ITEM 1. BUSINESS.
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.
(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:
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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.
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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:
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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
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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.
(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:
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damage to or destruction of property, equipment and the environment; and
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personal injury or loss of life; and,
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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.
ITEM 1A.
ITEM 1A. RISK FACTORS.
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:
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general economic and industry conditions, including the prices received for oil and natural gas;
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shortages of, or delays in, obtaining equipment, including hydraulic fracturing equipment, and qualified personnel;
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potential drainage by operators on adjacent properties;
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loss of or damage to oilfield development and service tools;
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problems with title to the underlying properties;
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increases in severance taxes;
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adverse weather conditions that delay drilling activities or cause producing wells to be shut down;
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domestic and foreign governmental regulations; and
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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:
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the domestic and foreign supply of oil and natural gas;
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the domestic and foreign demand for oil and natural gas;
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the prices and availability of competitors’ supplies of oil and natural gas;
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the actions of the Organization of Petroleum Exporting Countries, or OPEC, and state-controlled oil companies relating to oil price and production controls;
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the price and quantity of foreign imports of oil and natural gas;
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the impact of U.S. dollar exchange rates on oil and natural gas prices;
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domestic and foreign governmental regulations and taxes;
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speculative trading of oil and natural gas futures contracts;
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localized supply and demand fundamentals, including the availability, proximity and capacity of gathering and transportation systems for natural gas;
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the availability of refining capacity;
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the prices and availability of alternative fuel sources;
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weather conditions and natural disasters;
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political conditions in or affecting oil and natural gas producing regions, including the Middle East and South America;
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the continued threat of terrorism and the impact of military action and civil unrest;
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public pressure on, and legislative and regulatory interest within, federal, state and local governments to stop, significantly limit or regulate hydraulic fracturing activities;
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the level of global oil and natural gas inventories and exploration and production activity;
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authorization of exports from the Unites States of liquefied natural gas;
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the impact of energy conservation efforts;
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technological advances affecting energy consumption; and
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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:
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our estimated proved oil and natural gas reserves;
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the amount of oil and natural gas we produce from existing wells;
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the prices at which we sell our production;
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the costs of developing and producing our oil and natural gas reserves;
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our ability to acquire, locate and produce new reserves;
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the ability and willingness of banks to lend to us; and
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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:
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the quality and quantity of available data;
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the interpretation of that data;
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the judgment of the persons preparing the estimate; and
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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:
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unusual or unexpected geologic formations;
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natural disasters;
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adverse weather conditions;
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unanticipated pressures;
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loss of drilling fluid circulation;
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blowouts where oil or natural gas flows uncontrolled at a wellhead;
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cratering or collapse of the formation;
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pipe or cement leaks, failures or casing collapses;
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fires or explosions;
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releases of hazardous substances or other waste materials that cause environmental damage;
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pressures or irregularities in formations; and
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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:
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timing and amount of capital expenditures;
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the operator’s expertise and financial resources;
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the rate of production of reserves, if any;
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approval of other participants in drilling wells; and
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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:
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actual prices we receive for oil and natural gas;
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actual cost and timing of development and production expenditures;
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the amount and timing of actual production; and
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changes in governmental regulations or taxation.
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:
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a significant portion of our cash flows could be used to service our indebtedness;
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a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
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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;
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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
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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:
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personal injuries;
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property damage;
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containment and cleanup of oil and other spills;
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the management and disposal of hazardous materials;
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remediation and clean-up costs; and
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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:
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our actual or anticipated operating and financial performance and drilling locations, including reserves estimates;
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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;
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changes in revenue, cash flows or earnings estimates or publication of reports by equity research analysts;
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speculation in the press or investment community;
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public reaction to our press releases, announcements and filings with the SEC;
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sales of our common stock by us or other shareholders, or the perception that such sales may occur;
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the limited amount of our freely tradable common stock available in the public marketplace;
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general financial market conditions and oil and natural gas industry market conditions, including fluctuations in commodity prices;
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the realization of any of the risk factors presented in this Annual Report;
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the recruitment or departure of key personnel;
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commencement of, or involvement in, litigation;
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the prices of oil and natural gas;
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the success of our exploration and development operations, and the marketing of any oil and natural gas we produce;
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changes in market valuations of companies similar to ours; and
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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.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
ITEM 2.
ITEM 2. PROPERTIES.
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:
(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 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:
(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.
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.
(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.
(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, 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
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 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:
(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.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
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.
ITEM 4. MINE SAFETY DISCLOSURES.
None
PART II
ITEM 5.
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.
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
(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.
ITEM 6. SELECTED FINANCIAL DATA
Not required under Regulation S-K for “smaller reporting companies.”
ITEM 7.
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:
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production volumes;
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realized prices on the sale of oil and natural gas, including the effects of our commodity derivative contracts;
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oil and natural gas production and operating expenses;
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capital expenditures;
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general and administrative expenses;
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net cash provided by operating activities; and
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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 Gas. The 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.
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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK.
Not required under Regulation S-K for “smaller reporting companies.”
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The audited consolidated financial statements and supplementary data required by this Item are presented beginning on page of this Annual Report on Form 10-K.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
ITEM 9A.
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 addition, at that time, the Company will prepare and implement sufficient written policies and checklists which will set forth procedures for accounting and financial reporting with respect to the requirements and application of GAAP and SEC disclosure requirements.
Management believes that preparing and implementing sufficient written policies and checklists will remedy the following material weaknesses (i) insufficient written policies and procedures for accounting and financial reporting with respect to the requirements and application of GAAP and SEC disclosure requirements; and (ii) ineffective controls over period end financial close and reporting processes.
We will continue to monitor and evaluate the effectiveness of our internal controls and procedures and our internal controls over financial reporting on an ongoing basis and are committed to taking further action and implementing additional enhancements or improvements, as necessary and as funds allow.
Management’s Report on Internal Control Over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP, but because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. The Company’s internal control over financial reporting includes those policies and procedures that:
●
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
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provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
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provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.
As a result of the merger described above, there were changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the period covered by this report that are reasonably likely to materially affect our internal control over financial reporting.
During the year December 31, 2012, we reevaluated our most recent assessment of internal controls in conjunction with increased levels of activities in the development its operations and noted material weaknesses, discussed above, that changed our assessment of internal controls from effective to not effective. In order to remediate the weaknesses identified above, the Company is in the process of hiring additional accounting staff to provide more resources and expand the technical accounting knowledge.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal controls over financial reporting during the fourth quarter of the year ended December 31, 2012, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
Limitations on the Effectiveness of Controls
The Company’s disclosure controls and procedures provide the Company’s Chief Executive Officer and Chief Financial Officer with reasonable assurances that the Company’s disclosure controls and procedures will achieve their objectives. However, the Company’s management does not expect that the Company’s disclosure controls and procedures or the Company’s internal control over financial reporting can or will prevent all human error. A control system, no matter how well designed and implemented, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Furthermore, the design of a control system must reflect the fact that there are internal resource constraints, and the benefit of controls must be weighed relative to their corresponding costs. Because of the limitations in all control systems, no evaluation of controls can provide complete assurance that all control issues and instances of error, if any, within the Company’s company are detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur due to human error or mistake. Additionally, controls, no matter how well designed, could be circumvented by the individual acts of specific persons within the organization. The design of any system of controls is also based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated objectives under all potential future conditions.
Attestation Report of the Registered Public Accounting Firm
This report does not include an attestation report of our registered public accounting firm regarding our internal controls over financial reporting. Under SEC rules, such attestation is not required for smaller reporting companies such as ourselves.
ITEM 9B.
ITEM 9B. OTHER INFORMATION.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.
Executive Officers, Directors and Director Nominees
The following table sets forth the name, age and position held by each of our executive officers and directors. Directors are elected for a period of one year and thereafter serve until the next annual meeting at which their successors are duly elected by the shareholders.
(1)
Elizabeth P. Smith and David C. Crikelair have agreed to become directors effective upon the completion of the Company’s pending public offering of its securities as contemplated by that certain Registration Statement on Form S-1 filed by the Company with the Securities and Exchange Commission on October 10, 2012, as amended (the “Pending Public Offering”). Messrs. Peterson and Tseng have agreed to resign from our Board of Directors and be replaced by Director nominees Ms. Smith and Mr. Crikelair, upon completion of such offering.
Except for the foregoing, there is no arrangement or understanding between our director and executive officer and any other person pursuant to which any director or officer was or is to be selected as a director or officer, and there is no arrangement, plan or understanding as to whether non-management shareholders will exercise their voting rights to continue to elect the current board of directors. There are also no arrangements, agreements or understandings to our knowledge between non-management shareholders that may directly or indirectly participate in or influence the management of our affairs.
Business Experience
The following is a brief description of the business experience and background of our current directors and executive officers and our director nominees. There are no family relationships among any of the directors, director nominees or executive officers.
Frank C. Ingriselli, Executive Chairman of the Board, President and Chief Executive Officer
Mr. Ingriselli has served as our Executive Chairman of the Board, Chief Executive Officer and President since our acquisition of Pacific Energy Development in July 2012. Mr. Ingriselli has served as the President, Chief Executive Officer and Director of Pacific Energy Development since its inception. Mr. Ingriselli began his career at Texaco, Inc. in 1979 and held management positions in Texaco’s Producing-Eastern Hemisphere Department, Middle East/Far East Division, and Texaco’s International Exploration Company. While at Texaco, Mr. Ingriselli negotiated a successful foreign oil development investment contract in China in 1983. In 1992, Mr. Ingriselli was named President of Texaco International Operations Inc. and over the next several years directed Texaco’s global initiatives in exploration and development. In 1996, he was appointed President and CEO of the Timan Pechora Company, a Houston, Texas headquartered company owned by affiliates of Texaco, Exxon, Amoco and Norsk Hydro, which was developing an investment in Russia. In 1998, Mr. Ingriselli returned to Texaco’s Executive Department with responsibilities for Texaco’s power and natural gas operations, merger and acquisition activities, pipeline operations and corporate development. In August 2000, Mr. Ingriselli was appointed President of Texaco Technology Ventures, which was responsible for all of Texaco’s global technology initiatives and investments. In 2001, Mr. Ingriselli retired from Texaco after its merger with Chevron, and founded Global Venture Investments LLC, which we refer to as GVEST, an energy consulting firm, for which Mr. Ingriselli continues to serve as the President and Chief Executive Officer. We believe Mr. Ingriselli’s positions with GVEST require only an immaterial amount of Mr. Ingriselli’s time and do not conflict with his roles or responsibilities with our company. In 2005, Mr. Ingriselli co-founded CAMAC Energy Inc. (NYSE: CAK) (formerly Pacific Asia Petroleum, Inc.) an independent energy company headquartered in Houston, Texas, and served as its President, Chief Executive Officer and a member of its Board of Directors from 2005 to July 2010.
From 2000 to 2006, Mr. Ingriselli sat on the Board of the Electric Drive Transportation Association (where he was also Treasurer) and the Angelino Group, and was an officer of several subsidiaries of Energy Conversion Devices Inc., a U.S. public corporation engaged in the development and commercialization of environmental energy technologies. From 2001 to 2006, he was a Director and Officer of General Energy Technologies Inc., a “technology facilitator” to Chinese industry serving the need for advanced energy technology and the demand for low-cost high quality components, and Eletra Ltd, a Brazilian hybrid electric bus developer. Mr. Ingriselli currently sits on the Advisory Board of the Eurasia Foundation, a Washington D.C.-based non-profit that funds programs that build democratic and free market institutions in the new independent states of the former Soviet Union. Since 2006, Mr. Ingriselli has also served on the board of directors and as an executive officer of Brightening Lives Foundation Inc., a New York charitable foundation headquartered in Danville, California.
Mr. Ingriselli graduated from Boston University in 1975 with a Bachelor of Science degree in Business Administration. He also earned a Master of Business Administration degree from New York University in both Finance and International Finance in 1977 and a Juris Doctor degree from Fordham University School of Law in 1979.
Mr. Ingriselli brings to the board over 33 years’ experience in the energy industry. The board of directors believes that Mr. Ingriselli’s experience with our company’s recently acquired subsidiary Pacific Energy Development and the insights he has gained from these experiences will benefit our company’s future plans to evaluate and acquire additional oil producing properties and that they qualify him to serve as a director for our company.
Michael L. Peterson, Chief Financial Officer and Executive Vice President
Mr. Peterson has served as our Chief Financial Officer and Executive Vice President since our acquisition of Pacific Energy Development in July 2012. Mr. Peterson joined Pacific Energy Development as its Executive Vice President in September 2011 and assumed the additional office of Chief Financial Officer in June 2012. Mr. Peterson formerly served as Interim President and CEO (from June 2009 to December 2011) and as director (from May 2008 to December 2011) of Blast, as a director (from May 2006 to July 2012) of Aemetis, Inc. (formerly AE Biofuels Inc.), a Cupertino, California-based global advanced biofuels and renewable commodity chemicals company (AMTX), and as Chairman and Chief Executive Officer of Nevo Energy, Inc. (NEVE) (formerly Solargen Energy, Inc.), a Cupertino, California-based developer of utility-scale solar farms which he helped form in December 2008 (from December 2008 to July 2012). In addition, since February 2006, Mr. Peterson has served as founder and managing partner of California-based Pascal Management, a manager of hedge and private equity investments, which we believe requires only an immaterial amount of Mr. Peterson’s time and does not conflict with his roles or responsibilities with our company. From 2005 to 2006, Mr. Peterson co-founded and became a managing partner of American Institutional Partners, a venture investment fund based in Salt Lake City. From 2000 to 2004, he served as a First Vice President at Merrill Lynch, where he helped establish a new private client services division to work exclusively with high net worth investors. From September 1989 to January 2000, Mr. Peterson was employed by Goldman Sachs & Co. in a variety of positions and roles, including as a Vice President with the responsibility for a team of professionals that advised and managed over $7 billion in assets. Mr. Peterson speaks Mandarin Chinese.
Mr. Peterson received his MBA at the Marriott School of Management and a BS in statistics/computer science from Brigham Young University.
Our board of directors believes that Mr. Peterson brings to our board of directors extensive experience in the energy, corporate finance and securities sectors, which will provide crucial guidance for our company’s capital raising efforts.
Jamie Tseng, Senior Vice President, Managing Director and Director
Mr. Tseng has served as our Senior Vice President, Managing Director and a director since our acquisition of Pacific Energy Development in July 2012. Mr. Tseng has served as Pacific Energy Development’s Senior Vice President, Managing Director and director, since its inception, and as Chief Financial Officer from inception until June 2012. In 2005, Mr. Tseng co-founded CAMAC Energy Inc. (NYSE: CAK) (formerly Pacific Asia Petroleum, Inc.), an independent energy company headquartered in Houston, Texas, and served as its Executive Vice President from 2005 through his retirement from our company in January 2010. From February 2000 to August 2005, Mr. Tseng served as Chief Financial Officer of General Energy Technologies Inc., a “technology facilitator” to Chinese industry serving the need for advanced energy technology and the demand for low cost high quality components. From 1998 to February 2000, Mr. Tseng served as Chief Financial Officer of Multa Communications Corporation, a California-based Internet service provider focusing on China. From 1980 until 1998, he held management positions with Collins Company, Hilton International, China Airlines and Tatung Company of America. Mr. Tseng is fluent in Chinese Mandarin. He has a BD degree in Accounting from Soochow University in Taiwan.
Mr. Tseng brings to our board of directors more than 25 years of financial management and operations experience in the People’s Republic of China, the Republic of China and the U.S. The board of directors believes that Mr. Tseng’s experience with our company’s recently acquired subsidiary Pacific Energy Development and the insights he has gained from these experiences will benefit our company’s future plans to evaluate and acquire additional oil producing properties and that they qualify him to serve as a director for our company.
Clark R. Moore, Executive Vice President, General Counsel and Secretary
Mr. Moore has served as our Executive Vice President, General Counsel, and Secretary since our acquisition of Pacific Energy Development in July 2012 and has served as the Executive Vice President, General Counsel, and Secretary of Pacific Energy Development since its inception. Mr. Moore began his career in 2000 as a corporate attorney at the law firm of Venture Law Group located in Menlo Park, California, which later merged into Heller Ehrman LLP in 2003. In 2004, Mr. Moore left Heller Ehrman LLP and launched a legal consulting practice focused on representation of private and public company clients in the energy and high-tech industries. In September 2006, Mr. Moore joined CAMAC Energy Inc. (NYSE: CAK) (formerly Pacific Asia Petroleum, Inc.), an independent energy company headquartered in Houston, Texas, as its acting General Counsel and continued to serve in that role through June 2011.
Mr. Moore received his J.D. with Distinction from Stanford Law School and his B.A. with Honors from the University of Washington.
Elizabeth P. Smith, Director Nominee
Ms. Smith will be appointed to our Board of Directors effective upon the completion of the Pending Public Offering. Ms. Smith retired from Texaco Inc. as Vice President-Investor Relations and Shareholder Services in late 2001 following its merger with Chevron Corp. Ms. Smith was also the Corporate Compliance Officer for Texaco and was a member of the Board of The Texaco Foundation. Ms. Smith joined Texaco’s Legal Department in 1976. As an attorney in the Legal Department, Ms. Smith handled administrative law matters and litigation. She served as Chairman of the American Petroleum Institute’s Subcommittee on Department of Energy Law for the 1983-1985 term. Ms. Smith was appointed Director of Investor Relations for Texaco, Inc. in 1984, and was named Vice President of the Corporate Communications division in 1989. In 1992, Ms. Smith was elected a Vice President of Texaco Inc. and assumed additional responsibilities as head of that company’s Shareholder Services Group. In 1999, Ms. Smith was named Corporate Compliance Officer for Texaco. Ms. Smith served as a Director of Pacific Asia Petroleum, Inc. until its merger with CAMAC Energy, Inc. in April of 2010.
Ms. Smith was elected to the Board of Finance of Darien, Connecticut, in November 2007, and since November 2010, has been serving as the Chairman. In June of 2012, Ms. Smith was elected a Trustee of St. Luke’s School in New Canaan, Connecticut. From 2007 through 2010, Ms. Smith has also served as a Board Member of the Community Fund of Darien, Connecticut, and from 1996 through 2006, Ms. Smith served on the board of directors of INROADS/Fairfield Westchester Counties, Inc. From 2002 through 2005 Ms. Smith served as a member of the Board of Families With Children From China-Greater New York, and from 2004 through 2005 she served as a member of the Board of The Chinese Language School of Connecticut. While at Texaco, Ms. Smith was an active member in NIRI (National Investor Relations Institute) and the NIRI Senior Roundtable. She has been a member and past President of both the Investor Relations Association and the Petroleum Investor Relations Institute. Ms. Smith was a member of the Board of Trustees of Marymount College Tarrytown from 1993 until 2001. She was also a member of the Board of The Education and Learning Foundation of Westchester and Putnam Counties from 1993 to 2002.
Ms. Smith graduated from Bucknell University in 1971 with a Bachelor of Arts degree, cum laude, and received a Doctor of Jurisprudence degree from Georgetown University Law Center in 1976.
The board of directors believes that Ms. Smith’s over 30 years’ experience in corporate compliance, investor relations, and law in the energy industry working at a major U.S. oil and gas company, and the insights she has gained from these experiences, will provide crucial guidance for our company’s future operations and compliance efforts.
David C. Crikelair, Director Nominee
Mr. Crikelair will be appointed to our Board of Directors effective upon the completion of the Pending Public Offering. Mr. Crikelair has more than 40 years of experience in the oil and gas industry, and has broad experience in the areas of corporate finance, banking, capital markets and financial reporting. Since 2001, Mr. Crikelair has been as co-owner and serves as a Managing Partner of FrontStreet Partners, LLC, a privately-held energy and real estate investment firm. Previously, Mr. Crikelair spent most of his career with Texaco Inc. and Affiliates, serving in various financial and operating positions, including: Vice President of Texaco Inc. (1991 - 1999), corporate Treasurer (1986 - 1991), and Head of the Alternate Energy Department (1991 - 1996), responsible for worldwide co-generation and power businesses, technology licensing, gasification business, ethanol manufacturing, intellectual property, and non-oil and gas natural resources. Mr. Crikelair also served as Chief Financial Officer of Equilon Enterprises, LLC (1998 - 1999), the major Houston based joint venture of the Shell Oil Company and Texaco Inc. focused on the refining, marketing, trading, transportation and lubricant businesses. Mr. Crikelair also served as a Director of Caltex Petroleum Corporation, the principal international refining and marketing joint venture company owned by Texaco Inc. and Chevron. He also served as Chief Financial Officer for a privately-held software company focused on collaborative supply chain activities.
Mr. Crikelair has served as a member of various not for profit community and governmental organizations and boards. He continues to be involved in a number of charitable organizations. Mr. Crikelair graduated from Franklin and Marshall College in 1969 with a Bachelor of Arts degree in Mathematics and received a Masters of Business Administration in Corporate Finance from the New York University Graduate School of Business Administration in 1971.
The board of directors believes that Mr. Crikelair’s over 40 years’ experience in corporate finance, banking, capital markets and financial reporting in the energy industry, and the insights he has gained from these experiences, will provide crucial guidance for our company’s future operations, capital raising efforts, and oversight of our financial reporting and internal controls.
Director Qualifications
The Board believes that each of our directors is highly qualified to serve as a member of the Board. Each of the directors has contributed to the mix of skills, core competencies and qualifications of the Board. When evaluating candidates for election to the Board, the Board seeks candidates with certain qualities that it believes are important, including integrity, an objective perspective, good judgment, and leadership skills. Our directors are highly educated and have diverse backgrounds and talents and extensive track records of success in what we believe are highly relevant positions.
Involvement in Certain Legal Proceedings
To the best of our knowledge, during the past five years, none of our directors or executive officers were involved in any of the following: (1) any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time; (2) any conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses); (3) being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; and (4) being found by a court of competent jurisdiction (in a civil action), the SEC or the Commodities Futures Trading Commission to have violated a federal or state securities or commodities law, and the judgment has not been reversed, suspended or vacated.
Director Independence
Our board of directors has determined that none of our current directors is an independent director as defined in the NYSE MKT rules governing members of boards of directors or as defined under Rule 10A-3 of the Securities Exchange Act of 1934, as amended, which we refer to as the Exchange Act.
Effective upon completion of the Pending Public Offering, two of our three current directors, Messrs. Peterson and Tseng, will resign and Ms. Smith and Mr. Crikelair, each of whom has agreed to serve as a director effective upon the completion of the Pending Public Offering, will be appointed to the board. Our board of directors has determined that Ms. Smith and Mr. Crikelair will each be an independent director as defined in the NYSE MKT rules governing members of boards of directors and as defined under Rule 10A-3 of the Exchange Act. Therefore, effective upon completion of the Pending Public Offering, a majority of the members of our board of directors will be independent as defined in the NYSE MKT rules governing members of boards of directors and as defined under Rule 10A-3 of the Exchange Act.
Committees of our Board of Directors
The Company has no separate committees and all matters of corporate governance are addressed by the full board of directors. The disinterested directors vote on all matters involving directors and their separate interests. All members of the board will serve until the next annual meeting of shareholders and until successors are elected and qualified by our shareholders, or until their retirement, resignation or removal.
The board currently has neither a separate audit committee nor an “audit committee financial expert” as defined by applicable SEC rules. The board plans to establish a separate audit committee in the near future and, if established, will search for one or more qualified individuals to serve on the committee and as the Board’s “audit committee financial expert.”
