determine the specific ratio and effective time for the reverse split. We have filed and mailed to our shareholders an Information Statement on Schedule 14C in connection with such approval. We have not made any adjustments to the amount of shares disclosed in this Annual Report to account for this intended reverse stock split.
Shareholders
 
As of December 31, 2012, there were approximately 789 holders of record of our common stock, not including any persons who hold their stock in “street name.”
 
Common Stock
 
The Company is authorized to issue 200,000,000 shares of common stock with $0.001 par value per share. Holders of shares of common stock are entitled to one vote per share on each matter submitted to a vote of shareholders. In the event of liquidation, holders of common stock are entitled to share pro rata in the distribution of assets remaining after payment of liabilities, if any. Holders of common stock have no cumulative voting rights, and, accordingly, the holders of a majority of the outstanding shares have the ability to elect all of the directors of the Company. Holders of common stock have no preemptive or other rights to subscribe for shares. Holders of common stock are entitled to such dividends as may be declared by the Board out of funds legally available therefore. The outstanding shares of common stock are validly issued, fully paid and non-assessable.
 
Preferred Stock
 
The Company is authorized to issue 100,000,000 shares of preferred stock, $0.001 par value per share, of which 25,000,000 shares have been designated “Series A Convertible Preferred Stock”. At December 31, 2012, there were 20,512,370 shares of Series A Convertible Preferred Stock outstanding convertible into 20,512,370 shares of our common stock.
 
 
On January 27, 2013, each outstanding share of Series A Convertible Preferred Stock converted into one share of common stock. Accordingly, the Company has no preferred shares outstanding currently.
 
Dividend Policy
 
We have never declared or paid any dividends on our common stock and do not anticipate that we will pay dividends in the foreseeable future. Any payment of cash dividends on our common stock in the future will be dependent upon the amount of funds legally available, our earnings, if any, our financial condition, our anticipated capital requirements and other factors that the board of directors may think are relevant. However, we currently intend for the foreseeable future to follow a policy of retaining all of our earnings, if any, to finance the development and expansion of our business and, therefore, do not expect to pay any dividends on our common stock in the foreseeable future.
 
Securities Authorized for Issuance Under Equity Compensation Plans
 
The following table sets forth information, as of December 31, 2012, with respect to our compensation plans under which common stock is authorized for issuance.

EQUITY COMPENSATION PLAN INFORMATION

Plan Category
 
Number of securities to be issued upon exercise of outstanding options, warrants and rights
(A)
   
Weighted-average exercise price of outstanding options, warrants and rights
(B)
   
Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in Column A)
(C)
 
                         
Equity compensation plans approved by stockholders (1)
    894,615     $ 0.77       5,960,000 (2)
Equity compensation plans not approved by stockholders
    4,660,893     $ 2.57       0  
Total
    5,555,508     $ 2.28       5,960,000  

(1)  
Consists of:  (i) options to purchase 9,000 shares of common stock issued and outstanding under Pacific Energy Development Corp. standalone incentive stock option plan; (ii) options to purchase 855,000 shares of common stock issued and outstanding under Pacific Energy Development Corp. 2012 Equity Incentive Plan; and (iii) options to purchase 30,615 shares of common stock issued and outstanding under Blast Energy Services, Inc. 2009 Stock Incentive Plan and 2003 Stock Option Plan.
(2)  
Consists of 5,960,000 shares of common stock reserved for issuance under the PEDEVCO Corp. 2012 Equity Incentive Plan.
(3)  
Consists of:  (i) options to purchase 2,860,000 shares of common stock issued by Pacific Energy Development Corp. to employees and consultants of the company in October 2011 and June 2012; (ii) warrants to purchase 1,717,584 shares of common stock issued by Pacific Energy Development Corp. to investors, placement agents and consultants between October 2011 and July 2012; and (iii) warrants to purchase 83,309 shares of common stock issued by Blast Energy Services, Inc. to investors, placement agents, employees and consultants between January 2005 and June 2011.

Stock Transfer Agent
 
Our Stock Transfer Agent is First American Stock Transfer, located at 4747 N. 7th Street, Suite 170, Phoenix, AZ 85014.
 
Recent Sales of Unregistered Securities
 
During the past year, we issued and sold the following securities without registration under the Securities Act. On July 30, 2012, we conducted a reverse stock split of our common stock on a 1:112 basis. All share and per share amounts used throughout this section have been retroactively restated for the impact of the reverse split.
 
 
On January 13, 2012, we entered into an Agreement and Plan of Reorganization with Blast Acquisition Corp., a newly formed wholly-owned Nevada subsidiary of our company which we refer to as MergerCo, and Pacific Energy Development Corp., a privately-held Nevada corporation, which we refer to as Pacific Energy Development, pursuant to which MergerCo would be merged with and into Pacific Energy Development, with Pacific Energy Development being the surviving entity and becoming a wholly-owned subsidiary of our company.
 