Code of Ethics
In 2012, in accordance with SEC rules, our board of directors adopted a Code of Business Conduct and Ethics for our directors, officers and employees. Our board of directors believes that these individuals must set an exemplary standard of conduct. This code sets forth ethical standards to which these persons must adhere and other aspects of accounting, auditing and financial compliance, as applicable. The Code of Business Conduct and Ethics is available on our website at www.pacificenergydevelopment.com. Please note that the information contained on our website is not incorporated by reference in, or considered to be a part of, this Annual Report.
Shareholder Communications
Currently, we do not have a policy with regard to the consideration of any director candidates recommended by security holders. To date, no security holders have made any such recommendations.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our executive officers and directors and persons who own more than 10% of a registered class of our equity securities to file with the SEC initial statements of beneficial ownership, reports of changes in ownership and annual reports concerning their ownership in our common stock and other equity securities, on Form 3, 4 and 5 respectively. Executive officers, directors and greater than 10% shareholders are required by the SEC regulations to furnish our company with copies of all Section 16(a) reports they file.
Based solely on our review of the copies of such reports received by us and on written representation by our officers and directors regarding their compliance with the applicable reporting requirements under Section 16(a) of the Exchange Act, we believe that with respect to the fiscal year ended December 31, 2012, our directors, executive officers and 10% stockholders complied with all Section 16(a) filing requirements.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
Upon completion of the Pacific Energy Development merger, our then existing directors and officers resigned and we appointed our current officers and directors.
Executive Employment Agreements
Frank Ingriselli. Pacific Energy Development, our wholly owned subsidiary, has entered into an employment agreement with Frank Ingriselli, its Chairman, President and Chief Executive Officer, pursuant to which, effective June 15, 2011, Mr. Ingriselli has been employed by Pacific Energy Development, and since the Pacific Energy Development merger, our company, with a base annual salary of $200,000 ($350,000 commencing November 1, 2011), and a target annual cash bonus of between 20% and 40% of his base salary, awardable by the board of directors in its discretion. In addition, Mr. Ingriselli’s employment agreement includes, among other things, severance payment provisions that would require our company to make lump sum payments equal to 36 months’ salary and target bonus to Mr. Ingriselli in the event his employment is terminated without “Cause” or if he voluntarily resigns for “Good Reason” (48 months in connection with a “Change of Control”), and continuation of benefits for up to 48 months, as such terms are defined below. The employment agreement also prohibits Mr. Ingriselli from engaging in competitive activities during and following termination of his employment that would result in disclosure of company’s confidential information, but does not contain a general restriction on engaging in competitive activities.
For purposes of Mr. Ingriselli’s employment agreement, the term “Cause” shall mean his (1) conviction of, or plea of nolo contendere to, a felony or any other crime involving moral turpitude; (2) fraud on or misappropriation of any funds or property of our company or any of its affiliates, customers or vendors; (3) act of material dishonesty, willful misconduct, willful violation of any law, rule or regulation, or breach of fiduciary duty involving personal profit, in each case made in connection with his responsibilities as an employee, officer or director of our company and which has, or could reasonably be deemed to result in, a Material Adverse Effect upon our company; (4) illegal use or distribution of drugs; (5) material violation of any policy or code of conduct of our company; or (6) material breach of any provision of the employment agreement or any other employment, non-disclosure, non-competition, non-solicitation or other similar agreement executed by him for the benefit of our company or any of its affiliates, all as reasonably determined in good faith by the board of directors of our company. However, an event that is or would constitute “Cause” shall cease to be “Cause” if he reverses the action or cures the default that constitutes “Cause” within 10 days after our company notifies his in writing that Cause exists. No act or failure to act on Mr. Ingriselli’s part will be considered “willful” unless it is done, or omitted to be done, by him in bad faith or without reasonable belief that such action or omission was in the best interests of our company. Any act or failure to act that is based on authority given pursuant to a resolution duly passed by the board of directors, or the advice of counsel to our company, shall be conclusively presumed to be done, or omitted to be done, in good faith and in the best interests of our company.
For purposes of the employment agreement, “Material Adverse Effect” means any event, change or effect that is materially adverse to the condition (financial or otherwise), properties, assets, liabilities, business, operations or results of operations of our company or its subsidiaries, taken as a whole.
For purposes of Mr. Ingriselli’s employment agreement, “Good Reason” means the occurrence of any of the following without his written consent: (a) the assignment to him of duties substantially inconsistent with this employment agreement or a material adverse change in his titles or authority; (b) any failure by our company to comply with the compensation provisions of the agreement in any material way; (c) any material breach of the employment agreement by our company; or (d) the relocation of him by more than fifty (50) miles from the location of our company’s principal office located in Danville, California. However, an event that is or would constitute “Good Reason” shall cease to be “Good Reason” if: (i) he does not terminate employment within 45 days after the event occurs; (ii) before he terminates employment, our company reverses the action or cures the default that constitutes “Good Reason” within 10 days after he notifies us in writing that Good Reason exists; or (iii) he was a primary instigator of the “Good Reason” event and the circumstances make it inappropriate for him to receive “Good Reason” termination benefits under the employment agreement (e.g., he agrees temporarily to relinquish his position on the occurrence of a merger transaction he assists in negotiating).
For purposes of Mr. Ingriselli’s employment agreement, “Change of Control” means: (i) a merger, consolidation or sale of capital stock by existing holders of capital stock of our company that results in more than 50% of the combined voting power of the then outstanding capital stock of our company or its successor changing ownership; (ii) the sale, or exclusive license, of all or substantially all of our company’s assets; or (iii) the individuals constituting our company’s board of directors as of the date of the employment agreement (the “Incumbent Board”) cease for any reason to constitute at least 1/2 of the members of the board of directors; provided, however, that if the election, or nomination for election by our stockholders, of any new director was approved by a vote of the Incumbent Board, such new director shall be considered a member of the Incumbent Board. Notwithstanding the foregoing and for purposes of clarity, a transaction shall not constitute a Change in Control if: (w) its sole purpose is to change the state of our company’s incorporation; (x) its sole purpose is to create a holding company that will be owned in substantially the same proportions by the persons who held our company’s securities immediately before such transaction; or (y) it is a transaction effected primarily for the purpose of financing our company with cash (as determined by the board of directors in its discretion and without regard to whether such transaction is effectuated by a merger, equity financing or otherwise).
Michael L. Peterson. On September 1, 2011, Pacific Energy Development, our wholly owned subsidiary, entered into a Consulting Agreement engaging Michael L. Peterson to serve as Executive Vice President of Pacific Energy Development. This Consulting Agreement was superseded by an employment offer letter dated February 1, 2012, which employment offer letter was later amended and restated in full on June 16, 2012. Pursuant to Mr. Peterson’s current employment offer letter, Mr. Peterson serves as our company’s Chief Financial Officer and Executive Vice President at an annual base salary of $275,000, and a target annual cash bonus of between 20% and 40% of his base salary, awardable by the board of directors in its discretion. In addition, Mr. Peterson’s employment offer letter includes, among other things, severance payment provisions that would require our company to make lump sum payments equal to 12 months’ salary to Mr. Peterson and accelerate 12 months’ of equity vesting in the event his employment is terminated without “cause”, as such term is defined below, or upon his death. Mr. Peterson previously served as a member of the board of directors and as the Interim President and Chief Executive Officer of Blast.
We have also issued to Mr. Peterson an option to purchase 300,000 shares of our company’s common stock, with an exercise price of $0.08 per share, vesting 50% on March 1, 2012, 25% on June 1, 2012, and the balance of 25% on January 1, 2013, subject to Mr. Peterson’s continued service as an employee, officer, director or consultant to our company. In addition, Mr. Peterson holds an aggregate of 1,450,000 shares of restricted common stock of the Company, of which (a) 700,000 are subject to forfeiture in the event Mr. Peterson is no longer an employee, officer, director or consultant to our company, which risk of forfeiture lapsed with respect to 50% of the shares on June 1, 2012, and which risk of forfeiture will lapse with respect to the remaining 25% of the shares on December 1, 2012, and the balance of 25% of the shares on June 1, 2013 (this vesting schedule was adopted on February 9, 2012, and superseded the original vesting schedule which provided for vesting based on achievement of Pacific Energy Development fundraising and “going public” milestones), and (b) 750,000 are subject to forfeiture in the event Mr. Peterson is no longer an employee, officer, director or consultant to Pacific Energy Development, which risk of forfeiture lapsed with respect to 50% of the shares on August 9, 2012, and which risk of forfeiture will lapse with respect to the remaining 20% of the shares on February 9, 2013, 20% of the shares on August 9, 2013, and the balance of 10% of the shares on February 9, 2014. If our company terminates Mr. Peterson’s employment or consulting relationship without “Cause”, then 100% of the options and restricted stock granted to Mr. Peterson will automatically vest. In connection with our acquisition of our company, we have assumed these option obligations.
In addition, on January 11, 2013, Mr. Peterson’s employment offer letter was amended to revise the termination and severance provisions to parallel those of Mr. Clark Moore, our Executive Vice President, Secretary and General Counsel, as described below. Mr. Peterson’s employment offer letter amendment provides for, among other things, severance payment provisions that would require our company to make lump sum payments equal to 18 months’ salary and target bonus to Mr. Peterson in the event his employment is terminated due to his death or disability, terminated without “Cause” or if he voluntarily resigns for “Good Reason” (36 months in connection with a “Change of Control”), and continuation of benefits for up to 36 months (48 months in connection with a “Change of Control”), as such terms are defined below.
For purposes of Mr. Peterson’s employment offer letter amendment, the term “Cause” shall mean his (1) conviction of, or plea of nolo contendere to, a felony or any other crime involving moral turpitude; (2) fraud on or misappropriation of any funds or property of our company or any of its affiliates, customers or vendors; (3) act of material dishonesty, willful misconduct, willful violation of any law, rule or regulation, or breach of fiduciary duty involving personal profit, in each case made in connection with his responsibilities as an employee, officer or director of our company and which has, or could reasonably be deemed to result in, a Material Adverse Effect upon our company; (4) illegal use or distribution of drugs; (5) material violation of any policy or code of conduct of our company; or (6) material breach of any provision of the employment agreement or any other employment, non-disclosure, non-competition, non-solicitation or other similar agreement executed by him for the benefit of our company or any of its affiliates, all as reasonably determined in good faith by our board of directors. However, an event that is or would constitute “Cause” shall cease to be “Cause” if he reverses the action or cures the default that constitutes “Cause” within 10 days after our company notifies his in writing that Cause exists. No act or failure to act on Mr. Peterson’s part will be considered “willful” unless it is done, or omitted to be done, by him in bad faith or without reasonable belief that such action or omission was in the best interests of our company. Any act or failure to act that is based on authority given pursuant to a resolution duly passed by the board of directors, or the advice of counsel to our company, shall be conclusively presumed to be done, or omitted to be done, in good faith and in the best interests of our company.
For purposes of the employment offer letter amendment, “Material Adverse Effect” means any event, change or effect that is materially adverse to the condition (financial or otherwise), properties, assets, liabilities, business, operations or results of operations of our company or its subsidiaries, taken as a whole.
For purposes of Mr. Peterson’s employment offer letter amendment, “Good Reason” means the occurrence of any of the following without his written consent: (a) the assignment to him of duties substantially inconsistent with this employment agreement or a material adverse change in his titles or authority; (b) any failure by our company to comply with the compensation provisions of the agreement in any material way; (c) any material breach of the employment agreement by our company; or (d) the relocation of him by more than fifty (50) miles from the location of our company’s principal office located in Danville, California. However, an event that is or would constitute “Good Reason” shall cease to be “Good Reason” if: (i) he does not terminate employment within 45 days after the event occurs; (ii) before he terminates employment, our company reverses the action or cures the default that constitutes “Good Reason” within 10 days after he notifies our company in writing that Good Reason exists; or (iii) he was a primary instigator of the “Good Reason” event and the circumstances make it inappropriate for him to receive “Good Reason” termination benefits under the employment agreement (e.g., he agrees temporarily to relinquish his position on the occurrence of a merger transaction he assists in negotiating).
For purposes of Mr. Peterson’s employment offer letter amendment, “Change of Control” means: (i) a merger, consolidation or sale of capital stock by existing holders of our capital stock that results in more than 50% of the combined voting power of the then outstanding capital stock of our company or its successor changing ownership; (ii) the sale, or exclusive license, of all or substantially all of our company’s assets; or (iii) the individuals constituting our company’s board of directors as of the date of the employment agreement (the “Incumbent Board”) cease for any reason to constitute at least 1/2 of the members of the board of directors; provided, however, that if the election, or nomination for election by our company’s stockholders, of any new director was approved by a vote of the Incumbent Board, such new director shall be considered a member of the Incumbent Board. Notwithstanding the foregoing and for purposes of clarity, a transaction shall not constitute a Change in Control if: (w) its sole purpose is to change the state of our company’s incorporation; (x) its sole purpose is to create a holding company that will be owned in substantially the same proportions by the persons who held our company’s securities immediately before such transaction; or (y) it is a transaction effected primarily for the purpose of financing our company with cash (as determined by the board of directors in its discretion and without regard to whether such transaction is effectuated by a merger, equity financing or otherwise).
Jamie Tseng. On January 6, 2012, Pacific Energy Development, our wholly owned subsidiary, entered into an employment offer letter with Jamie Tseng, Senior Vice President, Director and Managing Director of our company, pursuant to which Mr. Tseng is paid an annual base salary of $120,000.
Clark Moore. Pacific Energy Development, our wholly owned subsidiary, has entered into an employment agreement with Clark Moore, its Executive Vice President, Secretary and General Counsel, pursuant to which, effective June 1, 2011, Mr. Moore has been employed by Pacific Energy Development, and since the Pacific Energy Development merger, our company, with a base annual salary of $150,000 ($250,000 commencing November 1, 2011), and a target annual cash bonus of between 20% and 40% of his base salary, awardable by the board of directors in its discretion. In addition, Mr. Moore’s employment agreement includes, among other things, severance payment provisions that would require our company to make lump sum payments equal to 18 months’ salary and target bonus to Mr. Moore in the event his employment is terminated without “Cause” or if he voluntarily resigns for “Good Reason” (36 months in connection with a “Change of Control”), and continuation of benefits for up to 36 months (48 months in connection with a “Change of Control”), as such terms are defined below. The employment agreement also prohibits Mr. Moore from engaging in competitive activities during and following termination of his employment that would result in disclosure of our company’s confidential information, but does not contain a general restriction on engaging in competitive activities.
For purposes of Mr. Moore’s employment agreement, the term “Cause” shall mean his (1) conviction of, or plea of nolo contendere to, a felony or any other crime involving moral turpitude; (2) fraud on or misappropriation of any funds or property of our company or any of its affiliates, customers or vendors; (3) act of material dishonesty, willful misconduct, willful violation of any law, rule or regulation, or breach of fiduciary duty involving personal profit, in each case made in connection with his responsibilities as an employee, officer or director of our company and which has, or could reasonably be deemed to result in, a Material Adverse Effect upon our company; (4) illegal use or distribution of drugs; (5) material violation of any policy or code of conduct of our company; or (6) material breach of any provision of the employment agreement or any other employment, non-disclosure, non-competition, non-solicitation or other similar agreement executed by him for the benefit of our company or any of its affiliates, all as reasonably determined in good faith by our board of directors. However, an event that is or would constitute “Cause” shall cease to be “Cause” if he reverses the action or cures the default that constitutes “Cause” within 10 days after our company notifies his in writing that Cause exists. No act or failure to act on Mr. Moore’s part will be considered “willful” unless it is done, or omitted to be done, by him in bad faith or without reasonable belief that such action or omission was in the best interests of our company. Any act or failure to act that is based on authority given pursuant to a resolution duly passed by the board of directors, or the advice of counsel to our company, shall be conclusively presumed to be done, or omitted to be done, in good faith and in the best interests of our company.
For purposes of the employment agreement, “Material Adverse Effect” means any event, change or effect that is materially adverse to the condition (financial or otherwise), properties, assets, liabilities, business, operations or results of operations of our company or its subsidiaries, taken as a whole.
For purposes of Mr. Moore’s employment agreement, “Good Reason” means the occurrence of any of the following without his written consent: (a) the assignment to him of duties substantially inconsistent with this employment agreement or a material adverse change in his titles or authority; (b) any failure by our company to comply with the compensation provisions of the agreement in any material way; (c) any material breach of the employment agreement by our company; or (d) the relocation of him by more than fifty (50) miles from the location of our company’s principal office located in Danville, California. However, an event that is or would constitute “Good Reason” shall cease to be “Good Reason” if: (i) he does not terminate employment within 45 days after the event occurs; (ii) before he terminates employment, our company reverses the action or cures the default that constitutes “Good Reason” within 10 days after he notifies our company in writing that Good Reason exists; or (iii) he was a primary instigator of the “Good Reason” event and the circumstances make it inappropriate for him to receive “Good Reason” termination benefits under the employment agreement (e.g., he agrees temporarily to relinquish his position on the occurrence of a merger transaction he assists in negotiating).
For purposes of Mr. Moore’s employment agreement, “Change of Control” means: (i) a merger, consolidation or sale of capital stock by existing holders of our capital stock that results in more than 50% of the combined voting power of the then outstanding capital stock of our company or its successor changing ownership; (ii) the sale, or exclusive license, of all or substantially all of our company’s assets; or (iii) the individuals constituting our company’s board of directors as of the date of the employment agreement (the “Incumbent Board”) cease for any reason to constitute at least 1/2 of the members of the board of directors; provided, however, that if the election, or nomination for election by our company’s stockholders, of any new director was approved by a vote of the Incumbent Board, such new director shall be considered a member of the Incumbent Board. Notwithstanding the foregoing and for purposes of clarity, a transaction shall not constitute a Change in Control if: (w) its sole purpose is to change the state of our company’s incorporation; (x) its sole purpose is to create a holding company that will be owned in substantially the same proportions by the persons who held our company’s securities immediately before such transaction; or (y) it is a transaction effected primarily for the purpose of financing our company with cash (as determined by the board of directors in its discretion and without regard to whether such transaction is effectuated by a merger, equity financing or otherwise).
Equity Incentive Plans
2012 Plan
General. On June 26, 2012, our board adopted the Blast Energy Services, Inc. 2012 Equity Incentive Plan, which we refer to as the 2012 Plan, which was approved by our shareholders on July 30, 2012. The 2012 Plan provides for awards of incentive stock options, non-statutory stock options, rights to acquire restricted stock, stock appreciation rights, or SARs, and performance units and performance shares. Subject to the provisions of the 2012 Plan relating to adjustments upon changes in our common stock, an aggregate of 6,000,000 shares of common stock have been reserved for issuance under the 2012 Plan.
Purpose. Our board adopted the 2012 Plan to provide a means by which our employees, directors and consultants may be given an opportunity to benefit from increases in the value of our common stock, to assist in attracting and retaining the services of such persons, to bind the interests of eligible recipients more closely to our company’s interests by offering them opportunities to acquire shares of our common stock and to afford such persons stock-based compensation opportunities that are competitive with those afforded by similar businesses.
Administration. Unless it delegates administration to a committee, our board administers the 2012 Plan. Subject to the provisions of the 2012 Plan, our board has the power to construe and interpret the 2012 Plan, and to determine: (a) the fair value of common stock subject to awards issued under the 2012 Plan; (b) the persons to whom and the dates on which awards will be granted; (c) what types or combinations of types of awards will be granted; (d) the number of shares of common stock to be subject to each award; (e) the time or times during the term of each award within which all or a portion of such award may be exercised; (f) the exercise price or purchase price of each award; and (g) the types of consideration permitted to exercise or purchase each award and other terms of the awards.
Eligibility. Incentive stock options may be granted under the 2012 Plan only to employees of our company and its affiliates. Employees, directors and consultants of our company and its affiliates are eligible to receive all other types of awards under the 2012 Plan.
Terms of Options and SARs. The exercise price of incentive stock options may not be less than the fair market value of the common stock subject to the option on the date of the grant and, in some cases, may not be less than 110% of such fair market value. The exercise price of nonstatutory options also may not be less than the fair market value of the common stock on the date of grant.
Options granted under the 2012 Plan may be exercisable in cumulative increments, or “vest,” as determined by our board. Our board has the power to accelerate the time as of which an option may vest or be exercised. The maximum term of options, SARs and performance shares and units under the 2012 Plan is ten years, except that in certain cases, the maximum term is five years. Options, SARs and performance shares and units awarded under the 2012 Plan generally will terminate three months after termination of the participant’s service, subject to certain exceptions.
A recipient may not transfer an incentive stock option otherwise than by will or by the laws of descent and distribution. During the lifetime of the recipient, only the recipient may exercise an option, SAR or performance share or unit. Our board may grant nonstatutory stock options, SARs and performance shares and units that are transferable to the extent provided in the applicable written agreement.
Terms of Restricted Stock Awards. Our board may issue shares of restricted stock under the 2012 Plan as a grant or for such consideration, including services, and, subject to the Sarbanes-Oxley Act of 2002, promissory notes, as determined in its sole discretion.
Shares of restricted stock acquired under a restricted stock purchase or grant agreement may, but need not, be subject to forfeiture to us or other restrictions that will lapse in accordance with a vesting schedule to be determined by our board. In the event a recipient’s employment or service with our company terminates, any or all of the shares of common stock held by such recipient that have not vested as of the date of termination under the terms of the restricted stock agreement may be forfeited to our company in accordance with such restricted stock agreement.
Rights to acquire shares of common stock under the restricted stock purchase or grant agreement shall be transferable by the recipient only upon such terms and conditions as are set forth in the restricted stock agreement, as our board shall determine in its discretion, so long as shares of common stock awarded under the restricted stock agreement remain subject to the terms of such agreement.
Adjustment Provisions. If any change is made to our outstanding shares of common stock without our receipt of consideration (whether through reorganization, stock dividend or stock split, or other specified change in the capital structure of our company, other than in connection with the reverse stock split discussed above in connection with the Pacific Energy Development merger), appropriate adjustments may be made in the class and maximum number of shares of common stock subject to the 2012 Plan and outstanding awards. In that event, the 2012 Plan will be appropriately adjusted in the class and maximum number of shares of common stock subject to the 2012 Plan, and outstanding awards may be adjusted in the class, number of shares and price per share of common stock subject to such awards.
Effect of Certain Corporate Events. In the event of (a) a liquidation or dissolution of our company; (b) a merger or consolidation of our company with or into another corporation or entity (other than a merger with a wholly-owned subsidiary); (c) a sale of all or substantially all of the assets of our company; or (d) a purchase or other acquisition of more than 50% of the outstanding stock of our company by one person or by more than one person acting in concert, any surviving or acquiring corporation may assume awards outstanding under the 2012 Plan or may substitute similar awards. Unless the stock award agreement otherwise provides, in the event any surviving or acquiring corporation does not assume such awards or substitute similar awards, then the awards will terminate if not exercised at or prior to such event.
Duration, Amendment and Termination. Our board may suspend or terminate the 2012 Plan without stockholder approval or ratification at any time or from time to time. Unless sooner terminated, the 2012 Plan will terminate ten years from the date of its adoption by our board, i.e., in March 2022.
Our board may also amend the 2012 Plan at any time, and from time to time. However, except as relates to adjustments upon changes in common stock, no amendment will be effective unless approved by our stockholders to the extent stockholder approval is necessary to preserve incentive stock option treatment for federal income tax purposes. Our board may submit any other amendment to the 2012 Plan for stockholder approval if it concludes that stockholder approval is otherwise advisable.
As of the date of this Annual Report, 40,000 shares of restricted stock have been issued under the 2012 Plan, with 5,960,000 shares of common stock remaining available for issuance under the 2012 Plan.
2012 Pacific Energy Development (Pre-Merger) Plan
On February 9, 2012, prior to the Pacific Energy Development merger, Pacific Energy Development adopted the Pacific Energy Development 2012 Equity Incentive Plan, which we refer to as the 2012 Pre-Merger Plan. We assumed the obligations of the 2012 Pre-Merger Plan pursuant to the Pacific Energy Development merger, though the 2012 Pre-Merger Plan has been superseded by the 2012 Plan.
The 2012 Pre-Merger Plan provides for awards of incentive stock options, non-statutory stock options, rights to acquire restricted stock, stock appreciation rights, or SARs, and performance units and performance shares. Subject to the provisions of the 2012 Pre-Merger Plan relating to adjustments upon changes in our common stock, an aggregate of 3,000,000 shares of common stock have been reserved for issuance under the 2012 Pre-Merger Plan.
The board of Pacific Energy Development adopted the 2012 Pre-Merger Plan to provide a means by which its employees, directors and consultants may be given an opportunity to benefit from increases in the value of its common stock, to assist in attracting and retaining the services of such persons, to bind the interests of eligible recipients more closely to our company’s interests by offering them opportunities to acquire shares of our common stock and to afford such persons stock-based compensation opportunities that are competitive with those afforded by similar businesses.
The exercise price of incentive stock options may not be less than the fair market value of the common stock subject to the option on the date of the grant and, in some cases, may not be less than 110% of such fair market value. The exercise price of nonstatutory options also may not be less than the fair market value of the common stock on the date of grant. Options granted under the 2012 Pre-Merger Plan may be exercisable in cumulative increments, or “vest,” as determined by the board of Pacific Energy Development at the time of grant.
Shares of restricted stock could be issued under the 2012 Pre-Merger Plan as a grant or for such consideration, including services, and, subject to the Sarbanes-Oxley Act of 2002, promissory notes, as determined in the sole discretion of the Pacific Energy Development board. Shares of restricted stock acquired under a restricted stock purchase or grant agreement could, but need not, be subject to forfeiture or other restrictions that will lapse in accordance with a vesting schedule determined by the board of Pacific Energy Development at the time of grant. In the event a recipient’s employment or service with our company terminates, any or all of the shares of common stock held by such recipient that have not vested as of the date of termination under the terms of the restricted stock agreement may be forfeited to our company in accordance with such restricted stock agreement.
Appropriate adjustments may be made to outstanding awards in the event of changes in our outstanding shares of common stock, whether through reorganization, stock dividend or stock split, or other specified change in capital structure of our company. In the event of liquidation, merger or consolidation, sale of all or substantially all of the assets of our company, or other change in control, any surviving or acquiring corporation may assume awards outstanding under the 2012 Pre-Merger Plan or may substitute similar awards. Unless the stock award agreement otherwise provides, in the event any surviving or acquiring corporation does not assume such awards or substitute similar awards, then the awards will terminate if not exercised at or prior to such event.
As of the date of this Annual Report 855,000 options and 2,117,816 shares of restricted stock remain outstanding under the 2012 Pre-Merger Plan. These options have a weighted average exercise price of $0.14 per share, and have expiration dates ranging from February 8, 2022 to June 18, 2022.
2009 Stock Incentive Plan
Effective July 30, 2012, our 2009 Stock Incentive Plan, which we refer to as the 2009 Plan was replaced by the 2012 Plan. The 2009 Plan was intended to secure for us the benefits arising from ownership of our common stock by the employees, officers, directors and consultants of our company. The 2009 Plan was designed to help attract and retain for our company and its affiliates personnel of superior ability for positions of exceptional responsibility, to reward employees, officers, directors and consultants for their services and to motivate such individuals through added incentives to further contribute to the success of our company and its affiliates.
Pursuant to the 2009 Plan, our board of directors (or a committee thereof) had the ability to award grants of incentive or non-qualified options, restricted stock awards, performance shares and other securities as described in greater detail in the 2009 Plan to our employees, officers, directors and consultants. The number of securities issuable pursuant to the 2009 Plan was initially 44,643, provided that the number of shares available for issuance under the 2009 Plan would be increased on the first day of each fiscal year beginning with our 2011 fiscal year, in an amount equal to the greater of (a) 17,857 shares; or (b) three percent (3%) of the number of issued and outstanding shares of our company on the first day of such fiscal year. The 2009 Plan was to expire in April 2019. As of the date of this Annual Report 14,286 options remain outstanding under the 2009 Plan. These options have a weighted average exercise price of $15.89 per share, and have an expiration date ranging from March 14, 2015 to February 2, 2021.
2003 Stock Option Plan
Effective April 1, 2009, our 2003 Stock Option Plan was replaced by the 2009 Plan. The number of securities originally grantable pursuant to the 2003 Stock Option Plan were 71,429. Any options granted pursuant to the 2003 Stock Option Plan remain in effect until they otherwise expire or are terminated according to their terms.
Compensation of Executive Officers
The following table sets forth the compensation for services paid in all capacities for the two fiscal years ended December 31, 2012 and 2011 to (a) Frank C. Ingriselli, who was appointed President and Chief Executive Officer effective July 2012 upon the closing of the Pacific Energy Development merger, and who was serving in these positions at fiscal year end, (b) Roger P. (Pat) Herbert, who was serving as Interim President and Chief Executive Officer until the July 2012 effectiveness of the Pacific Energy Development merger, and (c) Michael L. Peterson and Clark R. Moore, who were the two most highly compensated executive officers at fiscal year end. There were no other executive officers who received compensation in excess of $100,000 in either 2011 or 2012.
Summary Compensation Table
Does not include perquisites and other personal benefits, or property, unless the aggregate amount of such compensation is more than $10,000.
(1)
Amounts in this column represent the aggregate grant date fair value of awards computed in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718. For additional information on the valuation assumptions with respect to the option grants, refer to Note 12 of our financial statements for the year ended December 31, 2011. These amounts do not correspond to the actual value that will be recognized by the named directors from these awards.
(2)
Reflects a bonus of $140,000 post-merger from August, 2012 through December, 2012.
(3)
Reflects a bonus of $110,000 post-merger from August, 2012 through December, 2012.
(4)
Mr. Peterson served as Interim President and Chief Executive Officer of Blast Energy Services from June 2009 to December 2011.
(5)
Consists of non-qualified options granted in February 2011 to purchase 8,929 shares of our common stock at $10.08 per share. The option was immediately vested and will expire ten years from the date of grant.
(6)
Reflects 2011 board fees accrued and unpaid at December 31, 2011 paid in common stock of the Company in 2012.
(7)
Reflects a bonus of $100,000 post-merger from August, 2012 through December, 2012.
(8)
Mr. Herbert was appointed as Interim President and Chief Executive Officer of Blast Energy Services on December 22, 2011 and resigned on July 27, 2012.
(9)
Reflects board fees from January through July pre-merger paid in common stock of the Company in 2012.
(10)
Reflects 2011 board fees accrued and unpaid at December 31, 2011 paid in common stock of the Company in 2012.
Outstanding Equity Awards at Year Ended December 31, 2012
The following table sets forth information as of December 31, 2012 concerning unexercised options, unvested stock and equity incentive plan awards for the executive officers named in the Summary Compensation Table. All outstanding option awards were proportionally adjusted in light of the July 2012 reverse stock split.
_______________________________
(1)
Vesting with respect to 40% of these options on June 18, 2013, 40% on December 18, 2013, and 20% on June 18, 2014, subject to the holder remaining an employee of or consultant to the Company on such vesting date.
Compensation of Directors
Subsequent to the Pacific Energy Development merger, each of our directors has also served as an officer of our company. Only Roger P. Herbert received compensation for his service as a director. The compensation paid to Mr. Herbert for his service as director during the fiscal year ended December 31, 2012 is discussed above under Executive Compensation. We do not anticipate that directors who also serve as our employees will receive any additional compensation for their service as directors. We have reimbursed our directors for travel and lodging expenses in connection with their attendance at board and committee meetings and anticipate continuing that policy.
Our board has adopted a compensation program that, effective for periods after 2012, will provide each of our “independent” directors as defined in NYSE MKT rules or under Rule 10A-3 of the Exchange Act with compensation consisting of (a) a quarterly cash payment of $5,000, and (b) an annual equity award consisting of shares of restricted stock valued at $60,000, vesting on the date that is one year following the date of grant.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The following table sets forth, as of the date of this Annual Report, the number and percentage of outstanding shares of our common stock beneficially owned by: (a) each person who is known by us to be the beneficial owner of more than 5% of our outstanding shares of common stock; (b) each of our directors; (c) the Named Executive Officers; and (d) all current directors and executive officers, as a group. As of March 22, 2013 there were 42,102,852 shares of common stock issued and outstanding.
Beneficial ownership has been determined in accordance with Rule 13d-3 under the Exchange Act. Under this rule, certain shares may be deemed to be beneficially owned by more than one person (if, for example, persons share the power to vote or the power to dispose of the shares). In addition, shares are deemed to be beneficially owned by a person if the person has the right to acquire shares (for example, upon exercise of an option or warrant) within 60 days of the date as of which the information is provided. In computing the percentage ownership of any person, the amount of shares is deemed to include the amount of shares beneficially owned by such person by reason of such acquisition rights. As a result, the percentage of outstanding shares of any person as shown in the following table does not necessarily reflect the person’s actual voting power at any particular date.
To our knowledge, except as indicated in the footnotes to this table and pursuant to applicable community property laws, the persons named in the table have sole voting and investment power with respect to all shares of common stock shown as beneficially owned by them.
* Less than 1%
_____________________________
Unless otherwise stated, the address of each shareholder is c/o PEDEVCO Corp., 4125 Blackhawk Plaza Circle, Suite 201, Danville, CA 94506
(1)
Ownership voting percentages are based on 42,102,852 total shares of common stock which were outstanding as of March 22, 2013, and which reflects the January 27, 2013 automatic 1 for 1 conversion of all the Company’s outstanding Series A preferred stock for common stock. Beneficial ownership is determined in accordance with the rules of the SEC and includes voting and/or investing power with respect to securities. We believe that, except as otherwise noted and subject to applicable community property laws, each person named in the following table has sole investment and voting power with respect to the securities shown as beneficially owned by such person. Additionally, shares of common stock subject to options, warrants or other convertible securities that are currently exercisable or convertible, or exercisable or convertible within 60 days of the applicable date below, are deemed to be outstanding and to be beneficially owned by the person or group holding such options, warrants or other convertible securities for the purpose of computing the percentage ownership of such person or group, but are not treated as outstanding for the purpose of computing the percentage ownership of any other person or group.
(2)
Includes: (a) 403,402 fully-vested shares of common stock held by Mr. Ingriselli; (b) 500,000 shares of common stock held by Mr. Ingriselli which vest with respect to 50% of the shares of August 9, 2012, 20% of the shares on February 9, 2013, 20% of the shares on August 9, 2013, and 10% of the shares on February 9, 2014; (c) 2,385,668 fully-vested shares of common stock held by Global Venture Investments LLC, a limited liability company owned and controlled by Mr. Ingriselli, which we refer to as GVEST; (d) options to purchase 522,400 shares of common stock exercisable by Mr. Ingriselli as of December 18, 2012 at an exercise price of $0.17 per share; and (e) warrants exercisable for 1,000 shares of common stock held by GVEST at $0.75 per share (originally issued as warrants exercisable for 1,000 shares of Series A preferred stock, now exercisable for 1,000 shares of common stock as a result of the January 27, 2013 automatic conversion of the Company’s Series A preferred stock). Mr. Ingriselli has voting control over his unvested shares of common stock.
(3)
Consisting of the following: (a) 80,000 fully-vested shares of common stock held by Mr. Peterson’s minor children; (b) 128,694 fully-vested shares of common stock (including shares held by a family trust which Mr. Peterson is deemed to beneficially own); (c) 350,000 shares of common stock held by Mr. Peterson vesting with respect to 175,000 of the shares on December 1, 2012, and 175,000 of the shares on June 1, 2013; (d) 750,000 shares of common stock held by Mr. Peterson vesting with respect to 50% of the shares on August 9, 2012, 20% of the shares of February 9, 2013, 20% of the shares on August 9, 2013, and 10% of the shares on February 9, 2014; (e) options to purchase 150,000 shares of common stock exercisable by Mr. Peterson as of March 1, 2012 at an exercise price of $0.08 per share; (f) options to purchase 75,000 shares of common stock exercisable by Mr. Peterson as of June 1, 2012 at an exercise price of $0.08 per share; (g) options to purchase 404,300 shares of common stock exercisable by Mr. Peterson as of December 18, 2012 at an exercise price of $0.17 per share; and (h) 10,269 shares of common stock underlying currently exercisable options, of which options to purchase 8,929 shares are exercisable at $10.08 per share and options to purchase 1,340 shares are exercisable at $20.16 per share. Mr. Peterson has voting control over his unvested shares of common stock.
(4)
Includes: (a) 2,000,000 fully-vested shares of common stock held by Mr. Tseng; and (b) options to purchase 50,000 shares of common stock exercisable by Mr. Tseng on August 9, 2012 at an exercise price of $0.10 per share and 20,000 shares of common stock exercisable by Mr. Tseng on February 9, 2012 at an exercise price of $0.10 per share.
(5)
Includes: (a) 1,617,920 fully-vested shares of common stock; (b) 50,000 fully-vested shares of common stock held by each of Mr. Moore’s two minor children, which he is deemed to beneficially own; (c) 250,000 shares of common stock held by Mr. Moore vesting with respect to 50% of the shares on August 9, 2012, 20% of the shares of February 9, 2013, 20% of the shares on August 9, 2013, and 10% of the shares on February 9, 2014; and (d) options to purchase 283,300 shares of common stock exercisable by Mr. Moore as of December 18, 2012 at an exercise price of $0.17 per share. Mr. Moore has voting control over his unvested shares of common stock.
(6)
Address: c/o MIE Holdings Corporation, Suite 1501, Block C, Grand Palace, 5 Huizhong Road, Chaoyong District, Beijing, China 100101. To the best of our knowledge, the beneficial owners of MIE Holdings Corporation are Zhang Ruilin, its Executive Director, Chairman and Chief Executive Officer, and Zhao Jiangwei, its Executive Director, Vice Chairman and Senior Vice President.
(7)
Representing 4,000,000 shares of common stock (issued upon the January 27, 2013 automatic conversion of 4,000,000 shares of Series A preferred stock held by MIE Holdings Corporation), warrants to purchase 500,000 shares of common stock with an exercise price of $1.25 per share, and warrants to purchase 500,000 shares of common stock with an exercise price of $1.50 per share.
(8)
Address: 45 Barry Road, Scarsdale, NY 10583.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
Pacific Energy Development (Prior to Pacific Energy Development merger)
The following transactions were engaged in by Pacific Energy Development and persons that may be deemed “related persons” to Pacific Energy Development pursuant to applicable rules under the Exchange Act, prior to our acquisition of Pacific Energy Development in July 2012.
Transactions with Directors and Officers
From its inception, Frank Ingriselli has been the Chief Executive Officer, President, and a Director of Pacific Energy Development. Starting in September 2011, Mr. Peterson has been the Chief Financial Officer and Executive Vice President of Pacific Energy Development. From its inception, Jamie Tseng has been the Senior Vice President, a Director and Managing Director, of Pacific Energy Development, and its Chief Financial Officer from inception until September 2011. Since its inception, Clark Moore has been the Executive Vice President, General Counsel and Secretary of Pacific Energy Development. Each of the foregoing individuals also was beneficial owner of more than 5% of the shares of common stock of Pacific Energy Development.
Upon our acquisition of Pacific Energy Development, the foregoing individuals became officers and directors of our company, with the same positions set forth above, and in each case became beneficial owners of more than 5% of our shares of common stock. Prior to our acquisition of Pacific Energy Development, Mr. Peterson formerly served as Interim President and Chief Executive Officer (from June 2009 to December 2011) and as director (from May 2008 to December 2011) of Blast, as discussed in greater details above.
Founders
Since the founding of Pacific Energy Development, an aggregate of 14,520,000 fully-vested shares of common stock have been directly and indirectly purchased by various parties as founder’s shares for nominal value as follows: 7,600,000 shares to Frank C. Ingriselli (including the shares issued to GVEST, as described below); 2,000,000 shares to Jamie Tseng; and 1,900,000 shares to Clark R. Moore.
Global Venture Investments LLC, which we refer to as GVEST, an entity wholly owned and controlled by Mr. Ingriselli, and Pacific Energy Development entered into a Subscription Agreement, dated April 30, 2011, pursuant to which GVEST contributed a 6% joint venture interest in Rare Earth Ovonic Metal Hydride JV Co. Ltd. Joint Venture, a Chinese rare earth metal manufacturing and production company, to Pacific Energy Development in exchange for 4,100,000 fully-vested shares of common stock.
Share Grants to Management
The majority of the shares of Pacific Energy Development held by Messrs. Ingriselli, Tseng and Moore were acquired through the direct purchase of such shares from Pacific Energy Development at a price of approximately $0.001 per share, and are fully-vested. A total of 350,000 of the shares of Pacific Energy Development held by Mr. Peterson are subject to forfeiture in the event Mr. Peterson is no longer an employee, officer, director or consultant to Pacific Energy Development, which risk of forfeiture lapses with respect to 50% of the shares on December 1, 2012, and with respect to the remaining 50% of the shares on June 1, 2013. An additional 350,000 of the shares of Pacific Energy Development held by Mr. Peterson were similarly subject to restrictions that lapsed on June 1, 2012. In addition, 750,000, 500,000, and 250,000 of the shares of Pacific Energy Development held by Messrs. Peterson, Ingriselli and Moore, respectively, were acquired through a grant of such shares as restricted stock by Pacific Energy Development, and are or were subject to forfeiture in the event the holder is or was no longer an employee, officer, director or consultant to Pacific Energy Development, which risk of forfeiture lapsed with respect to 50% of the shares on August 9, 2012, and the risk of forfeiture lapses with respect to 20% of the shares on February 9, 2013, 20% of the shares on August 9, 2013, and the balance of 10% of the shares on February 9, 2014.
Loans from Directors and Officers
GVEST loaned Pacific Energy Development $900,000, as evidenced by a secured convertible promissory note, dated July 6, 2011, which we refer to as the GVEST Note. The GVEST Note accrued interest at a rate of 3% per annum, compounded annually. Pursuant to the terms of the GVEST Note, all principal under the GVEST Note was converted into 2,400,000 shares of Pacific Energy Development Series A preferred stock on October 31, 2011, all accrued interest in the amount of $8,655 was paid in cash, and the GVEST Note was cancelled. In addition, upon conversion of the GVEST Note effective October 31, 2011, Pacific Energy Development issued to GVEST a 3-year warrant to purchase an additional 480,000 shares of Pacific Energy Development Series A preferred stock with an exercise price equal to $0.75 per Share. The warrants may be exercised on a cashless basis.
Mr. Frank Ingriselli loaned Pacific Energy Development $200,000 pursuant to a Secured Promissory Note, dated February 14, 2011, which we refer to as the Ingriselli Note. The Ingriselli Note accrued interest at a rate of 3% per annum, compounded annually. All principal and accrued interest under the Ingriselli Note was paid in full on October 31, 2011, and the Ingriselli Note was cancelled. Upon receipt of the repayment of principal under the Ingriselli Note, GVEST purchased 266,667 shares of Pacific Energy Development Series A preferred stock at a purchase price of $0.75 per share pursuant to a subscription agreement entered into with Pacific Energy Development on October 31, 2011.
Agreements with Affiliates
MIE Holdings Corporation, which we refer to as MIE Holdings, an independent upstream onshore oil company operating in China and abroad, may be deemed to be an affiliate of our company due to its beneficial ownership of 4,000,000 shares of our common stock, representing beneficial ownership of greater than 5% of our outstanding common stock. MIE Holdings acquired 4,000,000 shares of preferred stock from Pacific Energy Development and an 80% interest in Condor for $3,000,000 on October 31, 2011; the shares were converted into 4,000,000 shares of our Series A preferred stock in the Pacific Energy Development merger and subsequently converted into 4,000,000 shares of our common stock in January 2013. MIE Holdings continues to hold these shares.
Pacific Energy Development and an affiliate of MIE Holdings collectively own and operate Condor, which holds part of our interests in the Niobrara asset, and White Hawk, which currently holds our interests in the Eagle Ford asset.
On February 14, 2013, the Company, through its wholly-owned Nevada subsidiary, Pacific Energy Development Corp. (“PEDCO”), entered into a Secured Subordinated Promissory Note (the “Note”) with MIE Jurassic Energy Corporation (“MIEJ”), with an effective date of November 1, 2012. Under the Note, PEDCO may draw down multiple advances up to a maximum of $5 million outstanding principal under the Note, with repaid amounts not being permitted to be re-borrowed. Amounts borrowed under the Note may be used by PEDCO to fund fees and expenses allocable to PEDCO with respect to its operations in the Niobrara asset located in Weld and Morgan Counties, Colorado (the “Niobrara Asset”). When drawn, principal borrowed under the Note carries an interest rate of 10.0% per annum. Principal and accrued interest under the Note shall be due and payable within ten (10) business days of the earlier to occur of (i) December 31, 2013 or (ii) the closing of a debt or equity financing transaction with gross proceeds to the Company of at least $10 million. The Note may be prepaid in full by the Company without penalty, and is secured by all of PEDCO’s ownership and working interest in the FFT2H well located in the Niobrara Asset, and all corresponding leasehold rights pooled with respect to such well, and PEDCO’s ownership and working interest in each future well drilled and completed in the Niobrara Asset. The Note documents prior amounts previously advanced by MIEJ to PEDCO in the amount of $2.17 million to fund operations in the Niobrara Asset through November 1, 2012, as well as an additional $2 million loaned by MIEJ to PEDCO under the Note on February 14, 2013, for a total current principal amount outstanding under the Note of $4.17 million.
On November 26, 2012, we entered into an agreement with MIEJ providing for the allocation of 50% of the purchase price, payment of the aggregate $864,866 performance deposit due, ownership interest, development and operational expenses with respect to the Mississippian asset to each of our company and MIEJ, provided that if MIEJ elected to not participate in the acquisition of the Mississippian asset, that we would refund MIEJ’s $432,433 paid as its 50% portion of the performance deposit paid and allow MIEJ to exit the transaction. In February 2013, MIEJ elected not to participate in the Mississippian asset acquisition transaction, the seller and the Company agreed to restructure the Mississippian asset acquisition transaction to provide for the Company to be the sole buyer and apply the performance deposit previously paid toward the purchase price due from the Company in the restructured transaction, and the Company is now obligated to refund to MIEJ the amount of $432,433.