In connection with the Pacific Energy Development merger agreement, we entered into other agreements, including several agreements to convert the following debt obligations of our company into shares of common stock at a rate of $2.24 per share:
 
the BMC Note;
a Promissory Note, dated May 19, 2011, with Clyde Berg in the aggregate principal amount of $100,000, which we refer to as the Berg Note;
$201,000 of accrued compensation due to the members of Board of Directors;
$6,150 of short term loans from members of our board of directors;
$225,959 of accrued salaries and vacation pay owed to our employees; and
approximately $47,960 in accrued finders’ fees owed to Trident pursuant to a Placement Agent Agreement.
 
In addition, in connection with the Pacific Energy Development merger agreement, on January 13, 2012, we and Centurion amended the Note Purchase Agreement to provide, among other things that, effective upon the effective date of the Pacific Energy Development merger, for the conversion of up to 50% of the loan amounts outstanding to Centurion, into shares of our common stock at $0.75 per share on a post-reverse split basis at the option of Centurion at any time after June 9, 2012, provided that we in our sole discretion may waive the 50% conversion limitation. The conversion rights described above are subject to Centurion being prohibited from converting any portion of the outstanding notes which would cause it to beneficially own more than 4.99% of our then outstanding shares of common stock, subject to Centurion’s right to increase such limit to up to 9.99% of our outstanding shares with 61 days prior written notice to us. On August 31, 2012, Centurion converted $101,250 of the loan and accrued interest amounts outstanding to Centurion under the Centurion Notes at $0.75 per share into an aggregate of 135,000 shares of our common stock and on October 23, 2012, Centurion converted $536,250 under the Centurion Notes into 715,000 shares of our common stock. On November 23, 2012, we and Centurion again amended the Centurion Notes to permit conversion in excess of the 50% conversion limit discussed above, and Centurion converted the remaining Centurion Notes into 522,727 additional shares of common stock, and concurrently exercised the Centurion warrant in full on a cashless basis to purchase 106,633 shares of common stock. As a result of the conversion, the Centurion Notes were fully retired.
 
On June 26, 2012, we provided notice of our intent to exercise our rights under the January 13, 2012 debt conversion agreements, and on June 27, 2012, we issued a total of 730,470 shares, including 673,461 shares of common stock under the BMC Note and 57,009 shares of common stock under the Berg Note.
 
On July 30, 2012 and in connection with the Pacific Energy Development merger, we conducted a reverse stock split of our common stock on a 1:112 basis and all of our outstanding shares of Series A preferred stock and Series B preferred stock were automatically converted into shares of common stock on a 1:112 basis in connection with the filing of our Amended and Restated Certificate of Formation.
 
On July 27, 2012, as a result of the closing of the Pacific Energy Development merger, we issued an aggregate of 17,917,261 shares of common stock and 19,616,676 shares of new Series A preferred stock to former shareholders of Pacific Energy Development. Additionally, we granted (a) warrants to purchase an aggregate of 100,000 shares of common stock with an exercise price of $0.08 per share;500,000 shares of common stock with an exercise price of $1.25 per share; 500,000 shares of common stock with an exercise price of $1.50 per share; 20,000 shares of common stock with an exercise price of $0.75 per share, to former common stock warrant holders of Pacific Energy Development; and 692,584 shares of new Series A preferred stock with an exercise price of $0.75 per share to former Series A preferred stock warrant holders of Pacific Energy Development; and (b) options to purchase an aggregate of 470,000 shares of common stock with an exercise price of $0.08 per share; 365,000 shares of common stock with an exercise price of $0.10 per share; and 3,400,000 shares of our common stock with an exercise price of $0.17 per share, to former option holders of Pacific Energy Development.
 
On September 24, 2012, we issued an aggregate of 368,435 shares of Series A preferred stock to Esenjay Oil & Gas, Ltd., and certain other sellers, in connection with the acquisition by Condor Energy Technology LLC, which we refer to as Condor, of leasehold interests covering approximately 3,582 net acres located in Morgan and Weld Counties, Colorado with a 100% working interest (80% net revenue interest). Condor acquired the properties for $1,105,309 in cash and 368,435 shares of our Series A preferred stock (approximately $385 net per acre, based on an assumed share price of $0.75 per share as agreed upon by the parties in July 2012 upon execution of the definitive purchase documentation). Also in connection with this transaction, we issued to Esenjay Oil & Gas, Ltd., referred to here as Esenjay, 279,749 shares of Series A preferred stock in full satisfaction and release of our obligation to carry $419,624 of Esenjay’s drilling and completion expenses, which obligation was incurred by us as part of the purchase consideration due in our October 2011 acquisition of interests in Weld County, Colorado from Esenjay and certain other sellers.
 
 
On November 20, 2012, we issued to Esenjay and the other sellers an aggregate of 133,334 shares of Series A preferred stock in connection with their agreement to defer payment obligations owed as part of the purchase consideration due in our October 2011 acquisition of interests in Weld County, Colorado from Esenjay and certain other sellers.
 