Investor Relations
Pacific Energy Development entered into A Consulting Agreement with Liviakis Financial Communications, Inc., dated December 5, 2011, for certain investor relations services post-merger, pursuant to which Pacific Energy Development issued an aggregate of 696,666 fully-vested shares of Pacific Energy Development Common Stock to Liviakis Financial Communications, Inc., and an employee thereof. John Liviakis, the President and owner of Liviakis Financial Communications, Inc., beneficially owned an aggregate of 1,333,333 fully-vested shares of Pacific Energy Development Common Stock (including shares held by Liviakis Financial Communications, Inc.), representing greater than 5% of the outstanding common stock of Pacific Energy Development at the time.
Blast (Prior to the Acquisition of Pacific Energy Development)
The following transactions were engaged in by our company and persons that may be deemed “related persons” to the pre-merger entity, Blast, pursuant to applicable rules under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), prior to the Pacific Energy Development merger.
Conversion of Deferred Board Fees
In February 2011, as payment of deferred board fees accrued from October 2008, we issued 13,392 shares of common stock to Roger (Pat) Herbert, 8,928 shares of common stock to Michael L. Peterson, and 2,380 shares of common stock to Joseph J. Penbera as payment of deferred board fees accrued from October 2008. Mr. Herbert served as Chairman of our Board from June 2005 to July 2012 and as Interim President and Chief Executive Officer from December 2011 to July 2012. Mr. Peterson formerly served as Interim President and Chief Executive Officer from June 2009 to December 2011 and as director from May 2008 to December 2011. Mr. Penbera formerly served as a Director from April 1999 to October 2009. Fees were converted into shares at $10.08 per share, based on the closing market price of our company’s stock on February 2, 2011.
In August 2012, in connection with the Pacific Energy Development merger and the transactions contemplated by the Debt Conversion Agreement discussed below, Messrs. Herbert, Peterson and Boyd, each converted $85,000, $48,000 and $68,000, respectively, of accrued and unpaid board of directors fees, at a conversion rate of $2.24 per share into 37,947, 21,429, and 30,358 shares of common stock, respectively. In addition, John MacDonald (our company’s Chief Financial Officer at the time), and Andrew Wilson (a non-executive officer of our company at the time) each converted $72,159, and $153,800, respectively, of outstanding accrued pay and vacation at a conversion rate of $2.24 per share into 32,213 and 68,660 shares of common stock of our company, respectively.
Loans from Directors and Officers
Our company was advanced $2,050 from each of Messrs. Herbert, Peterson and Boyd, who were officers and directors at the time, for the purpose of paying our Directors’ and Officers’ insurance premiums in the month of September 2011. These advances were noninterest bearing, unsecured and were due on demand. Each of these loans were converted into 915 shares of common stock of our company at a conversion rate of $2.24 per share in August 2012 in connection with the Pacific Energy Development merger and the transactions contemplated in the Debt Conversion Agreement discussed below.
BMC and Clyde Berg Notes
Each of Berg McAfee Companies, LLC, which we refer to as BMC, and Clyde Berg, an affiliate of BMC, may have been deemed “related persons” under applicable rules of the Exchange Act at the time of the following transactions through their beneficial ownership of greater than 5% of our common stock. After our acquisition of Pacific Energy Development in July 2012, they no longer are deemed related persons under such rules.
On February 27, 2008, in connection with our bankruptcy plan, BMC was issued a promissory note, which we refer to as the BMC Note, for $1.12 million that carried an 8% interest rate and was convertible into common stock at $22.40 per share. The BMC Note had a maturity date of February 27, 2011. On January 5, 2011, our company and BMC amended the 2008 AFJ Note to among other things, extend the maturity date to February 27, 2013; to subordinate the security for such note to our obligations due to and in connection with the drilling and completion of the Guijarral Hills development project; and to provide BMC the right to convert the amount outstanding under the BMC Note into shares of our common stock at a reduced rate of $8.96 per share, rather than $22.40 per share. Our company also agreed to amend the terms of our then outstanding Series A preferred stock to provide for a reduction in the conversion price of such preferred stock from $56.00 per share to $22.40 per share.
On May 19, 2011, we entered into a $100,000 promissory note with Mr. Berg, which we refer to as the Berg Note. The Berg Note carried a 25% interest rate, had a one-year term and was guaranteed by Eric McAfee, another affiliate of BMC. The proceeds from this note were used to partially pay the cost of testing operations on the Solimar Energy 76-33 well located in our Guijarral Hills development project.
On January 13, 2012, we entered into a Debt Conversion Agreement, which we refer to as the BMC Debt Conversion Agreement, with BMC and Mr. Berg. The BMC Debt Conversion Agreement modified the BMC and the Berg Note to provide that all principal and accrued interest under such note could be converted into shares of our common stock at a conversion price of $2.24 per share at our option in connection with its shareholder meeting with respect to the Pacific Energy Development merger. Pursuant to the BMC Debt Conversion Agreement, on June 26, 2012, the BMC Note and accrued interest thereon was converted into 673,461 shares of common stock and the Berg Note and accrued interest thereon was converted into 57,009 shares of common stock. In conjunction with the conversion, a previous revenue sharing agreement with BMC with respect to the Guijarral Hills development project was eliminated.
In January 2012, BMC and Mr. Berg also entered into a Voting Agreement with us and agreed to vote our company capital stock held by them in favor of the transactions contemplated by the Agreement and Plan of Reorganization, dated January 13, 2012.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.
The following table presents fees for professional audit services performed by GBH CPAs, PC for the audit of our annual financial statements for the fiscal year ended December 31, 2012 and professional audit services performed by Singer Lewak, LLP for the audit of our annual financial statements for the fiscal year ended December 31, 2011.
(1)
Audit fees include professional services rendered for (1) the audit of our annual financial statements for the fiscal years ended December 31, 2012 and 2011 and (ii) the reviews of the financial statements included in our quarterly reports on Form 10-Q for such years.
(2)
Audit-related fees consist of fees billed for professional services that are reasonably related to the performance of the audit or review of our consolidated financial statements, but are not reported under “Audit fees.”
(3)
Tax fees include professional services relating to preparation of the annual tax return.
(4)
Other fees include professional services for review of various filings and issuance of consents.
Pre-Approval Policies
It is the policy of our Board of Directors that all services to be provided by our independent registered public accounting firm, including audit services and permitted audit-related and non-audit services, must be pre-approved by our Board of Directors. Our Board of Directors pre-approved all services, audit and non-audit, provided to us by GBH CPAs, PC for 2012 and provided to us by Singer Lewak, LLP for 2011.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) Financial Statements
3.
List of Exhibits
_________________
*
Filed with this Annual Report on Form 10-K.
**
XBRL (Extensible Business Reporting Language) information is furnished and not filed or a part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.
Each document listed in this Exhibit Index that has been previously filed with the SEC is incorporated by reference into this Annual Report on Form 10-K.
(1)
Previously filed on May 31, 2012 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(2)
Previously filed on August 2, 2012 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(3)
Previously filed on March 6, 2008 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(4)
Previously filed on November 20, 2003 as an exhibit to the Registrant’s Report on Form 10-QSB incorporated herein by reference.
(5)
Previously filed on August 14, 2009 as an exhibit to the Registrant’s Report on Form 10-Q incorporated herein by reference.
(6)
Previously filed on August 2, 2012 as an exhibit to the Registrant’s Report on Form 8-K.
(7)
Previously filed on February 9, 2010 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(8)
Previously filed on September 23, 2010 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(9)
Previously filed on November 2, 2010 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(10)
Previously filed on January 5, 2011 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(11)
Previously filed on January 13, 2011 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(12)
Previously filed on March 2, 2011 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(13)
Previously filed on April 12, 2011 as an exhibit to the Registrant’s Report on Form 10-K incorporated herein by reference.
(14)
Previously filed on August 22, 2011 as an exhibit to the Registrant’s Report on Form 10-Q incorporated herein by reference.
(15)
Previously filed on November 14, 2011 as an exhibit to the Registrant’s Report on Form 10-Q incorporated herein by reference.
(16)
Previously filed on December 27, 2011 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(17)
Previously filed on January 20, 2012 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(18)
Previously filed on May 18, 2012 as an exhibit to the Registrant’s Report on Form 10-Q incorporated herein by reference.
(19)
Previously filed on April 16, 2012 as an exhibit to the Registrant’s Report on Form 10-K incorporated herein by reference.
(20)
Previously filed on May 31, 2012 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(21)
Previously filed on September 6, 2012 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(22)
Previously filed on October 1, 2012 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(23)
Previously filed on October 10, 2012 as an exhibit to the Registrants Registration Statement on Form S-1.
(24)
Previously filed on November 27, 2012 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(25)
Previously filed on December 6, 2012 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(26)
Previously filed on December 13, 2012 as an exhibit to the Registrant’s Amendment No. 1 to Registration Statement on Form S-1 incorporated herein by reference.
(27)
Previously filed on January 16, 2013 as an exhibit to the Registrant’s Amendment No. 2 to Registration Statement on Form S-1 incorporated herein by reference.
(28)
Previously filed on February 5, 2013 as an exhibit to the Registrant’s Amendment No. 3 to Registration Statement on Form S-1 incorporated herein by reference.
(29)
Previously filed on February 12, 2013 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(30)
Previously filed on February 19, 2013 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
(31)
Previously filed on August 8, 2012 as an exhibit to the Registrant’s Report on Form 8-K incorporated herein by reference.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PEDEVCO Corp.
Date: March 22, 2013
By:
/s/ Frank C. Ingriselli
Frank C. Ingriselli
President and Chief Executive Officer
(Principal Executive Officer)
Date: March 22, 2013
By:
/s/ Michael L. Peterson
Michael L. Peterson
Executive Vice President and Chief Financial Officer (Principal Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
Title
Date
/s/ Frank C. Ingriselli
President, Chief Executive Officer and Chairman of the Board of Directors
March 22, 2013
Frank C. Ingriselli
(Principal Executive Officer)
/s/ Michael L. Peterson
Chief Financial Officer, Executive Vice President and Director
March 22, 2013
Michael L. Peterson
(Principal Financial and Accounting Officer)
/s/ Jamie Tseng
Senior Vice President and Director
March 22, 2013
Jamie Tseng
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors
PEDEVCO Corp. (formerly Bast Energy Services, Inc.)
Danville, California
We have audited the accompanying consolidated balance sheet of PEDEVCO Corp. (formerly Bast Energy Services, Inc.) as of December 31, 2012 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for the year ended December 31, 2012. These consolidated financial statements are the responsibility of PEDEVCO Corp.’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of PEDEVCO Corp. as of December 31, 2012 and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America.
We have also audited the calculation of net loss per common share-basic and diluted for the period from February 9, 2011 (Inception) through December 31, 2011. In our opinion, the calculation of net loss per common share-basic and diluted is presented fairly in all material respects and in conformity with accounting principles generally accepted in the United State of America.
The accompanying consolidated financial statements have been prepared assuming that PEDEVCO Corp. will continue as a going concern. As discussed in Note 3 to the financial statements, the Company incurred a loss from continuing operations for the year ended December 31, 2012 and has an accumulated deficit at December 31, 2012 which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters also are described in Note 3. These consolidated financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classification of liabilities that may result from the outcome of this uncertainty.
/s/ GBH CPAs, PC
GBH CPAs, PC
www.gbhcpas.com
Houston, Texas
March 22, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To Board of Directors
Pacific Energy Development Corporation
4125 Blackhawk Plaza Circle, Suite 201A
Danville, CA 94506
We have audited the accompanying consolidated balance sheet of Pacific Energy Development Corporation and its subsidiary (the “Company”) as of December 31, 2011, and the related consolidated statements of operations, stockholders’ equity and cash flows for the period from February 9, 2011 (Inception) to December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above, before the addition of loss per share, present fairly, in all material respects, the financial position of the Company as of December 31, 2011, and the results of its operations and its cash flows for the period from February 9, 2011 (Inception) through December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.
We were not engaged to audit, review, or apply any procedures to the loss per share calculation for the period from February 9, 2011 (Inception) through December 31, 2011 and, accordingly, we do not express an opinion or any other form of assurance in regards to the loss per share calculation. This amount was audited by other auditors.
The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the financial statements, the Company has incurred net losses from operations and has no revenue producing activities at December 31, 2011. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 3. The financial statements do not include any adjustments that may result from the outcome of this uncertainty.
As discussed in Note 5 under the caption “Initial Restatement”, these financial statements have been restated to correct for certain errors related to the Company’s accounting for its deferred costs and equity method investment.
As discussed in Note 5 under the caption “Second Restatement”, these financial statements have been restated to adjust the Company's accounting related to the issuance of a fully-vested non-forfeitable stock award. We were engaged to audit the restatement adjustments in accordance with the standards of the Public Company Accounting Oversight Board. We audited the adjustments necessary to restate these financial statements. In our opinion, such adjustments are appropriate and have been properly applied.
SingerLewak, LLP
San Francisco, California
March 27, 2012, except for Note 5 under the caption “Initial Restatement” as to which the date is May 23, 2012 and except for Note 5 under the caption “Second Restatement” as to which the date is December 12, 2012
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PEDEVCO CORP.
(FORMERLY BLAST ENERGY SERVICES, INC.)
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
PEDEVCO CORP.
(FORMERLY BLAST ENERGY SERVICES, INC.)
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2012 and for the
Period from February 9, 2011 (Inception) through December 31, 2011
See accompanying notes to consolidated financial statements.
PEDEVCO CORP.
(FORMERLY BLAST ENERGY SERVICES, INC.)
CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY
For the Period from February 9, 2011 (Inception) through December 31, 2012
See accompanying notes to consolidated financial statements.
PEDEVCO CORP.
(FORMERLY BLAST ENERGY SERVICES, INC.)
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2012 and the
Period from February 9, 2011 (Inception) through December 31, 2011
See accompanying notes to consolidated financial statements.
PEDEVCO CORP.
(FORMERLY BLAST ENERGY SERVICES, INC.)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - BASIS OF PRESENTATION
The accompanying consolidated financial statements of PEDEVCO CORP., formerly Blast Energy Services, Inc. (“PEDEVCO” or the “Company”), have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the Securities and Exchange Commission (“SEC”).
NOTE 2 - DESCRIPTION OF BUSINESS
PEDEVCO’s primary business plan is: (i) engaging in oil and gas exploration, development and production of primarily shale oil and gas and secondarily conventional oil and gas opportunities in the United States (U.S.), and (ii) subsequently utilizing the Company’s strategic relationships for exploration, development and production in Pacific Rim countries, with a particular focus in China.
The Company owns a 20% interest in Condor Energy Technology, LLC (“Condor”), as well as a 50% interest in White Hawk Petroleum, LLC (“White Hawk”). Condor’s operations consist primarily of working interests in oil and gas leases in the Niobrara shale formation located in the Denver-Julesberg Basin in Morgan and Weld Counties, Colorado. The remaining interest in Condor is owned by an affiliate of MIE Holdings Corporation (Hong Kong Stock Exchange code: 1555.HK), one of the largest independent upstream onshore oil companies in China (“MIE Holdings”). White Hawk’s operations consist primarily of working interests in oil and gas leases in the Eagle Ford shale formation in McMullen County, Texas. The remaining interest in White Hawk is also owned by an affiliate of MIE Holdings.
The Company plans to focus initially on developing shale oil and gas assets held by the Company in the U.S., including its first oil and gas working interest known as “the Niobrara Asset” and its second oil and gas working interest known as the “the Eagle Ford Asset”. Subsequently, the Company plans to seek additional shale oil and gas and conventional oil and gas asset acquisition opportunities in the U.S. and Pacific Rim countries utilizing its strategic relationships and technologies that may provide the Company a competitive advantage in accessing and exploring such assets. Some or all of these assets may be acquired by subsidiaries, including Condor, or others that may be formed at a future date.
NOTE 3 - GOING CONCERN
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 and has negative working capital and/or accumulated deficit at December 31, 202. 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.
NOTE 4 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation and Principles of Consolidation. The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) and include the accounts of the Company and those of its wholly owned subsidiaries as follows: (i) Eagle Domestic Drilling Operations LLC, a Texas limited liability company; (ii) Blast AFJ, Inc., a Delaware corporation; (iii) Pacific Energy Development Corp., a Nevada corporation; (iv) Pacific Energy Technology Services, LLC, a Nevada limited liability company; (v) Pacific Energy & Rare Earth Limited, a Hong Kong company; and (vi) Blackhawk Energy Limited, a British Virgin Islands company. All significant intercompany accounts and transactions have been eliminated.
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 VIE’s, but since the Company is not the primary beneficiary of either Condor or White Hawk, the Company concluded that consolidation was not required for either entity.
Use of Estimates in Financial Statement Preparation. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates generally include those with respect to the amount of recoverable oil and gas reserves, the fair value of financial instruments, oil and gas depletion, asset retirement obligations, and stock-based compensation.
The Company's most significant estimates relate to the valuation of its investment in the Rare Earth JV and its valuation of its common stock, options and warrants. With respect to the Rare Earth JV, given that there is no established market for this interest combined with the highly speculative nature of this investment, management used their best good faith judgment and estimated a nominal value of $4,100 for this asset at the time of its exchange for shares of the Company's common stock. Management considered the following in arriving at their judgment of value: the joint venture's historical operating results, the lack of marketability, restrictions on transfer, and its minority interest position. If the Company sells the asset, the actual results of any sale could be materially different from management's estimated value.
Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. As of December 31, 2012 and December 31, 2011, cash equivalents consisted of money market funds and cash on deposit.
Concentrations of Credit Risk. Financial instruments which potentially subject the Company to concentrations of credit risk include cash deposits placed with financial institutions. The Company maintains its cash in bank accounts which, at times, may exceed federally insured limits as guaranteed by the Federal Deposit Insurance Corporation (FDIC). At December 31, 2012, approximately $2,215,587 of the Company’s cash balances were uninsured. The Company has not experienced any losses in such accounts. Sales to two customers comprised 68% and 32% of the Company’s total oil and gas revenues for the year ended December 31, 2012. The Company had no revenue for the year ended December 31, 2011. The Company believes that, in the event that its primary customer was unable or unwilling to continue to purchase the Company’s production, there are a substantial number of alternative buyers for its production at comparable prices.
Accounts Receivable. Accounts receivable typically consist of oil and gas receivables. The Company has classified these as short-term assets in the balance sheet because the Company expects repayment or recovery within the next 12 months. The Company evaluates these accounts receivable for collectability considering the results of operations of these related entities and when necessary records allowances for expected unrecoverable amounts. To date, no allowances have been recorded.
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 and natural gas. Revenue from crude oil and natural gas sales is recognized when the product is delivered to the purchaser and collectability is reasonably assured. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves. If collection is uncertain, revenue is recognized when cash is collected.
Equipment. Equipment is stated at cost less accumulated depreciation and amortization. Maintenance and repairs are charged to expense as incurred. Renewals and betterments which extend the life or improve existing equipment are capitalized. Upon disposition or retirement of equipment, the cost and related accumulated depreciation are removed and any resulting gain or loss is reflected in operations. Depreciation is provided using the straight-line method over the estimated useful lives of the assets, which are 3 to 10 years.
Deferred Property Acquisition Costs. The Company defers the costs, such as title and legal fees, related to oil and gas property acquisitions. At the time the acquisition is completed, these costs are reclassified and included as part of the purchase price of the property acquired. To the extent a property acquisition is not consummated these costs are expensed.
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.
Impairment of Long-Lived Assets. The Company reviews the carrying value of its long-lived assets annually or whenever events or changes in circumstances indicate that the historical cost-carrying value of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the future net undiscounted cash flows expected to result from the asset, including eventual disposition. If the future net undiscounted cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and estimated fair value.
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, the Company will record a liability (an asset retirement obligation or “ARO”) on its consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and 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 the 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 statements of operations.
Income Taxes. The Company utilizes the asset and liability method in accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for operating loss and tax credit carry-forwards and for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in the results of operations in the period that includes the enactment date. A valuation allowance is recorded to reduce the carrying amounts of deferred tax assets unless it is more likely than not that the value of such assets will be realized.
Stock-Based Compensation. 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.
The Company estimates volatility by considering the historical stock volatility. The Company has opted to use the simplified method for estimating expected term, which is generally equal to the midpoint between the vesting period and the contractual term.
Earnings or Loss per Common Share. Basic earnings per common share equal net earnings or loss divided by weighted average common shares outstanding during the period. Diluted earnings per share include the impact on dilution from all contingently issuable shares, including options, warrants and convertible securities. The common stock equivalents from contingent shares are determined by the treasury stock method. The Company incurred net losses for the years ended December 31, 2012 and 2011, and therefore, basic and diluted earnings per share for those periods are the same as all potential common equivalent shares would be anti-dilutive. The Company excluded 3,754,615 potentially issuable shares of common stock related to options and 1,800,893 potentially issuable shares of common stock related to warrants due to their anti-dilutive effect.
Fair Value of Financial Instruments. The Company follows Financial Accounting Standards Board (“FASB”) ASC 820, Fair Value Measurement (“ASC 820”), which clarifies fair value as an exit price, establishes a hierarchal disclosure framework for measuring fair value, and requires extended disclosures about fair value measurements. The provisions of ASC 820 apply to all financial assets and liabilities measured at fair value.
As defined in ASC 820, fair value, clarified as an exit price, represents the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As a result, fair value is a market-based approach that should be determined based on assumptions that market participants would use in pricing an asset or a liability.
As a basis for considering these assumptions, ASC 820 defines a three-tier value hierarchy that prioritizes the inputs used in the valuation methodologies in measuring fair value.
Level 1 - Quoted prices in active markets for identical assets or liabilities.
Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
Reclassifications. Certain amounts in the consolidated financial statements of the prior year have been reclassified to conform to the current presentation for comparative purposes.
Recently Issued Accounting Pronouncements. There were various accounting standards and interpretations issued during 2012 and 2011, none of which are expected to have a material impact on the Company’s financial position, operations or cash flows.
In July 2012 the FASB issued ASU 2012-02 Testing Indefinite-Lived Intangible Assets for Impairment, which amends Topic 350 and gives companies the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with Topic 350-30. This ASU shall be applied prospectively for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012 and early adoption is permitted. Implementation of the ASU is not expected to have a significant impact on the Company’s consolidated financial statements.
Subsequent Events. The Company has evaluated all transactions through the date the consolidated financial statements were issued for subsequent event disclosure consideration.
NOTE 5 - PRIOR YEAR RESTATEMENTS
Initial Restatement
On May 23, 2012, the financial statements for the period from February 9, 2011 (inception) through December 31, 2011 have been restated as a result of two errors discovered subsequent to their original issuance. These errors are as follows:
● $87,668 of improperly deferred costs associated with the Eagle Ford Asset acquisition (as described in Note 8).
● $19,200 of improper intercompany profit eliminations related to intercompany transactions between Condor and the Company.
The impact on the previously reported balance sheet as of December 31, 2011 is as follows:
The impact on the previously reported loss from operations and net loss for the period from February 9, 2011 (Inception) through December 31, 2011 is as follows:
Second Restatement
On December 12, 2012, the financial statements, for the period from February 9, 2011 (inception) through December 31, 2011, subsequent to the initial restatement discussed above have been restated again to adjust the Company’s accounting for the fully vested non-forfeitable stock award issued to investor relations consultants as disclosed in Note 14. The Company originally recorded the $69,667 value of the award as a stock subscription receivable in the balance sheet as performance was not required until the Company had completed a reverse merger transaction, at which time the 18 month service period would commence. Because the award is fully vested and non-forfeitable and the Company has no ability to compel specific performance, the Company reconsidered its accounting for this transaction and concluded that the appropriate treatment should have been to expense the value of the award in full. These financial statements are being restated to reflect this change.