On December 13, 2012, we granted 40,000 shares of common stock to an independent contractor for services provided pursuant to our 2012 Equity Incentive Plan.
 
On December 19, 2012, a holder of a warrant exercisable for an aggregate of 200,000 shares of our Series A preferred stock exercised the warrant on a cashless net exercise basis and has been issued an aggregate of 141,176 shares of our Series A preferred stock.
 
On December 19, 2012, five of our employees exercised incentive stock options exercisable for an aggregate of 511,000 shares of common stock on a cashless net exercise basis, netting an aggregate of 483,256 shares of restricted common stock to such employees. The options were previously granted to the employees under Pacific Energy Development’s incentive stock plans, and were all fully vested.
 
On January 11, 2013, the Company issued 533,333 shares of common stock upon conversion of 533,333 shares of Series A preferred stock held by a shareholder.
 
On January 27, 2013 the Company issued 19,979,040 shares of common stock on a 1 for 1 conversion of all our 19,979,040 outstanding Series A preferred stock, pursuant to the automatic conversion provisions our Series A Convertible Preferred Stock Amended and Restated Certificate of Designations.
 
The issuances and grants described above were exempt from registration pursuant to Section 4(2), Rule 506 of Regulation D and/or Regulation S of the Act since the foregoing issuances and grants did not involve a public offering, the recipients took the securities for investment and not resale, we took take appropriate measures to restrict transfer, and the recipients are (a) “accredited investors”; (b) have access to similar documentation and information as would be required in a Registration Statement under the Act; and/or (c) are non-U.S. persons.
 
With respect to any exchanges or conversions of our outstanding securities discussed above, we claim an exemption from registration afforded by Section 3(a)(9) of the Act for the above conversions, as the securities were exchanged by our company with its existing security holders exclusively in transactions where no commission or other remuneration was paid or given directly or indirectly for soliciting such exchange.
 
ITEM 6.  SELECTED FINANCIAL DATA
 
Not required under Regulation S-K for “smaller reporting companies.”
 
ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and related notes appearing elsewhere in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution you that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Risk Factors” and “Forward Looking Statements.”
 
 
On July 27, 2012, we completed our acquisition of Pacific Energy Development Corp., which we refer to as Pacific Energy Development. The acquisition was accounted for as a “reverse acquisition,” and Pacific Energy Development was deemed to be the accounting acquirer in the acquisition. Because Pacific Energy Development Corp. was deemed the acquirer for accounting purposes, the financial statements of Pacific Energy Development are presented as the continuing accounting entity and the below discussion solely relates to the financial information of Pacific Energy Development as the continuing accounting entity.
 
Overview
 
We are an energy company engaged in the acquisition, exploration, development and production of oil and natural gas resources in the U.S., with a primary focus on oil and natural gas shale plays and a secondary focus on conventional oil and natural gas plays. Our current operations are located primarily in the Niobrara Shale play in the Denver-Julesburg Basin in Morgan and Weld Counties, Colorado and the Eagle Ford Shale play in McMullen County, Texas. We also hold an interest in the North Sugar Valley Field in Matagorda County, Texas, though we consider this a non-core asset.
 
We have approximately 10,224 gross and 2,774 net acres of oil and gas properties in our Niobrara core area. Our current Eagle Ford position is a 3.97% working interest in 1,331 acres. Condor Energy Technology LLC, which we jointly own and manage with an affiliate of MIE Holdings Corporation as described below, operates our Niobrara interests, including three gross wells in the Niobrara asset with current daily production of approximately 494 BOE (150 BOE net). We believe our current assets could contain a gross total of 197 drilling locations.
 
We also have agreements in place (subject to customary closing conditions) for acquisitions and future operations in the Mississippian Lime play in Comanche, Harper, Barber and Kiowa Counties, Kansas and Woods County, Oklahoma. See “Recent Developments - Mississippian Opportunity (Pending Acquisition).” If the proposed acquisition of the Mississippian asset is completed, upon closing, we will have a 100% operated working interest in 7,006 gross (6,763 net) acres, and will hold an option to acquire an additional 7,880 gross (7,043 net) acres through May 30, 2013. We believe the Mississippian asset could contain a gross total of 84 drilling locations.
 
We believe that the Niobrara, Eagle Ford and Mississippian Shale plays represent among the most promising unconventional oil and natural gas plays in the U.S. We will continue to seek additional acreage proximate to our currently held core acreage. Our strategy is to be the operator, directly or through our subsidiaries and joint ventures, in the majority of our acreage so we can dictate the pace of development in order to execute our business plan. The majority of our capital expenditure budget for 2013 will be focused on the acquisition, development and expansion of these formations.
 
Detailed information about our business plans and operations, including our core Niobrara, Eagle Ford and Mississippian assets, is contained under “Business” in Part I, Item 1 above.
 
How We Conduct Our Business and Evaluate Our Operations
 
Our use of capital for acquisitions and development allows us to direct our capital resources to what we believe to be the most attractive opportunities as market conditions evolve. We have historically acquired properties that we believe have significant appreciation potential. We intend to continue to acquire both operated and non-operated properties to the extent we believe they meet our return objectives.
 