The impact on the previously reported balance sheet (after adjustment for the initial restatement discussed above) as of December 31, 2011 is as follows:
The impact on the previously reported loss from operations and net loss for the period from February 9, 2011 (Inception) through December 31, 2011 (after adjustment for the initial restatement discussed above) is as follows:
NOTE 6 - MERGER AGREEMENT - PACIFIC ENERGY DEVELOPMENT CORP.
On July 27, 2012, the Company completed the transactions contemplated by the January 13, 2012, Agreement and Plan of Reorganization (as amended, the “Merger Agreement”), by and between the Company, Blast Acquisition Corp., a wholly-owned Nevada subsidiary of the Company (“MergerCo”), and Pacific Energy Development Corp., a privately-held Nevada corporation (“PEDCO” or “Pacific Energy Development Corp.”).
Pursuant to the Merger Agreement on July 27, 2012, MergerCo was merged with and into PEDCO, with PEDCO continuing as the surviving entity and becoming a wholly-owned subsidiary of the Company, in a transaction structured to qualify as a tax-free reorganization (the “Merger”). In connection with the Merger, the Company issued former security holders of PEDCO 17,917,261 shares of common stock, 19,716,676 shares of new Series A Preferred Stock, warrants to purchase an aggregate of 1,120,000 shares of our common stock, warrants to purchase 692,584 shares of our new Series A Preferred Stock, and options to purchase 4,235,000 shares of the Company’s common stock.
Additionally, immediately prior to the Merger becoming effective, the shareholders of the Company approved an Amended and Restated Certificate of Formation and an Amended and Restated Series A Convertible Preferred Stock Designation which upon effectiveness: (i) converted all 6,000,000 outstanding shares of the Company’s Series A Convertible Preferred Stock and the single outstanding share of Series B Preferred Stock into 6,000,001 shares of common stock of the Company on a one to one basis, and immediately thereafter, (ii) effected a one for one hundred and twelve (1:112) reverse stock split rounding up for all fractional shares of the Company’s then outstanding common stock, resulting in the conversion of approximately 159,238,556 shares of common stock into 1,422,873 shares of common stock (the “Reverse Split” and the “Amended and Restated Certificate of Formation”). All share and per share amounts in the consolidated financial statements and footnotes have been retroactively restated for the impact of the reverse split.
Furthermore, in connection with the Reverse Split and the Amended and Restated Certificate of Formation, the Company changed its name to “PEDEVCO Corp.”, and amended its Certificate of Formation, to effect various changes to its Certificate of Formation, including, but not limited to increasing the Company’s authorized capitalization to 300,000,000 shares of capital stock post-Reverse Split, which includes 200,000,000 shares of common stock, $0.001 par value per share (“Common Stock”); and 100,000,000 authorized shares of Preferred Stock, including 25,000,000 authorized shares of Series A Convertible Preferred Stock, $0.001 par value per share ("New Series A Preferred Stock"), which shares were designated in connection with approval of and filing of the Amended and Restated Certificate of Designations of the Company’s Series A Convertible Preferred Stock, which amended and replaced the prior designation of the Company’s Series A Convertible Preferred Stock (which shares were automatically converted into shares of common stock pursuant to the Amended and Restated Certificate of Formation).
The acquisition was accounted for as a “reverse acquisition,” and Pacific Energy Development Corp. was deemed to be the accounting acquirer in the acquisition. The Company’s assets and liabilities are recorded at their fair value. Pacific Energy Development Corp.'s assets and liabilities are carried forward at their historical costs. The financial statements of Pacific Energy Development Corp. are presented as the continuing accounting entity since it is the acquirer for the purpose of applying purchase accounting. The equity section of the balance sheet and earnings per share of Pacific Energy Development Corp. are retroactively restated to reflect the effect of the exchange ratio established in the Merger Agreement. Goodwill is recorded for the excess of fair value of consideration transferred and fair value of net assets. As a result of the issuance of the shares of common stock pursuant to the Merger Agreement, a change in control of the Company occurred.
The purchase price on the date of acquisition was:
Management evaluated the amount of goodwill associated with the transaction 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.
Centurion Debt Modifications
In connection with the anticipated Merger, on January 13, 2012, Blast entered into an amendment to note purchase agreement (the “Note Purchase Amendment”), with Centurion Credit Funding LLC (“Centurion”), a secured creditor of Blast, and on May 29, 2012, Blast entered into the Second Amendment to First Tranche Promissory Note and the Second Amendment to the Second Tranche Promissory Note (collectively, the “Second Amendments to the Promissory Notes”) with Centurion. The Note Purchase Amendment and the Second Amendments to the Promissory Notes amended the Note Purchase Agreement, dated February 24, 2011 (the “Note Purchase Agreement”), entered into with Centurion primarily in order (i) to grant consent to the Merger, (ii) to waive, solely with respect to the Company post-Merger, certain loan covenants and restrictions as they relate to the assets of PEDCO and the operations of the Company post-Merger, (iii) to waive Centurion’s right of first refusal to provide additional funding to Blast, and (iv) to provide for the conversion of up to 50% of the loan amounts outstanding to Centurion in the original principal amount of $2,522,111, of which approximately $1,306,078 was owed as of the date of the parties’ entry into the Note Purchase Amendment, into shares of the Company’s common stock at $0.75 per share at the option of Centurion at any time after June 9, 2012, provided that the Company in its 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 the Company’s then outstanding shares of common stock, subject to Centurion’s right to increase such limit to up to 9.99% of the Company’s outstanding shares with 61 days prior written notice to the Company.
The Promissory Notes issued in connection with the Note Purchase Amendment were amended to provide an extension of the maturity date of such Promissory Notes, which were due February 2, 2012 under the terms of the original notes, to the earlier of (i) thirty (30) days after the termination of the Merger Agreement, if the Merger Agreement s terminated before June 1, 2012, (ii) August 1, 2012, or (iii) the date all obligations and indebtedness under such Promissory Notes are accelerated in accordance with the terms and conditions of such Promissory Notes. Furthermore, commencing February 2, 2012, the interest amount on the Promissory Notes was increased from 10% to 18% per annum, and the new interest rate included both the principal amount and the Exit Fee payable described below. Lastly, the Exit Fee, which is 12% of the repayment amount, was increased by an aggregate of $15,000 for the Promissory Notes and was expensed by Blast at the date of modification.
On August 30, 2012, following the Merger, the Company entered into the Third Amendment to Senior Secured Promissory Notes (First and Second Tranche) with Centurion (the “Third Amendment to the Promissory Notes”), which amended certain provisions of the Senior Secured Promissory Note (First Tranche) and Senior Secured Promissory Note (Second Tranche), each originally dated February 24, 2011 and amended on January 13, 2012 and May 29, 2012 (together, as amended, the “Promissory Notes”). The Promissory Notes were amended to provide an extension of the maturity date which were due as of August 1, 2012, to the earlier of (i) November 30, 2012, or (ii) the date all obligations and indebtedness under such Promissory Notes are accelerated in accordance with the terms and conditions of such Promissory Notes. The Company further agreed to deposit an additional $700,000 as a “repayment deposit” into the Company’s bank account that is subject to a deposit account control agreement (the “DACA”) between the Company and Centurion in order to provide additional security to Centurion with the DACA being revised to provide that Centurion may not have access to such funds until the maturity date of such Promissory Notes, unless a default or event of default has occurred. Additionally, the Third Amendment to the Promissory Notes removed the prior prohibition which limited Centurion to converting the Promissory Notes only once every thirty days.
The Company applied ASC 470-50-40/55 “Debtor’s Accounting for a Modification or Exchange of Debt Instrument” and concluded that the Note Purchase Amendment dated January 13, 2012 constituted a debt extinguishment rather than a debt modification because a significant conversion feature was added to the terms of the note. The conversion feature was contingent on the completion of the Merger. As such, the Company’s Merger with Blast, triggered the contingent conversion feature. As a result, the Company recorded a loss on debt extinguishment of $159,913 during the year ended December 31, 2012, as summarized below.
In connection with the Note Purchase Amendment, the convertible debenture was also analyzed for a beneficial conversion feature after the debt modification at which time it was concluded that a beneficial conversion feature existed. Accordingly, a debt discount was recorded at the date of the modification. See detail summary below for carrying value of debt on the date of the merger.
On August 31, 2012, Centurion converted $101,250 of principal and accrued interest, into 135,000 shares of the Company’s common stock. In October 2012, Centurion converted $536,250 of principal into 715,000 shares of the Company’s common stock. In November 2012, Centurion converted $392,045 of principal into 522,727 shares of the Company’s common stock. Centurion forgave the principal and interest balance of $169,181 and the balance owed Centurion at December 31, 2012 was paid in full. See detail summary below of loan activity and balance as of December 31, 2012.
The Company recorded a gain on debt extinguishment which was netted against loss resulted in a net hgain of $9,268.
Prior to the Merger, as additional security for the repayment of the First Note and Second Note, and pursuant to a Stock Purchase Agreement, the Company sold Centurion one (1) share of its newly designated Series B Preferred Stock, in consideration for $100, which entitled Centurion to consent to and approve the Company’s or any of its subsidiaries’ entry into any bankruptcy proceeding, consent to the appointment of a receiver, liquidator or trustee or the assignment by the Company or any of its subsidiaries for the benefit of any creditors. The Company assigned no value to this Series B Preferred Share. The one share of the Company’s Series B Preferred Stock was converted on a one-for-one basis into one (1) share of the Company’s pre-Reverse Split common stock in connection with the Merger.
Other Debt Conversions
In connection with the Merger, the Company approved the conversion of certain other outstanding debt obligations of the Company at $2.24 per share. At the time of the Mergers these debt obligations included: $335,500 of accrued compensation due to the members of Board of Directors, $6,150 of short term loans from members of the Board of Directors, $225,958 of accrued salaries and vacation pay owed to the Company’s employees for a total amount of $567,608. These amounts were converted at $2.24 per share under debt conversion agreements (“Debt Conversion Agreements”) into approximately 253,396 shares of the Company’s common stock in August and September 2012. Additionally, in May 2012, pursuant to a settlement agreed upon among the Company, Trident Partners Ltd. (“Trident”), and certain principals for Trident, the placement fee owed by the Company to Trident was reduced from $119,990 to $47,960 and Trident agreed to convert the remaining amount due at $2.24 per share into approximately 21,411 shares of the Company’s common stock upon completion of the Merger.
NOTE 7 - OIL AND GAS PROPERTIES
The following tables summarize the Company’s oil and gas activities by classification for the year ended December 31, 2012 and the period from February 9, 2011 (Inception) through December 31, 2011:
Niobrara Asset
The Company acquired oil and gas interests in Colorado in a geologic formation known as the Niobrara formation (“the Niobrara Asset”) on October 31, 2011 for a total cost of $4,914,624. The Company assigned 62.50% ($3,071,640) of the value of the Niobrara interest acquired to Condor, of which the Company owns 20%. The following table details the purchase price components:
(1)
The Company agreed to issue 1,333,334 shares of Series A Preferred Stock on November 13, 2012, subject to a guaranteed minimum value of $1 million of the preferred stock. At November 13, 2012, the Sellers had the option to elect to receive the fixed number of 1,333,334 shares or $1 million in cash, due and payable within five days of their written election to receive cash in lieu of the shares. The agreement does not provide the Sellers the option for a variable number of shares based on the per share value. The obligation of $1 million was recorded in accrued expenses on the date of the transaction. The Company received elections from the Sellers requesting payment of the obligation in cash due on or about November 20, 2012. On November 26, 2012, the Agreement was amended to provide for the payment of $100,000 to the Sellers, and 133,334 shares of the preferred stock valued at $100,000 to extend the $1 million payment to the Sellers until February 18, 2013. The fair value of $280,001 of the 133,334 preferred shares issued and the $100,000 payment were recorded as interest expense in 2012. The Company subsequently paid the $1 million on February 18, 2013.
(2)
The Company agreed to provide the Sellers a carried interest for $699,372 of their share of future drilling costs and was recorded as a liability on the date of the transaction, of which $279,748 was paid in the three months ending June 30, 2012 and the remaining $419,624 was satisfied in the three months ending September 30, 2012 through the issuance on September 24, 2012 of 279,749 shares of the Company’s Series A Preferred Stock with a fair value of $559,498. The Company recorded a loss on settlement of payables of $139,874.
(3)
The Company issued 285,595 shares of common stock in connection with the acquisition at a grant date fair value of $28,560 to a related party due diligence provider, South Texas Reservoir Alliance, LLC (“STXRA”).
(4)
The Company issued 230,000 shares of Series A Preferred Stock in February 2012 at a grant date fair value of $0.75 per share, or $172,500, to STXRA in exchange for the portion of working interests earned for worked performed in the transaction.
One of the sellers, Esenjay Oil & Gas, Ltd. ("Esenjay"), retains an overriding royalty interest in the production from the leases assigned equal to the amount, if positive, by which twenty percent (20%) of production exceeds the aggregate of all landowner royalties, overriding royalties and other burdens measured or payable out of the production that cover or affect the subject leases.
The depletion recorded for production on proved properties for the year ended December 31, 2012 amounted to $90,414. The Company recorded impairment of leases for the year ended December 31, 2012 of $180,262 for lease acreage that expired during the year due to non-renewals or non-utilization of leases.
During the year ended December 31, 2012, the Company began drilling operations on its FFT2H, Logan 2H and Waves 1H wells. The Company completed the FFT2H well in July 2012 and incurred $1,143,100 in drilling and completion costs. As of December 31, 2012, the Company has incurred $246,365 and $263,382 in drilling costs related to the Logan 2H and Waves 1H wells, respectively, which were completed subsequent to December 31, 2012. As a result of this drilling the Company reclassified $697,016 of the carrying value of the properties from unproved to proved property.
Eagle Ford Asset
On March 29, 2012, the Company acquired Excellong E&P-2, Inc., a Texas corporation for a total purchase price of $3.75 million. Excellong E&P-2’s sole asset was an approximately 8% working interest in certain oil and gas leases covering approximately 1,650 net acres in the Leighton Field located in McMullen County, Texas, which is currently producing oil and natural gas from the Eagle Ford shale formation. This area is currently producing oil and natural gas from three wells, but the remainder of the acreage is under development. The Company transferred these assets to White Hawk. See Note 8.
Guijarral Hills Exploitation Project
In October 2010, Blast entered into Farmout Agreement with Solimar Energy LLC (“Solimar”), to participate in an exploration project in the Guijarral Hills Field located in the San Joaquin basin of central California. In 2011, an initial exploratory well (the “Solimar Well”) was drilled on the project, but the zones tested did not result in an oil-producing well. On August 6, 2012, Solimar notified its desire to assign the Solimar Well to Vintage Production California LLC (“Vintage”), the lessor of the well in return for payment of the salvage value of the equipment in the Solimar Well. The Company elected to give up its right to take over the well and all related plugging and abandonment obligations, and agreed to assign its interest in the well to Vintage. As of August 10, 2012, Solimar had offered the well assignment to Vintage but Vintage had not yet responded as to its intentions whether to accept it or not. The Guijarral Hills Field lease expired pursuant to its own terms on September 30, 2012. In connection with the allocation of the purchase price in the Merger, no value was attributed to the Guijarral Project.
NOTE 8 - BUSINESS ACQUISITION AND DISPOSAL
On March 29, 2012, the Company acquired Excellong E&P-2, Inc., a Texas corporation for a total purchase price of $3.75 million. Excellong E&P-2’s sole asset was an approximately 8% working interest in certain oil and gas leases covering approximately 1,650 net acres in the Leighton Field located in McMullen County, Texas, which is currently producing oil and natural gas from the Eagle Ford shale formation (the “Eagle Ford Asset”). The purchase was accounted for as a business combination; however, the Company acquired no other assets or liabilities other than the working interests and tangible equipment associated with producing wells.
This area is currently producing oil and natural gas from three wells, with the remainder of the acreage is under development. The purchase price terms were:
(1)
Payable in 60 days following the closing. The amount was paid in May 2012 by an affiliate of MIE Holdings as consideration for the White Hawk sale described below.
(2)
The Company issued 1,666,667 shares of Series A Preferred Stock at a grant date fair value of $1,250,000. In accordance with the purchase agreement, the Company has a contingent obligation to repurchase up to the full 1,666,667 shares of Series A Preferred Stock at a price per share of $0.75 in the event that, on March 29, 2013 (the date that is twelve months from the closing date), the market value of the stock is less than $1,250,000, and the sellers demand repurchase. Accordingly, the Company has determined that the shares are redeemable at the option of the holder and has classified the Preferred Stock outside of stockholders’ equity on the accompanying balance sheet.
The following table summarizes the allocation of the aggregate contribution as follows:
On May 11, 2012, the Company merged its wholly-owned subsidiary, Excellong E&P-2, Inc. (“E&P-2”), into White Hawk Petroleum, LLC (“White Hawk”), a newly-formed Nevada limited liability company also wholly-owned by the Company (the “E&P-2 Merger”). The separate corporate existence of E&P-2 ceased as a result of the E&P-2 Merger. White Hawk then held all of the Eagle Ford Assets of the Company. The transaction among entities under common control was recorded at historical cost and no gain or loss was recognized. The assets transferred from E&P-2 to White Hawk amounted to $147,000 for tangible equipment and $2,958,936 for proved oil and gas reserves and $629,050 for unproved oil and gas leaseholds (total Eagle Ford E&P-2 property value of $3,734,986). The amount of production, depletion and depreciation between the acquisition date and the merger date was not material over this period.
On May 23, 2012, the Company completed the sale of 50% of the common stock of White Hawk (the “White Hawk Sale”) to an affiliate of MIE Holdings, which is also the Company’s 80% partner in Condor and a significant investor in the Company. As a result of the White Hawk Sale, an affiliate of MIE Holdings and the Company each have an equal 50% ownership interest in White Hawk and each have agreed to proportionately share all expenses and revenues with respect to the Eagle Ford Asset. The sale price consideration for the White Hawk Sale by the affiliate of MIE Holdings was $1,939,082 million as follows:
(1)
$1.0 million in cash paid directly to the original sellers of E&P-2 on behalf of the Company on May 23, 2012, which was the amount due to such sellers 60 days following the acquisition;
(2)
On May 23, 2012, the Company issued 500,000 warrants valued at $1,586 to purchase common stock at $1.25 per share exercisable in cash for a period of two years and an additional 500,000 warrants valued at $1,000 to purchase common stock at $1.50 per share exercisable in cash for a period of two years; and
(3)
The effective date of the sale was March 1, 2012. Accordingly, production activity from the effective date until the closing date is reflected as a purchase price adjustment.
The following table summarizes the allocation of the aggregate sale price as follows:
In connection with the White Hawk Sale, the Company recorded a gain of $64,168 representing the difference between the Company’s carrying value of the 50% interest sold ($1,875,000) and the fair value of the net sale proceeds received from MIE Holdings ($1,939,168).
The pro forma results of the White Hawk sale as if the transaction had occurred at January 1, 2012 and 2011, respectively, is:
NOTE 9 - EQUIPMENT
Property and equipment as of December 31, 2012 and, 2011 consisted of the following:
The AFJ rig, tractor and service trailer were acquired in the Merger transaction. In connection with the Merger, the Company evaluated the carrying value of the AFJ rig and, based upon the independent third party analysis, recorded the estimated fair value of the AFJ rig at $112,089 at the date of the merger, reflecting a reduction in the carrying valve at $254,000.
Depreciation expense for the year ended December 31, 2012 and the period from inception to December 31, 2011 was $30,258, and $662, respectively and are included in operating expenses in the accompanying statement of operations.
NOTE 10 - EQUITY METHOD INVESTMENTS
Condor Energy Technology, LLC
In October 2011, the Company formed a new subsidiary, Condor Energy Technology LLC (“Condor”), a limited liability company organized under the laws of the State of Nevada. Also, in October 2011, the Company issued 4,000,000 shares of its Series A Preferred Stock and an 80% interest in Condor to MIE Holdings for total proceeds of $3,000,000 of which the Company allocated $2,457,312 attributable to the MIE Holdings' investment in Condor, based on the proportionate fair value of the interest purchased by MIE Holdings. Following the transaction, the Company owns 20% of Condor and a subsidiary of MIE Holdings Corporation (“MIE Holdings”) owns 80%. The Company acquired oil and gas interests in the Niobrara formation (the “Niobrara Asset”) on October 31, 2011, and contributed the properties for its interest in Condor immediately upon the acquisition. Condor operates the Niobrara Asset. The $3,000,000 in proceeds received by the Company from the issuance of the 4,000,000 shares of Series A preferred stock were allocated first to MIE Holdings' interest in Condor based on the original purchase price of the Niobrara asset as follows in the table below, with the balance allocated to the Series A preferred stock purchased by MIE Holdings.
The Company accounts for its 20% ownership in Condor using the equity method. The Company evaluated its relationship with Condor to determine if Condor was a variable interest entity (“VIE”) as defined in ASC 810-10, and whether the Company was the primary beneficiary of Condor, in which case consolidation with the Company would be required. The Company determined that Condor qualified as a VIE, however, the Company concluded that MIE Holdings was the primary beneficiary as a result of being in control of the Board and its ability to control the funding commitments to Condor. The Company’s total investment in Condor at December 31, 2012 was $160,353, after recording its share of Condor’s losses for the year ended December 31, 2012 of $428,100.
During the years ended December 31, 2012 and December 31, 2011, the Company loaned Condor funds for operations which were documented in a promissory note entered into on February 14, 2013, with an effective date of November 1, 2012, which note permits multiple loans to be made thereunder up to $8,000,000 and scheduled therein as separate “advances”. The note receivable bears interest at a rate per annum equal to the one (1) month LIBOR rate for U.S. dollar deposits plus four (4.0) percentage points. Principal and interest are due thirty-six (36) months from the date each advance is made under the note, with the first repayment being due September 24, 2015. As of December 31, 2012, the balance of the note receivable is $2,711,992 plus accrued interest of $16,963 from Condor.
The Company has an agreement to provide management services to Condor for which Condor owes $81,124 at December 31, 2012. Total fees billed to Condor were $363,102 and $96,000 in 2012 and 2011.
At December 31, 2012, Condor owes the Company $92,690 from production sales related to the Company’s 18.75% working interest in the Niobrara Asset.
At December 31, 2012, the Company owes Condor $112,069 from production related expenses and $802,614 related to capital expenditures incurred by Condor for the drilling of the three wells during the year ended December 31, 2012.
White Hawk Petroleum, LLC
The Company accounts for its 50% ownership in White Hawk using the equity method. The Company evaluated its relationship with White Hawk to determine if White Hawk was a variable interest entity (“VIE”) as defined in ASC 810-10, and whether the Company was the primary beneficiary of White Hawk, in which case consolidation with the Company would be required. The Company determined that White Hawk qualified as a VIE, however the Company concluded that MIE Holdings was the primary beneficiary as a result of its ability to control the funding commitments to White Hawk. The Company’s entire investment in White Hawk is at risk of loss. The Company’s total investment in White Hawk at December 31, 2012 was $1,937,981 after recording its share of White Hawk’s income for the year ended December 31, 2012 of $70,488.