We will use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:
 
production volumes;
realized prices on the sale of oil and natural gas, including the effects of our commodity derivative contracts;
oil and natural gas production and operating expenses;
capital expenditures;
general and administrative expenses;
net cash provided by operating activities; and
net income.
 
 
Production Volumes
 
Production volumes will directly impact our results of operations. We currently have minimal production, all from the initial producing well associated with the Niobrara asset, three gross producing wells associated with our Eagle Ford asset, and three gross producing wells associated with our North Sugar Valley field, but expect to increase production assuming drilling success in the future.
 
Factors Affecting the Sales Price of Oil and Natural Gas
 
We expect to market our crude oil and natural gas production to a variety of purchasers based on regional pricing. The relative prices of crude oil and natural gas are determined by the factors impacting global and regional supply and demand dynamics, such as economic conditions, production levels, weather cycles and other events. In addition, relative prices are heavily influenced by product quality and location relative to consuming and refining markets.
 
Oil. The New York Mercantile Exchange-West Texas Intermediate (NYMEX-WTI) futures price is a widely used benchmark in the pricing of domestic crude oil in the U.S. The actual prices realized from the sale of crude oil differ from the quoted NYMEX-WTI price as a result of quality and location differentials. Quality differentials to NYMEX-WTI prices result from the fact that crude oils differ from one another in their molecular makeup, which plays an important part in their refining and subsequent sale as petroleum products. Among other things, there are two characteristics that commonly drive quality differentials: (a) the crude oil’s American Petroleum Institute, or API, gravity and (b) the crude oil’s percentage of sulfur content by weight. In general, lighter crude oil (with higher API gravity) produces a larger number of lighter products, such as gasoline, which have higher resale value and, therefore, normally sell at a higher price than heavier oil. Crude oil with low sulfur content (“sweet” crude oil) is less expensive to refine and, as a result, normally sells at a higher price than high sulfur-content crude oil (“sour” crude oil).
Location differentials to NYMEX-WTI prices result from variances in transportation costs based on the produced crude oil’s proximity to the major consuming and refining markets to which it is ultimately delivered. Crude oil that is produced close to major consuming and refining markets, such as near Cushing, Oklahoma, is in higher demand as compared to crude oil that is produced farther from such markets. Consequently, crude oil that is produced close to major consuming and refining markets normally realizes a higher price (i.e., a lower location differential to NYMEX-WTI).
 
In the past, crude oil prices have been extremely volatile, and we expect this volatility to continue. For example, the NYMEX-WTI oil price ranged from a high of $113.93 per Bbl to a low of $75.67 per Bbl during the year ended December 31, 2011 and from a high of $108.84 per Bbl to a low of $77.69 per Bbl during the year ended December 31, 2012.
 
 
 
Natural GasThe NYMEX-Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the U.S. Similar to crude oil, the actual prices realized from the sale of natural gas differ from the quoted NYMEX-Henry Hub price as a result of quality and location differentials. Quality differentials to NYMEX-Henry Hub prices result from: (a) the Btu content of natural gas, which measures its heating value, and (b) the percentage of sulfur, CO2 and other inert content by volume. Wet natural gas with a high Btu content sells at a premium to low btu content dry natural gas because it yields a greater quantity of natural gas liquids (NGLs). Natural gas with low sulfur and CO2 content sells at a premium to natural gas with high sulfur and CO2 content because of the added cost to separate the sulfur and CO2 from the natural gas to render it marketable. Wet natural gas is processed in third-party natural gas plants and residue natural gas as well as NGLs are recovered and sold. Dry natural gas residue from our properties is generally sold based on index prices in the region from which it is produced.
 
Location differentials to NYMEX-Henry Hub prices result from variances in transportation costs based on the natural gas’ proximity to the major consuming markets to which it is ultimately delivered. Also affecting the differential is the processing fee deduction retained by the natural gas processing plant generally in the form of percentage of proceeds. Generally, these index prices have historically been at a discount to NYMEX-Henry Hub natural gas prices.
 
In the past, natural gas prices have been extremely volatile, and we expect this volatility to continue. For example, the NYMEX-Henry Hub natural gas price ranged from a high of $4.92 per MMBtu to a low of $2.84 per MMbtu during the year ended December 31, 2011, and from a high of $3.20 per MMBtu to a low of $1.82 per MMBtu during the year ended December 31, 2012.
 
Commodity Derivative Contracts. We expect to adopt a commodity derivative policy designed to minimize volatility in our cash flows from changes in commodity prices. We have not determined the portion of our estimated production, if any, for which we will mitigate our risk through the use of commodity derivative instruments, but in no event will we maintain a commodity derivative position in an amount in excess of our estimated production. Should we reduce our estimates of future production to amounts which are lower than our commodity derivative volumes, we will reduce our positions as soon as practical. If forward crude oil or natural gas prices increase to prices higher than the prices at which we have entered into commodity derivative positions, we may be required to make margin calls out of our working capital in the amounts those prices exceed the prices we have entered into commodity derivative positions.
 