During the year ended December 31, 2012, the Company loaned White Hawk funds for operating expenses and drilling and completion costs for a third Eagle Ford well, pursuant to a promissory note entered into on June 4, 2012, which note permits multiple loans to be made thereunder and scheduled therein as separate “advances”, with no stated maximum limit of loan principal. The note receivable bears interest at a rate per annum equal to the one (1) month LIBOR rate for U.S. dollar deposits plus four (4.0) percentage points. Principal and interest of each loan is due thirty-six (36) months from the date of each advance is made under the note, with the first repayment being due June 4, 2015. As of December 31, 2012, the balance of the note receivable is $332,974 plus accrued interest of $460 from White Hawk.
NOTE 11 - NOTES PAYABLE
Related Party Transactions
Related Party Notes Payable
Funding with MIE Jurassic Energy Corporation- a related party
During 2012, MIE Jurassic Energy Corporation (“MIEJ”), a subsidiary of MIE Holdings, advanced funds in excess of its ownership interest in Condor. In November 2012, the Company executed a Secured Subordinated Promissory Note in the principal amount of $2,170,065. The note bears interest at 10% and is due upon the earlier of 1) an equity or debt financing transaction completed by the Company or December 31, 2013. At December 31, 2012, the balance owed with accrued interest was $2,206,233.
Global Venture Investments, LLC - a related party
In February 2011, the Company received a $200,000 loan from its president and chief executive officer. Interest accrued at an annual rate of 3%, and principal and interest were due on October 31, 2011. The loan plus accrued interest of $4,258 was repaid in full on October 31, 2011. Upon receipt of these proceeds, the president and chief executive officer used the proceeds to purchase, through Global Venture Investments, LLC, an entity wholly owned and controlled by him, 266,667 shares of the Company’s Series A Preferred Stock at a price of $0.75 per share.
In July 2011, the Company received a $900,000 loan from Global Venture Investments, LLC. Interest accrued at an annual rate of 3%, and principal and interest were due on November 30, 2011. The note was convertible into preferred stock of the Company in the event of the closing of a qualified financing (defined as receipt of at least $2,000,000 in gross proceeds), and the note converted into the securities being sold in the qualified financing at a 50% discount. The qualified financing occurred in October 2011 and the principal amount of this note was converted into 2,400,000 shares ($0.375 per share) of Series A Preferred Stock pursuant to the loan’s original conversion terms. The accrued interest of $8,655 was paid in cash. The Company evaluated the conversion feature and determined no beneficial conversion feature existed as the fair value of the underlying securities fair value was $0.13 per share and was out-of-the-money.
The note agreement also provided for the issuance of a warrant to the holder in the event that the note was automatically converted into a qualified financing. The warrant has a three year term and an exercise price equal to the price paid by the investors in the qualified financing. In connection with the initial closing of the Company’s Series A Preferred Stock financing in October 2011, which was a qualified financing, the Company issued this warrant for 480,000 shares of Series A Preferred Stock at an exercise price of $0.75 per share and a fair value as determined by a Black Scholes option pricing model of $44,600.
Third Party Transactions
Centurion Note Conversions
On August 31, 2012, Centurion converted $101,250 of principal and accrued interest, into 135,000 shares of the Company’s common stock. In October 2012, Centurion converted $536,250 of principal into 715,000 shares of the Company’s common stock. In November 2012, Centurion converted $392,045 of principal into 522,727 shares of the Company’s common stock. Centurion forgave the principal and interest balance of $169,181 and the balance owed Centurion at December 31, 2012 was paid in full.
NOTE 12 - COMMITMENTS
Office Lease
In July 2012, the Company entered into a non-cancelable lease agreement with a term of two years ending in July 2014 for its corporate office space located in Danville, California. The obligation under this lease as of December 31, 2012 is $78,679.
Niobrara Asset - $1 Million Guarantee
Under the Niobrara Asset purchase agreement, the Company agreed to issue 1,333,334 shares of Series A Preferred Stock on November 13, 2012, subject to a guaranteed minimum value of $1 million of the preferred stock. At November 13, 2012, the Sellers had the option to elect to receive the fixed number of 1,333,334 shares or $1 million in cash, due and payable within five days of their written election to receive cash in lieu of the shares. The agreement does not provide the Sellers the option for a variable number of shares based on the per share value. The obligation of $1 million was recorded in accrued expenses on the date of the transaction. The Company received elections from the Sellers requesting payment of the obligation in cash due on or about November 20, 2012. On November 26, 2012, the Agreement was amended to provide for the payment of $100,000 to the Sellers, and 133,334 shares of the preferred stock valued at $100,000 to extend the $1 million payment until February 18, 2013. The fair value of $280,001 of the 133,334 preferred shares issued and the $100,000 payment were recorded as interest expense in 2012. The Company subsequently paid the $1 million on February 18, 2013.
NOTE 13 - PREFERRED STOCK
Series A Convertible Preferred Stock Designations
At December 31, 2012, the Company was authorized to issue 100,000,000 shares of its Series A Preferred Stock with a par value of $0.001 per share.
The holders of our New Series A Preferred Stock are entitled to receive non-cumulative dividends at an annual rate of 6% of the “Original Issue Price” per share, which is $0.75 per share. These dividends will only accrue and become payable if declared by our Board of Directors in its discretion. The right to receive dividends on shares of Series A Preferred Stock is not cumulative, and no right to such dividends will accrue to holders of Series A Preferred Stock by reason of the fact that dividends on said shares are not declared or paid in any calendar year. All declared but unpaid dividends of the shares of New Series A Preferred Stock are payable in cash upon conversion of such shares. Any dividends declared on our New Series A Preferred Stock will be prior and in preference to any declaration or payment of any dividends or other distributions on our common stock. In the event of any liquidation, dissolution or winding up of our Company, either voluntary or involuntary, the holders of our New Series A Preferred Stock will be entitled to receive distributions of any of our assets prior and in preference to the holders of our common stock in an amount per share of New Series A Preferred Stock equal to the sum of (i) the Original Issue Price of $0.75 per share, and (ii) all declared but unpaid dividends on such shares of New Series A Preferred Stock. Each share of New Series A Preferred Stock will be convertible at the option of the holder into that number of fully-paid, nonassessable shares of common stock determined by dividing the “Original Issue Price” for the New Series A Preferred Stock by the conversion price of $0.75 per share (subject to adjustment). Therefore, each share of New Series A Preferred Stock will initially be convertible into one share of our common stock. Our shares of New Series A Preferred Stock will automatically convert into shares of common stock according to the conversion rate described above upon the first to occur of (i) the consent of a majority of the outstanding shares of New Series A Preferred Stock or (ii) the date on which the New Series A Preferred Stock issued on the original issuance date to holders who are not affiliates of the Company may be re-sold by such holders without registration in reliance on Rule 144 promulgated under the Securities Act of 1933, as amended, or another similar exemption. The holders of our New Series A Preferred Stock vote together with the holders of our common stock as a single class (on an “as converted” basis) on all matters to which our shareholders have the right to vote, except as may otherwise be required by law.
Preferred Stock Issuances
During 2011 the Company issued 6,666,667 shares of preferred stock as follows:
●
In October 2011, the Company issued 4,000,000 shares of its New Series A Preferred Stock and an 80% interest in Condor to a subsidiary of MIE Holdings, a related party, for proceeds of $3,000,000. No offering costs were incurred.
●
In October 2011, the Company repaid a $200,000 note payable to its president and chief executive plus accrued interest of $4,258. Upon receipt of these proceeds, the officer used the proceeds to purchase through an entity owned and controlled by him, 266,667 shares of the Company’s New Series A Preferred Stock at a price of $0.75 per share.
●
In October 2011, the Company converted the $900,000 note payable to Global Venture Investments, LLC into 2,400,000 shares of the Company’s New Series A Preferred Stock. Pursuant to the terms of the note, the note’s principal converted into New Series A Preferred Stock at a price of $0.375 per share, which was equal to 50% of the $0.75 price per share of the New Series A Preferred Stock. As required pursuant to the terms of the note, the Company also issued the note holder a warrant to purchase 480,000 shares of New Series A Preferred Stock with an exercise price of $0.75 per share.
During 2012 the Company issued 13,845,703 shares of preferred stock as follows:
●
In 2012, the Company issued 11,053,342 shares of New Series A Preferred Stock to investors for gross cash proceeds of $8,015,071. Offering costs were $246,423.
●
In February 2012, the Company issued 230,000 shares of New Series A Preferred Stock at a value of $172,500 to South Texas Reservoir Alliance LLC. (“STXRA”). A liability was accrued as of December 31, 2011 for this issuance, which issuance was made in full satisfaction of certain obligations to STXRA associated with the Niobrara Asset purchase.
●
In March 2012, the Company issued 1,666,667 shares of its New Series A Preferred Stock valued at $1,250,000 in connection with the acquisition of Excellong E&P-2. (See Note 7.)
●
In July 2012, the Company issued 368,435 shares of its New Series A Preferred Stock valued at $276,326 in exchange for a note receivable from Condor in connection with the acquisition of additional interests by Condor in the Niobrara formation of Weld and Morgan Counties, Colorado.
●
In September 2012, the Company issued 279,749 shares of its New Series A Preferred Stock valued at $559,498 for settlement of a payable due to Esenjay.
●
In November 2012, the Company issued 133,334 shares of its New Series A Preferred Stock to Esenjay pursuant to terms of a Modification Agreement wherein the Company extended the due date of a $1 million payment until February 18, 2013. These shares were recorded as additional interest expense of $280,001 based on the grant date fair value.
●
In October 2012, 27,000 shares of the Company’s New Series A Preferred Stock were converted by an investor into shares of the Company’s common stock.
NOTE 14 - COMMON STOCK
At December 31, 2012, the Company was authorized to issue 200,000,000 shares of its common stock with a par value of $0.001 per share.
During 2011 the Company issued 15,502,261 shares of common stock as follows:
In October 2011, the Company granted 700,000 shares of its restricted Common Stock valued at $0.10 per share to an executive of the Company. These shares were valued at $70,000. The Company recorded stock-based compensation expense of $65,589 in 2012. The shares are subject to forfeiture in the event the recipient is no longer an officer to the Company, which risk of forfeiture lapses with respect to 50% of the shares on June 1, 2012, 25% on December 31, 2012 and the final 25% on June 1, 2013, all contingent upon the recipient's continued service with the Company. These awards were authorized and issued under the Company's equity incentive plan adopted in February 2012. At December 31, 2012, 25% of these 700,000 shares were subject to forfeiture.
●
In February 2011, the Company issued 10,420,000 shares of Common Stock to its founders in exchange for cash in the amount of $10,420.
●
In February 2011, the Company issued 4,100,000 shares of Common Stock in February 2011 to a company that is wholly owned by the Company’s president and chief executive officer in exchange for that company’s 6% interest in the Rare Earth JV. These shares were valued at $4,100.
●
In conjunction with the Niobrara Asset acquisition in 2011, 285,595 shares of the Company’s Common Stock valued at $28,560 were issued to STXRA to arrange the transaction and provide various technical and due diligence services to the Company.
●
In October 2011, the Company signed a letter of intent to merge with a Blast Energy, Inc., a publicly-traded oil and gas exploration and production company. In connection with this proposed merger, the Company issued 696,666 fully vested, nonforfeitable shares of Common Stock to certain investor relations consultants. The Company recorded $69,667 of stock-based compensation expense on the grant date.
During 2012 the Company issued 6,048,230 shares of common stock as follows:
●
In February 2012, the Company granted to five of its consultants and employees a total of 1,655,000 shares of its restricted Common Stock valued at $0.10 per share. The Company recorded stock-based compensation expense of $165,500 on the date of grant. The shares are subject to forfeiture in the event the recipient is no longer an employee, officer, director or consultant to the Company, which risk of forfeiture lapses with respect to 50% of the shares six months from the date of grant, 20% twelve months from the date of grant, 20% eighteen months from the date of grant, and the final 10% twenty-four months from the date of grant, all contingent upon the recipient’s continued service with the Company. These awards were authorized and issued under the Company’s equity incentive plan adopted in February 2012. At December 31, 2012, 50% of these 1,655,000 shares were subject to forfeiture.
●
In September 2012, as a result of the 1:112 Reverse Split, 1,422,873 shares of common stock were issued to shareholders of Blast. (See Note 6).
●
In October 2012, 214,787 shares of common stock were issued in connection with the Blast merger in settlement of outstanding debt of the Company of $487,218. (See Note 6).
●
In December 2012, the Company granted 40,000 shares of its restricted Common Stock with a grant date fair value of $80,000 to an independent contractor for services proved pursuant to our 2012 Equity Incentive Plan.
●
In 2012, 1,372,727 shares of common stock were issued to Centurion pursuant to conversion of debt in the amount of $1,029,545. (See Note 11).
●
In June 2012, non-qualified stock options previously granted to South Texas Reservoir Alliance LLC (“STXRA”), were exercised at the $0.08 exercise price and STXRA paid $4,800 for the issuance of 60,000 shares of common stock.
●
In 2012, 483,256 shares of common stock were issued to employees and consultants in connection with the cashless exercise of common stock options.
●
In 2012, 112,587 shares of common stock were issued to an investor in connection with the cashless exercise of common stock warrants.
●
In October 2012, 27,000 shares of the Company’s New Series A Preferred Stock were converted by an investor into 27,000 shares of the Company’s Common Stock.
NOTE 15 - STOCK OPTIONS AND WARRANTS
Blast 2003 Stock Option Plan and 2009 Stock Incentive Plan
As of December 31, 2012, 30,615 shares of common stock granted under Blast’s 2003 Stock Option Plan and 2009 Stock Incentive Plan remain outstanding and exercisable. No options were issued under these plans in 2012.
2012 Incentive Plan
On July 27, 2012, the shareholders of the Company approved the 2012 Equity Incentive Plan (the “2012 Incentive Plan”), which was previously approved by the Board of Directors on June 27, 2012, and authorizes the issuance of various forms of stock-based awards, including incentive or non-qualified options, restricted stock awards, performance shares and other securities as described in greater detail in the 2012 Incentive Plan, to the Company’s employees, officers, directors and consultants. A total of 6,000,000 shares of Common Stock are eligible to be issued under the 2012 Incentive Plan.
PEDCO 2012 Equity Incentive Plan
As a result of the Merger, the Company assumed the PEDCO 2012 Equity Incentive Plan (the “PEDCO Incentive Plan”), which was adopted by PEDCO on February 9, 2012. The PEDCO Incentive Plan authorized PEDCO to issue an aggregate of 3,000,000 shares of common stock in the form of restricted shares, incentive stock options, non-qualified stock options, share appreciation rights, performance share, and performance unit under the PEDCO Incentive Plan. As of December 31, 2012, options to purchase 3,665,000 shares of PEDCO common stock and 1,655,000 shares of PEDCO restricted common stock had been granted under this plan (all of which were granted by PEDCO prior to the closing of the Merger, with such grants being assumed by the Company and remaining subject to the PEDCO Incentive Plan following the consummation of the Merger). The Company does not plan to grant any additional awards under the PEDCO Incentive Plan post-Merger.
Options
In 2011, the Company granted a non-qualified performance-based option to its consulting executive vice president for 300,000 shares of Common Stock at $0.08 per share with a term of 10 years. At December 31, 2011, none of the performance milestones had been met and, as a result, no expense was recorded in 2011 for this award. This award was modified in February 2012 to a time-based vesting schedule in connection with this consultant becoming a full-time employee of the Company. The vesting terms of the option exercisable for these 300,000 shares are now 50% of the shares subject to the option vesting on March 1, 2012, 25% on June 1, 2012, and the balance of 25% on January 1, 2013, all contingent upon the recipient’s continued service with the Company. The fair value of the options on the date of grant using the Black-Scholes model, was $19,800.
In 2012, options to purchase an aggregate of 265,000 shares of Common Stock were granted to five consultants and employees at an exercise price of $0.10 per share. The options have terms of 10 years and vest in February 2014. 50% of the shares subject to the options vest six months from the date of grant, 20% vest one year from the date of grant, 20% vest eighteen months from the date of grant, and the final 10% vest two years from the date of grant, all contingent upon the recipient’s continued service with the Company. The fair value of the options on the date of grant using the Black-Scholes model, was $20,670.
In 2012, options to purchase an aggregate of 3,400,000 shares of Common Stock were granted to management and employees at an exercise price of $0.17 per share. The options have terms of 10 years and vest in June 2014. 50% of the shares subject to the options vest six months from the date of grant, 20% vest one year from the date of grant, 20% vest eighteen months from the date of grant, and the final 10% vest two years from the date of grant, all contingent upon the recipient’s continued service with the Company. The fair value of the options on the date of grant using the Black-Scholes model, was $272,000.
During the year ended December 31, 2012, the Company recognized option stock-based compensation expense of $243,081. The remaining amount of unamortized stock options expense at December 31, 2012 is $122,963 The Black-Scholes option-pricing model was used to determine fair value. Variables used in the Black-Scholes option-pricing model for the options issued include: (1) a discount rate range of 0.27% to 0.41%, (2) expected term of 2 years, (3) expected volatility range of 88% to 173%, and (4) zero expected dividends.
The intrinsic value of outstanding and exercisable options at December 31, 2012 was $6,870,330 and $3,144,095, respectively.
Option activity during the year ended December 31, 2012 was:
Option activity during the year ended December 31, 2011 was:
Summary of options outstanding and exercisable as of December 31, 2012:
Summary of options outstanding and exercisable as of December 31, 2011:
Warrants
All of the warrants described below were issued in 2012.
In connection with the Series A Preferred Stock issuances, the Company issued warrants to its placement agent and an employee thereof to purchase a total of 60,000 shares of Series A Preferred Stock valued at $0.42 per share on the grant date. These warrants have an exercise price of $0.75 per share and expire in April 2015.
Warrants to purchase an aggregate of 100,000 shares of Common Stock were granted to an advisor at an exercise price of $0.10 per share. The warrants have a term of 10 years and are fully vested on the date of grant. The Company recorded $8,000 of stock compensation expense on the date of grant.
The Company issued warrants to an advisor to purchase a total of 6,500 shares of its Series A Preferred Stock valued at $0.42 per share on the grant date. These warrants have an exercise price of $0.75 per share and expire in May 2015. The Company recorded $2,714 of stock compensation expense on the date of grant.
As part of the sale of 50% of the ownership interests in White Hawk to an affiliate of MIE Holdings, the Company granted a two-year warrant to the affiliate of MIE Holdings exercisable for 500,000 shares of Company common stock at $1.25 per share valued at $1,586, exercisable solely on a cash basis, and granted a two-year warrant to the affiliate of MIE Holdings exercisable for 500,000 shares of Company common stock at $1.50 per share valued at $1,000, exercisable solely on a cash basis. The Company recorded $2,586 of stock-based compensation expense for the fair value of the warrants issued on the date of grant.
The Company issued warrants to seven consultants who provided placement agent services to purchase a total of 143,417 shares of its Series A Preferred Stock valued at $0.42 on the grant date. These warrants have an exercise price of $0.75 per share and expire in July 2015.
The Company issued warrants to three consultants who provided services for public relations, marketing, and Merger integration support to purchase a total of 125,000 shares of its Common Stock valued at $0.04 on the grant date. These warrants have an exercise price of $0.75 per share and expire in July 2015. The Company recorded $52,156 of stock-based compensation expense for the fair value of the warrants issued on the date of grant.
The Company acquired 206,206 warrants as part of the merger with Blast.
The principals of Trident Partners Ltd. (“Trident principals”) were issued an aggregate of 5,010 shares of the Company’s common stock upon the cashless net exercise of warrants exercisable for a total of 11,385 shares of the Company’s common stock that were originally issued to the Trident principals on June 3, 2011 and December 22, 2011 with an exercise price of $1.12 per share.
During the year ended December 31, 2012, the Company recognized warrant stock based compensation expense of $62,839. Fair value was determined by using the Black-Scholes option-pricing model. Variables used in the Black-Scholes option-pricing model for the warrants issued include: (1) discount rate range of 0.30% to 1.12%, (2) expected term range of 2 to 3 years, (3) expected volatility of 83%, and (4) zero expected dividends.
The intrinsic value of outstanding as well as exercisable warrants at December 31, 2012 was $1,883,479.
Warrant activity during the year ended December 31, 2012 was:
Warrant activity during the year ended December 31, 2011 was:
Summary of warrants outstanding and exercisable as of December 31, 2012 is as follows:
Summary of warrants outstanding and exercisable as of December 31, 2011 is as follows:
NOTE 16 - RELATED PARTY TRANSACTIONS
On the October 31, 2011 following the Company’s acquisition of the Niobrara Asset, the Company transferred and assigned to Condor, a Nevada limited liability company owned 20% by the Company and 80% by an affiliate of MIE Holdings, 62.5% of the Niobrara Asset interest acquired by the Company, the net result of which is that each of the Company and MIE Holdings have a 50% net working interest in the Niobrara Asset originally acquired by the Company. Furthermore, Condor was designated as “Operator” of the Niobrara Asset. Condor’s Board of Managers is comprised of the Company’s President and Chief Executive Officer, Mr. Frank Ingriselli, and two designees of MIE Holdings. In addition, in connection with the drilling and completion of the initial well on the Niobrara asset, and in light of our then-existing cash position, MIE Holdings loaned funds to Pacific Energy Development Corp., our wholly-owned subsidiary (“PEDCO”), equal to all of our proportional fees and expenses on that project, and has additionally loaned funds to PEDCO sufficient to fund our 20% portion of Condor expenses incurred in connection with the second and third wells drilled and completed by Condor on the Niobrara asset in January and February 2013. These loans were documented through the entry on February 14, 2013 of a Secured Subordinated Promissory Note (the “Note”) with MIEJ, with an effective date of November 1, 2012. Under the Note, PEDCO may draw down multiple advances up to a maximum of $5 million under the Note, with repaid amounts not being permitted to be re-borrowed. Amounts borrowed under the Note may only be used by PEDCO to fund fees and expenses allocable to PEDCO with respect to its operations in the Niobrara asset located in Weld and Morgan Counties, Colorado (the “Niobrara Asset”). When drawn, principal borrowed under the Note carries an interest rate of 10.0% per annum. Principal and accrued interest under the Note shall be due and payable within ten (10) business days of the earlier to occur of (i) December 31, 2013 or (ii) the closing of a debt or equity financing transaction with gross proceeds to the Company of at least $10 million. The Note may be prepaid in full by PEDCO without penalty, and is secured by all of PEDCO’s ownership and working interests in the FFT2H well located in the Niobrara Asset, and all corresponding leasehold rights pooled with respect to such well, and PEDCO’s ownership and working interests in each future well drilled and completed in the Niobrara Asset. The Note converts amounts previously advanced by MIEJ to PEDCO in the amount of $2.17 million to fund operations in the Niobrara Asset through November 1, 2012, as well as an additional $2 million loaned by MIEJ to PEDCO under the Note on February 14, 2013, for a total current principal amount outstanding under the Note of $4.17 million on February 14, 2013. There is currently approximately $830,000 available for future borrowing by PEDCO under the Note.
In October 2011, the Company issued 4,000,000 shares of its Series A Preferred Stock and an 80% interest in Condor to MIE Holdings for proceeds of $3,000,000.
In May 2012, the Company merged its wholly-owned subsidiary, Excellong E&P-2, Inc., into White Hawk and then sold 50% of its ownership interests in White Hawk to an affiliate of MIE Holdings and issued certain warrants thereto. .