Oil and Natural Gas Production Expenses. We will strive to increase our production levels to maximize our revenue. Oil and natural gas production expenses are the costs incurred in the operation of producing properties and workover costs. We expect expenses for utilities, direct labor, water injection and disposal, and materials and supplies to comprise the most significant portion of our oil and natural gas production expenses. Oil and natural gas production expenses do not include general and administrative costs or production and other taxes. Certain items, such as direct labor and materials and supplies, generally remain relatively fixed across broad production volume ranges, but can fluctuate depending on activities performed during a specific period. For instance, repairs to our pumping equipment or surface facilities may result in increased oil and natural gas production expenses in periods during which they are performed.
 
A majority of our operating cost components will be variable and increase or decrease as the level of produced hydrocarbons and water increases or decreases. For example, we will incur power costs in connection with various production related activities such as pumping to recover oil and natural gas and separation and treatment of water produced in connection with our oil and natural gas production. Over the life of hydrocarbon fields, the amount of water produced may increase for a given volume of oil or natural gas production, and, as pressure declines in natural gas wells that also produce water, more power will be needed to provide energy to artificial lift systems that help to remove produced water from the wells. Thus, production of a given volume of hydrocarbons may become more expensive each year as the cumulative oil and natural gas produced from a field increases until, at some point, additional production becomes uneconomic.
 
Production and Ad Valorem Taxes. Texas regulates the development, production, gathering and sale of oil and natural gas, including imposing production taxes and requirements for obtaining drilling permits. For oil production, Texas currently imposes a production tax at 4.6% of the market value of the oil produced and an additional 3/16 of one cent per barrel of crude petroleum produced, and for natural gas, Texas currently imposes a production tax at 7.5% of the market value of the natural gas produced. Colorado imposes production taxes ranging from 2% to 5% based on gross income and a conservation tax ranging from 0.07% to 1.5% based on the market value of oil and natural gas production. Wyoming imposes production taxes at a base rate of 6% and conservation tax of 0.04% based on the market value of oil and natural gas production. Ad valorem taxes are generally tied to the valuation of the oil and natural gas properties; however, these valuations are reasonably correlated to revenues, excluding the effects of any commodity derivative contracts.
 
General and Administrative Expenses. General and administrative expenses related to being a publicly traded company include: Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley compliance; expenses associated with our efforts to have our shares listed on the NYSE MKT; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. As a publicly-traded company, we expect that general and administrative expenses will continue to be significant.
 
 
Income Tax Expense. We are a C-corporation for federal income tax purposes, and accordingly, we are directly subject to federal income taxes which may affect future operating results and cash flows. We are also subject to taxation through our membership interests in our joint ventures, which are limited liability companies taxed as pass-through entities.
 
Results of Operations
 
As a result of the reverse acquisition, the financial statements of Pacific Energy Development prior to the merger are presented as the financial statements of the Company. The financial statements prior to the date of the merger represent the operations of pre-merger Pacific Energy Development only. After the date of the merger, the financial statements include the operations of the combined companies.
 
Comparison of the Year Ended December 31, 2012 with the Period from February 9, 2011 (inception) through December 31, 2011
 
Oil and Gas Revenue. We had total revenue of approximately $503,000 for the year ended December 31, 2012, comprised of approximately $357,000 in revenue generated after February 2012 from Pacific Energy Development’s two producing wells in the Eagle Ford asset and one producing well in the Niobrara asset and approximately $146,000 in revenue generated after the merger on July 27, 2012 from the former Blast business (“Blast”) operations. Prior to February 2012, Pacific Energy Development was focused on acquiring oil and natural gas properties, and did not yet generate any revenue. Consequently, oil and gas revenue were $-0- for the period from February 9, 2011 (inception) through the year ended December 31, 2011.
 
Lease Operating Expense. Operating expenses associated with the oil and gas properties were approximately $281,000 for the year ended December 31, 2012 comprised of approximately $176,000 for Pacific Energy Development and approximately $105,000 attributable to Blast after the merger on July 27, 2012. Prior to February 2012, Pacific Energy Development was focused on acquiring oil and natural gas properties, and did not yet generate any revenue. Consequently, well operating expenses were $-0- for the period from February 9, 2011 (inception) through the year ended December 31, 2011.
 
Selling, General and Administrative. Selling, general and administrative (“SG&A”) expenses increased by $3,013,000 to $3,730,000 for the year ended December 31, 2012 compared to $717,000 for the period from February 9, 2011 (inception) through December 31, 2011. The increase was primarily due to increased staff, professional service fees, legal fees in connection with the Pacific Energy Development merger, and stock compensation expense in 2012 not applicable to 2011.
 