During the year ended December 31, 2012, the Company loaned White Hawk funds to fund operating expenses and drilling and completion costs for a third Eagle Ford well, pursuant to a promissory note entered into on June 4, 2012, between the Company and White Hawk, which note permits multiple loans to be made thereunder and schedule therein as separate “advances” with no stated maximum limit of loan principal. The note receivable bears interest at a rate per annum equal to the one (1) month LIBOR rate for U.S. dollar deposits plus four (4.0) percentage points. Principal and interest of each loan is due thirty-six (36) months from the date of each advance under the note, with the first repayment being due June 4, 2015. As of December 31, 2012 the total notes payable and accrued interest are $332,974 and $459, respectively.
On September 24, 2012, Condor entered into a promissory note (the “PEDCO Note”) The Company, pursuant to which Condor may borrow, from time to time, cash advances from the Company up to a maximum amount of $8,000,000 to fund Condor’s operations as permitted under its Operating Agreement. When drawn, principal borrowed under the PEDCO Note carries an interest rate of per annum equal to the one (1) month term, LIBOR, plus four (4.0) percent. Principal and accrued interest under the PEDCO Note shall be due and payable on the date that is 36 months from the date of each advance thereunder, or on demand following the occurrence of an event of default, as defined therein. The PEDCO Note may be prepaid in full by Condor without penalty.
On November 1, 2012, and pursuant to the terms of the Inter-Company Agreement, Condor and the Company amended and restated the PEDCO Note in full to capitalize interest accrued under the PEDCO Note to November 1, 2012. As a result $1,224 in accrued interest was capitalized as additional principal. During the year ended December 31, 2012, the Company advanced $2,434,442 in cash and 368,435 shares of PEDEVCO’s Series A Preferred Stock valued at $276,326. As of December 31, 2012, Condor had $2,711,992 and $16,963 in loans payable and accrued interest, respectively, to the Company. The note principal includes the $276,326 value of the 368,435 shares issued by Pedevco.
Accruals for drilling costs due to Condor as a working interest owner and revenue receivable due from Condor as a working interest owner represent capital expenditures, lease operating expenses and revenues allocable to the Company for its 18.75% working interest and 15% net revenue interest in the Niobrara asset.
During the year ended December 31, 2012 and for the period from inception through December 31, 2011, the Company charged $375,441 and $96,000, respectively, in expenses related to a management services agreement with Condor. This management fee represents an amount agreed upon between MIEJ and the Company as being reflective of the approximate amount of time and resources the Company personnel dedicates to Condor-related matters on a monthly basis. Prior to November 1, 2012, the Company charged a monthly management of $28,250 to Condor. On November 1, 2012, the Company began charging a monthly management fee of $40,300. Condor will be paying a monthly management fee at least for the duration of 2013 based on the agreed upon 2013 budget. As of December 31, 2012 and 2011, the Company had accrued $81,124 and $96,000 in amounts due from Condor under the agreement.
NOTE 17 - INCOME TAXES
Due to the Company’s net loss, there was no provision for income taxes for the period from February 9, 2011 (Inception) and December 31, 2011 and the year ended December 31, 2012.
The difference between the income tax expense of zero shown in the statement of operations and pre-tax book net loss times the federal statutory rate of 34% is principally due to the change in the valuation allowance.
Deferred income taxes assets for the period from February 9, 2011 (Inception) through December 31, 2012 are as follows:
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of deferred assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible.
Based on the available objective evidence, management believes it is more likely than not that the net deferred tax assets will not be fully realizable. Accordingly, management has applied a full valuation allowance against its net deferred tax assets at December 31, 2012. The net change in the total valuation allowance for the period from February 9, 2011 (Inception) through December 31, 2012 was an increase of $1,947,749.
The Company’s policy is to recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. As of December 31, 2012, the Company did not have any significant uncertain tax positions or unrecognized tax benefits. The Company did not have associated accrued interest or penalties, nor was any interest expense or penalties recognized during the period from February 9, 2011 (Inception) through December 31, 2012.
As of December 31, 2012 the Company has federal net operating loss carryforwards of approximately $4,692,988 for federal and state tax purposes, respectively. If not utilized, these losses will begin to expire beginning in 2031 for both federal and state purposes.
Utilization of NOL and tax credit carryforwards may be subject to a substantial annual limitation due to ownership change limitations that may have occurred or that could occur in the future, as required by the Internal Revenue Code (the “Code”), as amended, as well as similar state provisions. In general, an "ownership change" as defined by the Code results from a transaction or series of transactions over a three-year period resulting in an ownership change of more than 50 percent of the outstanding stock of a company by certain stockholders or public groups.
NOTE 18 - COMMITMENTS AND CONTINGENCIES
Our oil and gas leasehold acreage is subject to expiration of leases if we do not drill and hold such acreage by production. In the Niobrara asset 1,510 net acres expire in 2013, 429 net acres expire in 2014, 123 net acres expire in 2015 and 95 net acres expire thereafter. We plan to hold significantly all of this acreage through an active program of drilling and completing producing wells. Where we are not able to drill a well before lease expiration we will seek to extend leases where able. 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. In the Eagle Ford asset the balance of our 26 net acres not held by production will expire in 2013. However, 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.
The Company is not aware of any pending or threatened legal proceedings. The foregoing is also true with respect to each officer, director and control shareholder as well as any entity owned by any officer, director and control shareholder, over the last five years.
As part of its regular operations, the Company may become party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its’ commercial operations, products, employees and other matters. Although the Company can give no assurance about the outcome of these or any other pending legal and administrative proceedings and the effect such outcomes may have on the Company, except as described above, the Company believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the Company’s financial condition or results of operations.
Our board has adopted a compensation program that, effective for periods after 2012, will provide each of our “independent” directors as defined in NYSE MKT rules or under Rule 10A-3 of the Exchange Act with compensation consisting of (a) a quarterly cash payment of $5,000, and (b) an annual equity award consisting of shares of restricted stock valued at $60,000, vesting on the date that is one year following the date of grant. Effective upon the completion of the Company’s pending public offering of its securities as contemplated by that certain Registration Statement on Form S-1 filed by the Company with the Securities and Exchange Commission on October 10, 2012, as amended (the “Pending Public Offering”), the Company plans to appoint two “independent” directors to the Board, each of whom shall receive an equity award consisting of shares of restricted stock valued at $60,000, vesting on the date that is one year following the date of grant, in accordance with this compensation program.
NOTE 19 - SUBSEQUENT EVENTS
On December 13, 2012, we granted 40,000 shares of common stock with a grant date fair value of $80,000 to an independent contractor for services provided pursuant to our 2012 Equity Incentive Plan, which shares were issued in January 2013.
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 was issued an aggregate of 141,176 shares of our Series A preferred stock in January 2013.
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 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.
On November 30, 2012, Condor Energy Technology LLC (“Condor”), a joint venture between the Company and MIEJ entered into an Agreement for Purchase of Term Assignment (the “Original Mississippian Agreement”) for the acquisition by Condor of interests in the Mississippian Lime covering approximately 13,806 net acres located in Comanche, Harper, Barber and Kiowa Counties, Kansas and Wood County, Oklahoma, and approximately 19.5 square miles of related 3-D seismic data, for an aggregate purchase price of $8,648,661. Pursuant to the Original Mississippian Agreement, Condor paid an initial deposit in the amount of $864,866 (the “Initial Deposit”), which was funded equally by MIEJ and the Company. On February 8, 2013, the Company, Condor and Berexco LLC (“Berexco”) entered into a Termination of Agreement for Purchase of Term Assignment; Agreement to Transfer Performance Deposit and Negotiate in Good Faith (the “Mutual Termination and Deposit Transfer Agreement”), in which Condor and Berexco mutually agreed, without fault of either party, to terminate the Original Mississippian Agreement. In the Mutual Termination and Deposit Transfer Agreement, the Company and Berexco agreed they would negotiate in good faith the terms and conditions of an alternative transaction whereby the Company would acquire the rights to the leases previously to be acquired under the Original Mississippian Agreement by Condor (the “Proposed PEDEVCO-Berexco Transaction”). The Initial Deposit continued to be held in escrow pending the entry into a new escrow agreement provided that if no agreement with respect to the Proposed PEDEVCO-Berexco Transaction was entered into by February 22, 2013, then the escrowed funds would be returned to the Company.
On February 22, 2013, Pacific Energy Development MSL LLC (“PEDCO MSL”), a wholly owned subsidiary of the Company, entered into an Agreement for Purchase of Term Assignment (the “Purchase Agreement”) with Berexco for the acquisition of interests in the Mississippian Lime covering approximately 6,763 net acres located in Comanche, Harper, Barber and Kiowa Counties, Kansas (the “Mississippian Asset”) and approximately 10.5 square miles of related 3-D seismic data, for an aggregate purchase price of $4,207,117. Pursuant to the Purchase Agreement, Berexco applied the Initial Deposit of $864,866 made in connection with the Original Mississippian Agreement to this new transaction. Closing is anticipated to occur in March 2013, subject to the satisfaction of certain customary closing conditions and the Company's ability to secure sufficient financing, of which there can be no assurances. In addition, PEDCO MSL and Berexco entered into an option agreement, dated February 22, 2013, pursuant to which Berexco granted to PEDCO MSL an exclusive option (an “Option”), expiring on May 30, 2013, to purchase a term assignment with respect to certain interests in the Mississippian Lime covering an additional approximately 7,043 net acres located in Comanche, Harper, Barber and Kiowa Counties, Kansas, and Woods County, Oklahoma and approximately 9.0 square miles of related 3-D seismic data, for an aggregate purchase price upon exercise of the Option of $4,216,544. The Company remains obligated to MIEJ to refund its portion of the Initial Deposit paid in the amount of $432,433.
On February 14, 2013, Pacific Energy Development Corp. (“PEDCO”), a wholly owned subsidiary of the Company, entered into a Secured Subordinated Promissory Note (the “Note”) with MIEJ, with an effective date of November 1, 2012. Under the Note, PEDCO may draw down multiple advances up to a maximum of $5 million under the Note, with repaid amounts not being permitted to be re-borrowed. Amounts borrowed under the Note may only be used by PEDCO to fund fees and expenses allocable to PEDCO with respect to its operations in the Niobrara asset located in Weld and Morgan Counties, Colorado (the “Niobrara Asset”). When drawn, principal borrowed under the Note carries an interest rate of 10.0% per annum. Principal and accrued interest under the Note shall be due and payable within ten (10) business days of the earlier to occur of (i) December 31, 2013 or (ii) the closing of a debt or equity financing transaction with gross proceeds to the Company of at least $10 million. The Note may be prepaid in full by PEDCO without penalty, and is secured by all of PEDCO’s ownership and working interests in the FFT2H well located in the Niobrara Asset, and all corresponding leasehold rights pooled with respect to such well, and PEDCO’s ownership and working interests in each future well drilled and completed in the Niobrara Asset. The Note converts amounts previously advanced by MIEJ to PEDCO in the amount of $2.17 million to fund operations in the Niobrara Asset through November 1, 2012, as well as an additional $2 million loaned by MIEJ to PEDCO under the Note for a total of $4.17 million outstanding on February 14, 2013. There is approximately $830,000 available for future borrowing by PEDCO under the Note.
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
The following supplemental unaudited information regarding PEDEVCO’s direct oil and gas activities is presented pursuant to the disclosure requirements of ASC 932. All oil and gas operations are located in the U.S.
(4) Reserve quantity information:
The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available. All of the Company’s reserves are located in the United States.
Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods.
The standardized measure of discounted future net cash flows is computed by applying the average first day of the month price of oil and gas during the 12 month period before the end of the year (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.
The reserve estimates set forth below were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), a professional engineering firm certified by the Texas Board of Professional Engineers (Registration number), 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.
The reserve estimates were prepared by Ryder Scott using reserve definitions and pricing requirements prescribed by the SEC.
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 the Company or obtained from public data sources. All of the proved developed non-producing and undeveloped reserves were estimated by analogy.
The standardized measure of discounted future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of future production of reserves. Revisions of previous year estimates can have a significant impact on these results. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the Company’s proved oil and natural gas properties.
Future income tax expense was computed by applying statutory rates, less the effects of tax credits for each period presented, to calculate the difference between pre-tax net cash flows relating to the Company’s proved reserves and the tax basis of proved properties, after consideration of available net operating loss and percentage depletion carryovers.
The following table sets forth the standardized measure of discounted future net cash flows (stated in thousands) relating to the proved reserves as of December 31, 2012:
Explanatory Note
Rule 3-09 of Regulation S-X provides that if a 50% or less owned person accounted for by the equity method meets the first or third condition of the significant subsidiary tests set forth in Rule 1-02(w) of Regulation S-X, substituting 20% for 10%, separate financial statements for such 50% or less owned person shall be filed. As Condor Energy Technology, LLC met such test as of December 31, 2012 and December 31, 2011, and for the period from October 12, 2011 to December 31, 2011 and for the year ended December 31, 2012, PEDEVCO CORP. has included in this Form 10-K the audited financial statements for the year ended December 31, 2012 and for the period from October 12, 2011 (Inception) to December 31, 2011.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Members of
Condor Technology Services, LLC
Danville, CA
We have audited the accompanying balance sheets of Condor Technology Services, LLC as of December 31, 2012 and 2011, and the related statements of operations, changes in members’ equity and cash flows for the year ended December 31, 2012 and for the period from October 12, 2011 (inception) through December 31, 2011. Condor Technology Services, LLC’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Condor Technology Services, LLC as of December 31, 2012 and 2011, and the results of its operations and its cash flows for the year ended December 31, 2012 and the period from October 12, 2011 (inception) through December 31, 2011 in conformity with accounting principles generally accepted in the United States of America.
The accompanying financial statements have been prepared assuming that Condor Technology Services, LLC will continue as a going concern. As discussed in Note 2 to the financial statements, Condor Technology Services, LLC has suffered recurring losses from operations that raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.
/s/ GBH CPAs, PC
GBH CPAs, PC
www.gbhcpas.com
Houston, Texas
March 22, 2013
CONDOR ENERGY TECHNOLOGY, LLC
BALANCE SHEETS
See accompanying notes to financial statements.
CONDOR ENERGY TECHNOLOGY, LLC
STATEMENTS OF OPERATIONS
For the Year Ended December 31, 2012 and for the
Period from October 12, 2011 (Inception) through December 31, 2011
See accompanying notes to financial statements.
CONDOR ENERGY TECHNOLOGY, LLC
STATEMENT OF CHANGES IN MEMBERS’ EQUITY
For the Period from October 12, 2011 (Inception) through December 31, 2011
and for the Year Ended December 31, 2012
See accompanying notes to financial statements.
CONDOR ENERGY TECHNOLOGY, LLC
STATEMENTS OF CASH FLOWS
For the Year Ended December 31, 2012 and for the
Period from October 12, 2011 (Inception) through December 31, 2012
See accompanying notes to financial statements.
CONDOR ENERGY TECHNOLOGY, LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - BASIS OF PRESENTATION
The accompanying financial statements of Condor Energy Technology, LLC, (“Condor” or the “Company”), have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the Securities and Exchange Commission (“SEC”).
NOTE 2 - DESCRIPTION OF BUSINESS
The Company was formed on October 12, 2011 as a Nevada limited liability company. Initial members’ equity was contributed by Pacific Energy Development Corp. (“PEDCO”), a wholly owned subsidiary of PEDEVCO Corp. (“PEDEVCO”), and MIE Jurassic Energy Corporation (“MIEJ”), a subsidiary of MIE Holdings Corporation (“MIE Holdings”) through the contribution of working interests in certain oil and gas properties in Colorado in the Niobrara formation during October 2011. MIE Holdings (Hong Kong Stock Exchange code: 1555.HK) is one of the largest independent upstream onshore oil companies in China. Condor’s primary business plan is engaging in oil and gas exploration, development and production of primarily shale oil and gas and secondarily conventional oil and gas opportunities in the United States.
Condor’s operations consist primarily of working interests in oil and gas leases in the Niobrara shale formation located in the Denver-Julesberg Basin in Morgan and Weld Counties, Colorado. PEDCO owns a 20% interest in Condor; the remaining interest in Condor is owned by MIEJ.
The Company plans to focus initially on developing shale oil and gas assets held by the Company in the U.S., including its first oil and gas working interest known as “the Niobrara Asset”. Subsequently, the Company plans to seek additional shale oil and gas and conventional oil and gas asset acquisition opportunities in the U.S. and Pacific Rim countries utilizing its strategic relationships and technologies that may provide the Company a competitive advantage in accessing and exploring such assets.
NOTE 3 - GOING CONCERN
The accompanying 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 $2,269,874 for the period from October 12, 2011 (inception) 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.
NOTE 4 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates in Financial Statement Preparation. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates generally include those with respect to the amount of recoverable oil and gas reserves, oil and gas depletion and asset retirement obligations.
Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. As of December 31, 2012 and 2011, cash and cash equivalents consisted of money market funds and cash on deposit.
Concentrations of Credit Risk. Financial instruments which potentially subject the Company to concentrations of credit risk include cash deposits placed with financial institutions. The Company maintains its cash in bank accounts which, at times, may exceed federally insured limits as guaranteed by the Federal Deposit Insurance Corporation (FDIC). At December 31, 2012, approximately $490,000 of the Company’s cash balances were uninsured. The Company has not experienced any losses in such accounts.
Sales to one customer comprised 100% of the Company’s total oil and gas sales for the year ending December 31, 2012. There were no sales in the period ended December 31, 2011. The Company believes that, in the event that its primary customer was unable or unwilling to continue to purchase the Company’s production, there are a substantial number of alternative buyers for its production at comparable prices.
Accounts Receivable. Accounts receivable typically consist of oil and gas receivables from our working interest owners. The Company has classified these as short-term assets in the balance sheet because the Company expects repayment or recovery within the next 12 months. The Company evaluates these accounts receivable for collectability considering the results of operations of these related entities and when necessary records allowances for expected unrecoverable amounts. To date, no allowances have been recorded.
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 and natural gas. Revenue from crude oil and natural gas sales is recognized when the product is delivered to the purchaser and collectability is reasonably assured. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves. If collection is uncertain, revenue is recognized when cash is collected.
Deferred Property Acquisition Costs. The Company defers the costs, such as title and legal fees, related to oil and gas property acquisitions. At the time the acquisition is completed, these costs are reclassified and included as part of the purchase price of the property acquired. To the extent a property acquisition is not consummated these costs are expensed.
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.
Impairment of Long-Lived Assets. The Company reviews the carrying value of its long-lived assets annually or whenever events or changes in circumstances indicate that the historical cost-carrying value of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the future net undiscounted cash flows expected to result from the asset, including eventual disposition. If the future net undiscounted cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and estimated fair value.
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, the Company will record a liability (an asset retirement obligation or “ARO”) on its balance sheet and capitalize the present value of the asset retirement cost in oil and 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 the 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 statements of operations.
Income Taxes. The Company is organized as a Limited Liability Company. A limited liability company is not a taxpaying entity. Any income or operating loss arising from the activities of the company is reported, after appropriate adjustments, on the personal income tax returns of the members. Adjustments to the income or loss allocated to a particular member will be required when the tax basis and accounting basis of net contributions made by an individual member are not equal. Because the company is not a taxpaying entity, its financial statements are different from those of taxpaying entities. Specifically, on the income statements there is no provision for federal income tax expense that must be paid because income was earned during the year. In addition, the balance sheets do not present a liability for income taxes incurred but not yet paid as of the balance sheet dates. Also, the balance sheets does not present any deferred tax assets or liabilities that might arise from different methods used to measure net income for the income statements and taxable income for the individual members.
Fair Value of Financial Instruments. The Company follows Financial Accounting Standards Board (“FASB”) ASC 820, Fair Value Measurement (“ASC 820”), which clarifies fair value as an exit price, establishes a hierarchal disclosure framework for measuring fair value, and requires extended disclosures about fair value measurements. The provisions of ASC 820 apply to all financial assets and liabilities measured at fair value.
As defined in ASC 820, fair value, clarified as an exit price, represents the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As a result, fair value is a market-based approach that should be determined based on assumptions that market participants would use in pricing an asset or a liability.
As a basis for considering these assumptions, ASC 820 defines a three-tier value hierarchy that prioritizes the inputs used in the valuation methodologies in measuring fair value.
Level 1 - Quoted prices in active markets for identical assets or liabilities.
Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
Recently Issued Accounting Pronouncements. There were various accounting standards and interpretations issued during 2012 and 2013, none of which are expected to have a material impact on the Company’s financial position, operations or cash flows.
In July 2012 the FASB issued ASU 2012-02 Testing Indefinite-Lived Intangible Assets for Impairment, which amends Topic 350 and gives companies the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with Topic 350-30. This ASU shall be applied prospectively for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012 and early adoption is permitted. Implementation of the ASU is not expected to have a significant impact on the Company’s financial statements.
Subsequent Events. The Company has evaluated all transactions through the date the financial statements were issued for subsequent event disclosure consideration.
NOTE 5 - OIL AND GAS PROPERTIES
Activities related to oil and gas properties during the year ended December 31, 2012 and the period from October 12, 2011 (Inception) through December 31, 2011 consisted of the following:
The following tables summarize the Company’s oil and gas activities by classification for the year ended December31, 2012 and the period from October 12, 2011 (Inception) through December 31, 2011:
Niobrara Asset
PEDCO acquired a 50% working interest in unproved oil and gas leases in Colorado in a geologic formation known as the Niobrara formation (the “Niobrara Asset”) on October 31, 2011 for a total cost of $4,914,624. PEDCO assigned a 31.25% working interest valued at $3,071,640 of the Niobrara interest acquired to Condor. The oil and gas properties assigned consisted of 4,416 net acres in the Niobrara formation in Colorado.
During the year ended December 31, 2012, the Company began drilling operations on its FFT2H, Logan 2H and Waves 1H wells. The Company completed the FFT2H well in June 2012 and incurred $3,734,152 in drilling and completion costs. As of December 31, 2012, the Company has incurred $804,759 and $860,382 in drilling costs related to the Logan 2H and Waves 1H wells, respectively, which were completed subsequent to December 31, 2012
On September 24, 2012, the Company acquired an additional 30% working interest and 3,595 net acres from Esenjay Oil & Gas, Ltd. ("Esenjay"), in the Niobrara asset. The purchase price was $1,381,636, which consisted of $1,105,310 in cash loaned from MIEJ and 368,435 shares of PEDEVCO’s Series A Preferred Stock valued at $276,326. In addition to this acquisition, the Company incurred $267,678 in land and title fees related to the additional acreage acquired.
Esenjay retains an overriding royalty interest in the production from the leases assigned equal to the amount, if positive, by which twenty percent (20%) of production exceeds the aggregate of all landowner royalties, overriding royalties and other burdens measured or payable out of the production that cover or affect the subject leases.
In December 2012, the Company acquired 319 net acres for $84,151 from various working interest owners in the Niobrara asset.
During the year ended December 31, 2012, the Company had leases expire related to 573 net acres in unproved properties. The Company recorded an impairment to unproved properties of $369,037. For the period from October 12, 2011 to December 31, 2011, there was no impairment of oil and gas properties.