   
For the Years Ended
       
   
December 31,
   
Increase
 
(in thousands)
 
2012
   
2011
   
(Decrease)
 
Payroll and related costs
 
$
1,682
   
$
309
   
$
1,373
 
Option and warrant expense
   
621
     
-
     
621
 
Legal fees and settlements
   
162
     
120
     
42
 
Professional  services
   
910
     
155
     
755
 
Insurance
   
109
     
10
     
99
 
Travel & entertainment
   
111
     
75
     
36
 
Office rent, communications and other
   
135
     
48
     
87
 
   
$
3,730
   
$
717
   
$
3,017
 
 
Impairment of Goodwill. Management evaluated the amount of goodwill associated with the merger with Blast following the allocation of fair value to the assets and liabilities acquired and determined that the goodwill should be fully impaired and has reflected the impairment on the statement of operations as of the date of the merger.
 
Depreciation, Depletion and Amortization (“DD&A”). DD&A costs were approximately $131,000 for the year ended December 31, 2012, compared to $1,000 for the period from February 9, 2011 (inception) through December 31, 2011, as recording of depletion commenced in 2012 when the wells began producing revenue.
 
Gain on Sale of Equity Method Investments. In connection with the White Hawk Sale in May 2012, the Company recorded a gain of $64,000 representing the difference between the Company’s carrying value of the 50% investment sold ($1,875,000) and the fair value of the net sale proceeds received from MIE Holdings ($1,939,000). There was no such sale in 2011.
 
Loss from Equity Method Investment. Loss from equity method investments was $358,000 in 2012, compared with $26,000 in 2011. The Company has two investments accounted for using the equity method, Condor and White Hawk, which was acquired in 2012. The increased loss was due primarily to costs associated with exploration of new, unproven areas within the Condor property and general and administrative costs incurred for a full year of Condor operations (Condor was formed in October of 2011), offset in part by the addition of White Hawk in 2012 which generated net income.
 

Interest Expense. Interest expense was $986,000 for the year ended December 31, 2012 compared to $13,000 for the period from February 9, 2011 (inception) through December 31, 2011, an increase of $971,000 from the prior period. This increase is primarily due to the amortization of $507,000 for debt discount and $63,000 of interest expense related to the Centurion note acquired from Blast in the merger; and $380,000 of interest incurred on the extension of the due date for a deferred payment related to the acquisition of the Eagle Ford property held in Excellong E&P-2, Inc. (now White Hawk Petroleum, LLC).
 
Gain on Debt Extinguishment. The Company recorded a loss of $160,000 for debt extinguishment in connection with modifications made to amounts borrowed from Centurion Credit Funding, LLC under the Note Purchase Amendment dated January 13, 2012 as a significant conversion feature was added to the terms of the note and the Company’s Merger with Blast triggered the contingent conversion feature. The Company recorded a gain on debt extinguishment of $169,000 in connection with amounts forgiven by Centurion Credit Funding, LLC for the complete extinguishment of the outstanding debt during the year. The net gain on debt extinguishment for the year ended December 31, 2012 was approximately $9,000.
 
Loss on Settlement of Payable. During the year, the Copmany recorded a loss on a settlement of payable in the amount of $139,874 related to issuance of 279,749 shares of Series A preferred Stock in full satisfaction and release of our obligation to Esenjay.
 
Net Loss. Net loss increased by $11,249,000 to a net loss of $12,013,000 for the year ended December 31, 2012 compared to a net loss of $764,000 for the period from February 9, 2011 (inception) through December 31, 2011. This increase was primarily due to $6,820,000 for goodwill impairment, the increase in SG&A of $3,017,000 in 2012 as described above, increased loss from equity investments of $332,000, the debt discount amortization and interest of $578,000 for the Centurion note, loss on settlement of payable to Esenjay in the amount of $139,874, and $380,000 of interest expense as described above.
 
Liquidity and Capital Resources
 
Liquidity Outlook
 
We expect to incur substantial expenses and generate significant operating losses as we continue to explore for and develop our oil and natural gas prospects, and as we opportunistically invest in additional oil and natural gas properties, develop our discoveries which we determine to be commercially viable and incur expenses related to operating as a public company and compliance with regulatory requirements.
 
On October 10, 2012, we filed a Registration Statement on Form S-1 with the Securities and Exchange Commission (“SEC”), with a proposed $50 million underwritten public offering of our common stock (the “Pending Public Offering”). Subject to clearance by the SEC, we anticipate closing the Pending Public Offering in the second quarter of 2013, although there can be no guarantee that we will be able to close the Pending Public Offering, or, if closed, raise the full amount sought in the offering. We intend to use the net proceeds that we receive from the Pending Public Offering to fund capital expenditures for leasehold acquisitions and development as well as for general corporate purposes.
 
Our future financial condition and liquidity will be impacted by, among other factors, our ability to successfully complete the Pending Public Offering, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production, and the actual cost of exploration, appraisal and development of our prospects. Assuming the Pending Public Offering closes in a timely manner, we estimate that we will make capital expenditures, excluding capitalized interest and general and administrative expense, of approximately $38 million during the period from January 1, 2013 to December 31, 2013 in order to achieve our plans.
 
We expect the proceeds of the Pending Public Offering, cash flow from operations, proceeds from asset divestitures and our existing cash on hand will be sufficient to fund our planned capital expenditures until the end of 2013. Because the wells funded by our 2013 drilling plans represent only a small percentage of our potential drilling locations, we will be required to generate or raise additional capital to develop our entire inventory of potential drilling locations, if we elect to do so. We may seek additional funding through asset sales, farm-out arrangements, lines of credit and additional public or private equity or debt financings.
 
Our capital budget may be adjusted as business conditions warrant. The amount, timing and allocation of capital expenditures is largely discretionary and within our control. If oil and natural gas prices decline or costs increase significantly, we could defer a significant portion of our budgeted capital expenditures until later periods to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in prices, availability of financing, drilling and acquisition costs, industry conditions, timing of regulatory approvals, availability of rigs, success or lack of success in drilling activities, contractual obligations, internally generated cash flows and other factors both within and outside our control.
 
Historical Liquidity and Capital Resources
 
Prior to the completion of the merger with Blast, we raised approximately $11.5 million through the sale of Series A preferred stock, which we refer to as the Pacific Energy Development Offering. The Pacific Energy Development Offering closed on July 27, 2012.
 

The proceeds of the Pacific Energy Development Offering were used to purchase our Niobrara and Eagle Ford assets and for general working capital expenses. The Eagle Ford asset had two producing wells when purchased and we have been receiving revenues since March 2012 from those wells. A well was drilled and completed in July 2012 in the Niobrara asset, resulting in oil revenues from this well in the quarter ended September 30, 2012. In the last quarter of 2012, Condor drilled two additional wells for a total drilling cost (not including fracking or completion costs incurred in 2013) net to our interest of $0.85 million in the Niobrara asset.
 
We had total current assets of $2.8 million as of December 31, 2012, including cash of $2.5 million, compared to total current assets of $0.6 million as of December 31, 2011, including a cash balance of $176,000.
 
We had total assets of $11.4 million as of December 31, 2012 and $2.9 million as of December 31, 2011. Included in total assets as of December 31, 2012 and December 31, 2011 were $2.4 million and $0, respectively, of proved oil and gas properties subject to amortization and $0.9 million and $1.7 million, respectively, in unproved oil and gas properties not subject to amortization,.
 
We had current liabilities of $4.7 million as of December 31, 2012, compared to current and total liabilities of $2.1 million as of December 31, 2011.
 
We had negative working capital of $1.9 million, total stockholders’ equity of $5.2 million and a total accumulated deficit of $12.6 million as of December 31, 2012, compared to negative working capital of $1.4 million, total stockholders’ equity of $0.9 million and a total accumulated deficit of $0.8 million as of December 31, 2011.
 
Cash Flows from Operating Activities. Pacific Energy Development had net cash used in operating activities of $2,804,000 for the year ended December 31, 2012, which was primarily due to a $11,873,000 loss from continuing operations offset by $6,820,000 for impairment of goodwill arising from the merger, $621,000 of stock compensation expense, $508,000 of amortization of financing costs,$358,000 in share of equity investment net loss, $280,000 of preferred stock issued to extend debt maturity and accounted for as interest expense.
 
Cash Flows from Investing Activities. Pacific Energy Development had net cash used in investing activities of $3,742,000 for the year ended December 31, 2012. Cash was used for oil and gas property acquisitions in the amount of $1,500,000, the payment of obligations of Blast related to the merger in the amount of $454,000, and cash funded to White Hawk and Condor as notes receivable in the amount of $2,786,000. This usage of cash was partially offset by $1,000,000 received from the sale of 50% of the White Hawk subsidiary to an affiliate of MIE Holdings.
 
Cash Flows from Financing Activities. Pacific Energy Development had net cash provided from financing activities of $8,848,000 for the year ended December 31, 2012, which was due primarily to the sale of preferred stock.
 
Critical Accounting Policies
 
Our discussion and analysis of our financial condition and results of operations is based on our financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our most significant judgments and estimates used in preparation of our financial statements.
 
Revenue Recognition. All revenue is recognized when persuasive evidence of an arrangement exists, the service or sale is complete, the price is fixed or determinable and collectability is reasonably assured. Revenue is derived from the sale of crude oil. Revenue from crude oil sales is recognized when the crude oil is delivered to the purchaser and collectability is reasonably assured. We follow the “sales method” of accounting for oil and natural gas revenue, which means we recognize revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than our share of the expected remaining proved reserves. If collection is uncertain, revenue is recognized when cash is collected. We recognize reimbursements received from third parties for out-of-pocket expenses incurred as service revenues and account for out-of-pocket expenses as direct costs.
 