NOTE 6 - DEFERRED ACQUISITION COSTS
On November 30, 2012, Condor, entered into an Agreement for Purchase of Term Assignment (the “Original Mississippian Agreement”) for the acquisition by Condor of interests in the Mississippian Lime covering approximately 13,806 net acres located in Comanche, Harper, Barber and Kiowa Counties, Kansas and Wood County, Oklahoma, and approximately 19.5 square miles of related 3-D seismic data, for an aggregate purchase price of $8,648,661. Pursuant to the Original Mississippian Agreement, Condor paid an initial deposit in the amount of $864,866 (the “Initial Deposit”), which was funded equally by MIEJ and PEDEVCO. In addition, as of December 31, 2012, the Company has incurred $125,354 in due diligence costs related to the acquisition.
NOTE 7 - RELATED PARTY TRANSACTIONS
On the October 31, 2011 following PEDCO’s acquisition of the Niobrara Asset, PEDCO transferred and assigned to Condor, 62.5% of the Niobrara Asset interest acquired by PEDCO, the net result of which is that each of PEDCO and MIEJ have a 50% net working interest in the Niobrara Asset originally acquired by PEDCO. Furthermore, Condor was designated as “Operator” of the Niobrara Asset. Condor’s Board of Managers is comprised of PEDEVCO’s President and Chief Executive Officer, Mr. Frank Ingriselli, and two designees of MIEJ.
PEDCO
Receivables from related party working interest owner and revenue payable to related party working interest owner are capital expenditures, lease operating expenses and revenues allocable to PEDCO for its 18.75% working interest and 15% net revenue interest in the Niobrara asset.
As of December 31, 2012, the Company had accounts payable of $100,180 owed to South Texas Reservoir Alliance LLC (“STXRA”), a related party, which performed engineering services on the Niobrara oil and gas properties. As of December 31, 2011, the Company had accounts payable of $203,750 owed to PEDCO for expenses paid by PEDCO on behalf of the Company.
During the year ended December 31, 2012 and for the period from inception through December 31, 2011, the Company incurred $375,441 and $96,000, respectively, in expenses related to a management services agreement with PEDCO. This management fee represents an amount agreed upon between MIEJ and PEDCO as being reflective of the approximate amount of time and resources the PEDCO team dedicates to Condor-related matters on a monthly basis. Prior to November 1, 2012, PEDCO charged a monthly management of $28,250 to the Company. On November 1, 2012, PEDCO began charging a monthly management fee of $40,300. The Company will be paying a monthly management fee at least for the duration of 2013 based on the agreed upon 2013 budget. As of December 31, 2012 and 2011, the Company had accrued $81,124 and $96,000 in amounts owed under the agreement.
Notes Payable - MIEJ and PEDCO
On March 7, 2012, Condor entered into a promissory note (the “MIEJ Note”) with MIEJ, the holder of 80% of the membership interests in Condor, pursuant to which Condor may borrow, from time to time, cash advances from MIEJ up to a maximum amount of $8,000,000 to fund Condor’s operations as permitted under its Operating Agreement. When drawn, principal borrowed under the MIEJ Note carries an interest rate of per annum equal to the one (1) month term, LIBOR, plus four (4.0) percent. Principal and accrued interest under the MIEJ Note shall be due and payable on the date that is 36 months from the date of each advance thereunder, or on demand following the occurrence of an event of default, as defined therein. The MIEJ Note may be prepaid in full by Condor without penalty.
On September 24, 2012, Condor entered into a promissory note (the “PEDCO Note”) PEDCO, pursuant to which Condor may borrow, from time to time, cash advances from PEDCO up to a maximum amount of $8,000,000 to fund Condor’s operations as permitted under its Operating Agreement. When drawn, principal borrowed under the PEDCO Note carries an interest rate of per annum equal to the one (1) month term, LIBOR, plus four (4.0) percent. Principal and accrued interest under the PEDCO Note shall be due and payable on the date that is 36 months from the date of each advance thereunder, or on demand following the occurrence of an event of default, as defined therein. The PEDCO Note may be prepaid in full by Condor without penalty.
On November 1, 2012, and pursuant to the terms of an Inter-Company Agreement entered into by and between PEDCO and MIEJ (the “Inter-Company Agreement”), Condor and MIEJ amended and restated the MIEJ Note in full to capitalize interest accrued under the original MIEJ Note to November 1, 2012, and to increase the maximum amount of cash advances under the note to $14,000,000. As a result $137,371 in accrued interest was capitalized as additional principal. During the year ended December 31, 2012, MIEJ advanced $9,240,798. As of December 31, 2012, the Company had $9,528,169 and $57,381 in notes payable and accrued interest, respectively, to MIEJ.
On November 1, 2012, and pursuant to the terms of the Inter-Company Agreement, Condor and PEDCO amended and restated the PEDCO Note in full to capitalize interest accrued under the PEDCO Note to November 1, 2012. As a result $1,224 in accrued interest was capitalized as additional principal. During the year ended December 31, 2012, PEDCO advanced $2,434,442 in cash and 368,435 shares of PEDEVCO’s Series A Preferred Stock valued at $276,326. As of December 31, 2012, the Company had $2,711,992 and $16,963 in loans payable and accrued interest, respectively, to PEDCO. The note principal includes the $276,326 fair market value of the 368,435 shares issued by Pedevco.
NOTE 8 - ASSET RETIREMENT OBLIGATIONS
The Company records the fair value of a liability for asset retirement obligations (“ARO”) in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The present value of the estimated asset retirement costs is capitalized as part of the long-lived asset and is depreciated over the useful life of the asset. The Company accrues an abandonment liability associated with its oil and gas wells when those assets are placed in service or acquired. The ARO is recorded at its estimated fair value and accretion is recognized over time as the discounted liability is accreted to its expected settlement value. Fair value is determined by using the expected future cash outflows discounted at the Company’s credit -adjusted cost of capital risk-free rate. No market premium has been included in the Company’s calculation of the ARO balance.
The following is a description of the changes to the Company’s ARO for the year ended December 31, 2012 and for the period from inception through December 31, 2011. There was no ARO recorded during 2011.
NOTE 9 - INCOME TAXES
The Company is organized as a limited liability company and all taxable income is taxed directly to the members thus there is no provision for income taxes. The Company’s basis in its assets for financial reporting purposes is lower than that of its tax basis by approximately $200,000 (unaudited).
NOTE 10 - COMMITMENTS AND CONTINGENCIES
The Company is not aware of any pending or threatened legal proceedings. The foregoing is also true with respect to each officer, director and control shareholder as well as any entity owned by any officer, director and control shareholder, over the last five years.
As part of its regular operations, the Company may become party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its’ commercial operations, products, employees and other matters. Although the Company can give no assurance about the outcome of these or any other pending legal and administrative proceedings and the effect such outcomes may have on the Company, except as described above, the Company believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the Company’s financial condition or results of operations.
NOTE 11 - MEMBERS’ EQUITY
On October 31, 2011 following PEDCO’s acquisition of the Niobrara Asset, PEDCO transferred and assigned to Condor 62.5% of the Niobrara Asset interest acquired by PEDCO valued at $3,071,640. As a result of the assignment, PEDCO received a 20% ownership in Condor and MIEJ received an 80% ownership of Condor.
NOTE 12 - SUBSEQUENT EVENTS
On February 8, 2013, PEDEVCO, Condor and Berexco LLC (“Berexco”) entered into a Termination of Agreement for Purchase of Term Assignment; Agreement to Transfer Performance Deposit and Negotiate in Good Faith (the “Mutual Termination and Deposit Transfer Agreement”), in which Condor and Berexco mutually agreed, without fault of either party, to terminate the Original Mississippian Agreement. In the Mutual Termination and Deposit Transfer Agreement, PEDEVCO and Berexco agreed they would negotiate in good faith the terms and conditions of an alternative transaction whereby PEDEVCO would acquire the rights to the leases previously to be acquired under the Original Mississippian Agreement by Condor (the “Proposed PEDEVCO-Berexco Transaction”). The Initial Deposit continued to be held in escrow pending the entry into a new escrow agreement provided that if no agreement with respect to the Proposed PEDEVCO-Berexco Transaction was entered into by February 22, 2013, then the escrowed funds would be returned to PEDEVCO.
On February 22, 2013, Pacific Energy Development MSL LLC (“PEDCO MSL”), a wholly owned subsidiary of PEDEVCO, entered into an Agreement for Purchase of Term Assignment (the “Purchase Agreement”) with Berexco for the acquisition of interests in the Mississippian Lime. Pursuant to the Purchase Agreement, Berexco applied the Initial Deposit of $864,866 made in connection with the Original Mississippian Agreement to this new transaction. Closing is anticipated to occur in March 2013, subject to the satisfaction of certain customary closing conditions and PEDEVCO’s ability to secure sufficient financing, of which there can be no assurances. PEDEVCO is obligated to pay to Condor the $432,433 portion of the deposit to be re paid by MIEJ to Condor and PEDEVCO will also re pay its portion of the $432,333 deposit to Condor.
Explanatory Note
Rule 3-09 of Regulation S-X provides that if a 50% or less owned person accounted for by the equity method meets the first or third condition of the significant subsidiary tests set forth in Rule 1-02(w) of Regulation S-X, substituting 20% for 10%, separate financial statements for such 50% or less owned person shall be filed. As White Hawk Petroleum, LLC met such test as of December 31, 2012 and for the period from May 11, 2012 (Inception) to December 31, 2012, PEDEVCO CORP. has included in this Form 10-K the audited financial statements as of and for the period from May 11, 2012 (Inception) to December 31, 2012.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Members of
White Hawk Petroleum, LLC
Danville, CA
We have audited the accompanying balance sheet of White Hawk Petroleum, LLC as of December 31, 2012, and the related statements of operations, changes in members’ equity and cash flows for period from May 11, 2012 (inception) through December 31, 2012. White Hawk Petroleum, LLC’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of White Hawk Petroleum, LLC as of December 31, 2012, and the results of its operations and its cash flows for the period from May 11, 2012 (inception) through December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.
/s/ GBH CPAs, PC
GBH CPAs, PC
www.gbhcpas.com
Houston, Texas
March 22, 2013
WHITE HAWK PETROLEUM, LLC
BALANCE SHEET
See accompanying notes to financial statements.
WHITE HAWK PETROLEUM, LLC
STATEMENT OF OPERATIONS
For the Period from May 11, 2012 (Inception) through
December 31, 2012
See accompanying notes to financial statements.
WHITE HAWK PETROLEUM, LLC
STATEMENT OF CHANGES IN MEMBERS’ EQUITY
For the Period from May 11, 2012 (Inception) through
December 31, 2012
See accompanying notes to financial statements.
WHITE HAWK PETROLEUM, LLC
STATEMENT OF CASH FLOWS
For the Period from May 11, 2012 (Inception) through
December 31, 2012
See accompanying notes to financial statements.
White Hawk Petroleum, LLC
NOTES TO FINANCIAL STATEMENTS
NOTE 1 - BASIS OF PRESENTATION
The accompanying financial statements of White Hawk Petroleum, LLC (“White Hawk” or the “Company”), have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules of the Securities and Exchange Commission (“SEC”).
NOTE 2 - DESCRIPTION OF BUSINESS
The Company was formed on May 11, 2012 as a Nevada limited liability company. Initial members’ equity was contributed by Pacific Energy Development Corp. (“PEDCO”) a wholly owned subsidiary of PEDEVCO Corp. (“PEDEVCO”) through the contribution of Excellong E&P-2, Inc. and all of its assets and liabilities on that date. On May 23, 2012, PEDCO sold 50% of its interest to MIE Jurassic Energy Corporation (“MIEJ”), an affiliate of MIE Holdings Corporation (Hong Kong Stock Exchange code: 1555.HK), one of the largest independent upstream onshore oil companies in China (“MIE Holdings”). At December 31, 2012, White Hawk is owned 50% by PEDCO and 50% by MIEJ. White Hawk is jointly managed by PEDCO and MIEJ.
The Company plans to focus initially on developing shale oil and gas assets held by the Company in the U.S., including its first oil and gas working interest known as “the Eagle Ford Asset”. Subsequently, the Company plans to seek additional shale oil and gas and conventional oil and gas asset acquisition opportunities in the U.S. utilizing its strategic relationships and technologies that may provide the Company a competitive advantage in accessing and exploring such assets.
NOTE 3 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates in Financial Statement Preparation. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as certain financial statement disclosures. While management believes that the estimates and assumptions used in the preparation of the financial statements are appropriate, actual results could differ from these estimates. Significant estimates generally include those with respect to the amount of recoverable oil and gas reserves, the fair value of financial instruments, oil and gas depletion, asset retirement obligations, and stock-based compensation.
Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. As of December 31, 2012, cash equivalents consisted of money market funds and cash on deposit.
Concentrations of Credit Risk. Financial instruments which potentially subject the Company to concentrations of credit risk include cash deposits placed with financial institutions. The Company maintains its cash in bank accounts which, at times, may exceed federally insured limits as guaranteed by the Federal Deposit Insurance Corporation (FDIC). At December 31, 2012, all of the Company’s cash balances were insured. The Company has not experienced any losses in such accounts.
Sales to two customers comprised 100% of the Company’s total oil and gas revenues for the period ending December 31, 2012. The Company believes that, in the event that its primary customer was unable or unwilling to continue to purchase the Company’s production, there are a substantial number of alternative buyers for its production at comparable prices.
Accounts Receivable. Accounts receivable typically consist of oil and gas receivables. The Company has classified these as short-term assets in the balance sheet because the Company expects repayment or recovery within the next 12 months. The Company evaluates these accounts receivable for collectability considering the results of operations of these related entities and when necessary records allowances for expected unrecoverable amounts. To date, no allowances have been recorded.
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 and natural gas. Revenue from crude oil and natural gas sales is recognized when the product is delivered to the purchaser and collectability is reasonably assured. The Company follows the “sales method” of accounting for oil and natural gas revenue, so it recognizes revenue on all natural gas or crude oil sold to purchasers, regardless of whether the sales are proportionate to its ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than its share of the expected remaining proved reserves. If collection is uncertain, revenue is recognized when cash is collected.
Deferred Property Acquisition Costs. The Company defers the costs, such as title and legal fees, related to oil and gas property acquisitions. At the time the acquisition is completed, these costs are reclassified and included as part of the purchase price of the property acquired. To the extent a property acquisition is not consummated these costs are expensed.
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.
Impairment of Long-Lived Assets. The Company reviews the carrying value of its long-lived assets annually or whenever events or changes in circumstances indicate that the historical cost-carrying value of an asset may no longer be appropriate. The Company assesses recoverability of the carrying value of the asset by estimating the future net undiscounted cash flows expected to result from the asset, including eventual disposition. If the future net undiscounted cash flows are less than the carrying value of the asset, an impairment loss is recorded equal to the difference between the asset’s carrying value and estimated fair value.
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, the Company will record a liability (an asset retirement obligation or “ARO”) on its balance sheet and capitalize the present value of the asset retirement cost in oil and 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 the 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 statements of operations.
Income Taxes. The Company is organized as a Limited Liability Company. A limited liability company is not a taxpaying entity. Any income or operating loss arising from the activities of the company is reported, after appropriate adjustments, on the personal income tax returns of the members. Adjustments to the income or loss allocated to a particular member will be required when the tax basis and accounting basis of net contributions made by an individual member are not equal. Because the company is not a taxpaying entity, its financial statements are different from those of taxpaying entities. Specifically, on the income statements there is no provision for federal income tax expense that must be paid because income was earned during the year. In addition, the balance sheets do not present a liability for income taxes incurred but not yet paid as of the balance sheet dates. Also, the balance sheets does not present any deferred tax assets or liabilities that might arise from different methods used to measure net income for the income statements and taxable income for the individual members.
Fair Value of Financial Instruments. The Company follows Financial Accounting Standards Board (“FASB”) ASC 820, Fair Value Measurement (“ASC 820”), which clarifies fair value as an exit price, establishes a hierarchal disclosure framework for measuring fair value, and requires extended disclosures about fair value measurements. The provisions of ASC 820 apply to all financial assets and liabilities measured at fair value.
As defined in ASC 820, fair value, clarified as an exit price, represents the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. As a result, fair value is a market-based approach that should be determined based on assumptions that market participants would use in pricing an asset or a liability.
As a basis for considering these assumptions, ASC 820 defines a three-tier value hierarchy that prioritizes the inputs used in the valuation methodologies in measuring fair value.
Level 1 - Quoted prices in active markets for identical assets or liabilities.
Level 2 - Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets or liabilities.
Level 3 - Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities.
The fair value hierarchy also requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.
Recently Issued Accounting Pronouncements. There were various accounting standards and interpretations issued during 2013 and 2012, none of which are expected to have a material impact on the Company’s financial position, operations or cash flows.
In July 2012 the FASB issued ASU 2012-02 Testing Indefinite-Lived Intangible Assets for Impairment, which amends Topic 350 and gives companies the option first to assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the indefinite-lived intangible asset is impaired. If, after assessing the totality of events and circumstances, an entity concludes that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. However, if an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test by comparing the fair value with the carrying amount in accordance with Topic 350-30. This ASU shall be applied prospectively for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012 and early adoption is permitted. Implementation of the ASU is not expected to have a significant impact on the Company’s financial statements.
Subsequent Events. The Company has evaluated all transactions through the date the financial statements were issued for subsequent event disclosure consideration.
NOTE 4 - BUSINESS ACQUISITION
On May 11, 2012, PEDCO merged Excellong E&P-2, Inc. (“E&P-2”) into White Hawk, then wholly-owned by PEDCO (the “E&P-2 Merger”). The separate corporate existence of E&P-2 ceased as a result of the E&P-2 Merger. White Hawk then held all of the Eagle Ford Assets of PEDCO. The transaction among entities under common control was recorded at historical cost.
E&P-2’s sole asset was an approximately 8% working interest in certain oil and gas leases covering approximately 1,651 net acres in the Leighton Field located in McMullen County, Texas, which is currently producing oil and natural gas from the Eagle Ford shale formation (the “Eagle Ford Asset”). White Hawk acquired no other assets or liabilities other than the working interests and tangible equipment associated with producing wells.
This area is currently producing oil and natural gas from three wells, with the remainder of the acreage under development.
The following table summarizes the allocation of the aggregate contribution as follows:
The estimated future net recoverable oil and gas reserves from proved resources, both developed and undeveloped which were acquired in this transaction are as follows (in thousands):
On May 23, 2012, PEDCO completed the sale of 50% of the members’ interests of White Hawk (the “White Hawk Sale”) to MIEJ. As a result of the White Hawk Sale, MIEJ and PEDCO each have an equal 50% ownership interest in White Hawk and each have agreed to proportionately share all expenses and revenues of White Hawk.
NOTE 5 - OIL AND GAS PROPERTIES
Activities related to oil and gas properties for the period from May 11, 2012 (Inception) through December 31, 2012 consisted of the following:
On May 11, 2012, the Company acquired E&P-2, Inc. from PEDCO as a contribution for member’s equity. E&P-2’s sole asset was an approximately 8% working interest in certain oil and gas leases covering approximately 1,651 net acres in the Leighton Field located in McMullen County, Texas, which is currently producing oil and natural gas from the Eagle Ford shale formation. This area is currently producing oil and natural gas from three wells, but the remainder of the acreage is under development.
During 2012, the Company acquired 0.68% in additional working interests in the Peeler 1H well for $0 as the Company’s pro rata share of working interests forfeited by a working interest owner that elected to not participate in the drilling and completion operations. The Company incurred $779,194 in drilling and completion costs related to the Peeler 1H well during the period from inception to December 31, 2012.
NOTE 6 - NOTES PAYABLE - RELATED PARTIES
During the year ended December 31, 2012, PEDEVCO loaned White Hawk funds to fund operating expenses and drilling and completion costs for a third Eagle Ford well, pursuant to a promissory note entered into on June 4, 2012, between PEDEVCO and White Hawk, which note permits multiple loans to be made thereunder and schedule therein as separate “advances” with no stated maximum limit of loan principal. The note receivable bears interest at a rate per annum equal to the one (1) month LIBOR rate for U.S. dollar deposits plus four (4.0) percentage points. Principal and interest of each loan is due thirty-six (36) months from the date of each advance under the note, with the first repayment being due June 4, 2015. As of December 31, 2012 the total notes payable and accrued interest are $332,974 and $459, respectively.
During the year ended December 31, 2012, MIEJ loaned White Hawk funds to fund operating expenses and drilling and completion costs for a third Eagle Ford well, pursuant to a promissory note entered into on June 4, 2012, between MIEJ and White Hawk, which note permits multiple loans to be made thereunder and schedule therein as separate “advances” with no stated maximum limit of loan principal. The note receivable bears interest at a rate per annum equal to the one (1) month LIBOR rate for U.S. dollar deposits plus four (4.0) percentage points. Principal and interest of each loan is due thirty-six (36) months from the date of each advance under the note, with the first repayment being due June 4, 2015. As of December 31, 2012, the total notes payable and accrued interest are $332,974 and $459, respectively.
NOTE 7 - RELATED PARTY TRANSACTIONS
As discussed in Note 4, in May 2012, PEDCO merged its wholly-owned subsidiary, E&P-2, Inc., into White Hawk and then sold 50% of its ownership interests in White Hawk to MIEJ.
NOTE 8 - INCOME TAXES
The Company is organized as a Limited Liability Company and all taxable income is taxed directly to the members thus there is no provision for income taxes. The Company’s basis in its assets for financial reporting purposes is lower than that of its tax basis by approximately $ 200,000 (unaudited).
NOTE 9 - COMMITMENTS AND CONTINGENCIES
The Company is not aware of any pending or threatened legal proceedings. The foregoing is also true with respect to each officer, director and control shareholder as well as any entity owned by any officer, director and control shareholder, over the last five years.
As part of its regular operations, the Company may become party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning its’ commercial operations, products, employees and other matters. Although the Company can give no assurance about the outcome of these or any other pending legal and administrative proceedings and the effect such outcomes may have on the Company, except as described above, the Company believes that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on the Company’s financial condition or results of operations.
NOTE 10 - ASSET RETIREMENT OBLIGATIONS
The Company records the fair value of a liability for asset retirement obligations (“ARO”) in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The present value of the estimated asset retirement costs is capitalized as part of the long-lived asset and is depreciated over the useful life of the asset. The Company accrues an abandonment liability associated with its oil and gas wells when those assets are placed in service or acquired. The ARO is recorded at its estimated fair value and accretion is recognized over time as the discounted liability is accreted to its expected settlement value. Fair value is determined by using the expected future cash outflows discounted at the Company’s credit -adjusted cost of capital risk-free rate. No market premium has been included in the Company’s calculation of the ARO balance.
The following is a description of the changes to the Company’s ARO for the period from inception through December 31, 2012.
NOTE 11 - MEMBERS’ EQUITY AND ALLOCATION OF INCOME
Initial members’ equity was contributed by PEDCO through the contribution of E&P-2 and all of its assets and liabilities on that date. The transaction was recorded as a transaction between entities under common control. Accordingly, the assets and liabilities of E&P-2 were recorded at the net carrying value of PEDCO.
On May 23, 2012, PEDCO sold 50% of its interest to MIEJ. At December 31, 2012, White Hawk is owned 50% by PEDCO and 50% by MIEJ.
In accordance with the provisions of the operating agreement of the Company, net capital appreciation or depreciation of the Company is allocated to all members in proportion to each member’s ownership interest for each accounting period, as defined in the operating agreement.