Equity Method Accounting for Joint Ventures. The majority of the Company’s oil and gas interests are held all or in part by the following joint ventures which are collectively owned with affiliates of MIE Holdings:
 
 
- Condor Energy Technology LLC, a Nevada limited liability company owned 20% by the Company and 80% by an affiliate of MIE Holdings. The Company accounts for its 20% ownership in Condor using the equity method; and
 
- White Hawk Petroleum, LLC, a Nevada limited liability company owned 50% by the Company and 50% by an affiliate of MIE Holdings. The Company accounts for its 50% interest in White Hawk using the equity method.
 
The Company evaluated its relationship with Condor and White Hawk to determine if either qualified as a variable interest entity ("VIE"), as defined in ASC 810-10, and whether the Company is the primary beneficiary, in which case consolidation would be required. The Company determined that both Condor and White Hawk qualified as a VIE, but since the Company is not the primary beneficiary of either Condor or White Hawk that consolidation was not required for either entity.
 
Oil and Gas Properties, Successful Efforts Method. The successful efforts method of accounting is used for oil and gas exploration and production activities. Under this method, all costs for development wells, support equipment and facilities, and proved mineral interests in oil and gas properties are capitalized. Geological and geophysical costs are expensed when incurred. Costs of exploratory wells are capitalized as exploration and evaluation assets pending determination of whether the wells find proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
 
Exploratory wells in areas not requiring major capital expenditures are evaluated for economic viability within one year of completion of drilling. The related well costs are expensed as dry holes if it is determined that such economic viability is not attained. Otherwise, the related well costs are reclassified to oil and gas properties and subject to impairment review. For exploratory wells that are found to have economically viable reserves in areas where major capital expenditure will be required before production can commence, the related well costs remain capitalized only if additional drilling is under way or firmly planned. Otherwise the related well costs are expensed as dry holes.
 
Exploration and evaluation expenditures incurred subsequent to the acquisition of an exploration asset in a business combination are accounted for in accordance with the policy outlined above.
 
The cost of oil and gas properties is amortized at the field level based on the unit of production method. Unit of production rates are based on oil and gas reserves and developed producing reserves estimated to be recoverable from existing facilities based on the current terms of the respective production agreements. The Company’s reserve estimates represent crude oil and natural gas which management believes can be reasonably produced within the current terms of their production agreements.
 
Accounting for Asset Retirement Obligations. If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we will record a liability (an asset retirement obligation or “ARO”) on our consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation assuming the normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for our company. After recording these amounts, the ARO will be accreted to its future estimated value using the same assumed cost of funds and the capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. Both the accretion and the depreciation will be included in depreciation, depletion and amortization expense on our consolidated statement of income.
 
Stock-Based Compensation. Pursuant to the provisions of FASB ASC 718, Compensation – Stock Compensation, which establishes accounting for equity instruments exchanged for employee service, we utilize the Black-Scholes option pricing model to estimate the fair value of employee stock option awards at the date of grant, which requires the input of highly subjective assumptions, including expected volatility and expected life. Changes in these inputs and assumptions can materially affect the measure of estimated fair value of our share-based compensation. These assumptions are subjective and generally require significant analysis and judgment to develop. When estimating fair value, some of the assumptions will be based on, or determined from, external data and other assumptions may be derived from our historical experience with stock-based payment arrangements. The appropriate weight to place on historical experience is a matter of judgment, based on relevant facts and circumstances. We estimate volatility by considering historical stock volatility. We have opted to use the simplified method for estimating expected term, which is equal to the midpoint between the vesting period and the contractual term.
 
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
 
Not required under Regulation S-K for “smaller reporting companies.”
 
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
 
The audited consolidated financial statements and supplementary data required by this Item are presented beginning on page F-1 of this Annual Report on Form 10-K.
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
 
None.
 
ITEM 9A. CONTROLS AND PROCEDURES.
 
Disclosure Controls and Procedures
 
Disclosure controls and procedures are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) is recorded, processed, summarized and reported, within the time period specified in the SEC’s rules and forms and is accumulated and communicated to the Company’s management, as appropriate, in order to allow timely decisions in connection with required disclosure.
 
Evaluation of Disclosure Controls and Procedures
 
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”), as of the end of the period covered by this quarterly report. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of December 31, 2012, that our disclosure controls and procedures were not effective because of the material weakness in internal control over financial reporting described below.
 
As a result of our merger with Blast Energy Services, Inc. and the formative stage of our development, the Company has not fully implemented the necessary internal controls for the combined entities. The matters involving internal controls and procedures that the Company's management considered to be material weaknesses under the standards of the Committee of Sponsoring Organizations of the Treadway Commission (COSO) were: (1) insufficient written policies and procedures for accounting and financial reporting with respect to the requirements and application of accounting principles generally accepted in the United States of America (“GAAP”) and SEC disclosure requirements; and (2) ineffective controls over period end financial disclosure and reporting processes.
 
Management believes that the material weaknesses set forth above did not have an effect on the Company's financial results reported herein. We are committed to improving our financial organization. As part of this commitment, we will increase our personnel resources and technical accounting expertise as we develop the internal and financial resources of the Company. In addi